HP_2010_10

OCTOBER 2010

HPIMPACT

SPECIALREPORT

TECHNOLOGY

Valves market growing

PROCESS CONTROL AND INFORMATION SYSTEMS

Stop fouling of hydrocracker units

Industrial gas demand expanding

APC builds more reliability plant-wide

Update on carrier gases for petrochemicals

www.HydrocarbonProcessing.com

Risk has always been part of this job.

A part we can do without.

High pressure. Extreme temperatures. Volatile products. It’s all part of the job in hydrocarbon processing. But so is the goal of maximizing safety integrity. We make the process more secure with our innovative valves and controls, which is why the industry relies on us to keep their workers safe and their plants running smoothly.

Engineering transformation.™

Learn more about our plant performance solutions at CWFC.com

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OCTOBER 2010 • VOL. 89 NO. 10 www.HydrocarbonProcessing.com

SPECIAL REPORT: PROCESS CONTROL AND INFORMATION SYSTEMS How to have a successful data reconciliation software implementation

29

Follow these guidelines to ensure success H. Won, W-S. Cho, T. Ayral and I. Samad

35

Improve exploration, production and refining with ‘add-at-will’ wireless automation After the technology was validated, a wireless infrastructure was installed blanketing 80% of a US refinery G. LaFramboise and B. Karschnia

39 41 49

17 Global industrial valves market growing

Here are six practical guidelines to consider B. Shuman

17 Industrial gas demand expanding

Increase your margin by 25%

17 IEC calls for a global taskforce

Here’s how to make sure that the planning LPs always match the plant A. Beerbaum, W. Korchinski and D. Geddes

Advanced process control in the plant engineering and construction phases

PROCESS DEVELOPMENTS Mitigate fouling in ebullated-bed hydrocrackers New monitoring tools help track and control asphaltene levels and solubility issues in resid products J. Kunnas, O. Ovaskainen and M. Respini

PETROCHEMICAL DEVELOPMENTS Troubleshoot silicon contamination on catalysts

65

What are the sources, impacts and possible solutions to controlling this problem in your hydrotreater?

J. M. Britto, M. V. Reboucas and I. Bessa

PUMPS/RELIABILITY Cost optimization in mechanical seal applications

70

Real-life case studies prove it is possible to make more informed choices that often lead to cost savings D. K. Shukla, D. K. Chaware and R. B. Swamy

GAS PROCESSING DEVELOPMENTS New correlation for calculating natural gas Z-factor

76

HPIMPACT

Building and installing a reliable industrial Ethernet infrastructure

Testing MVC performance using a dynamic model offers several benefits V. Sakizlis, K. Vakamudi, A. Coward and I. Mermans

59

Cover The image, from the article

by Chevron and Emerson, illustrates blanketing of facilities with wireless networks to enable add-at-will automation, see pp. 35.

Use these calculations for low absolute average error A. A. Moghadam and C. Ghotbi

LAB ANALYZERS Consider using alternative carrier gases for petrochemical analysis

79

19 The new biofuel: it’s whisky in a car 19 Studying the future of transportation fuels

COLUMNS 9 HPIN RELIABILITY Better equipment selection starts with understanding available upgrade options 11 HPIN EUROPE How German refiners sped up clean fuels rules to save their heating oil business 13 HPIN ASSOCIATIONS Rice’s E&C Forum a well-rounded affair 15 HPIN CONTROL Process control practice renewal 2010—performance 86 HPIN WATER MANAGEMENT Utility water boot camp for process engineers—Part 2

Advantages include higher efficiency and shorter analysis times J. Duan and T. Jacksier

DEPARTMENTS 7 HPIN BRIEF • 21 HPINNOVATIONS • 25 HPIN CONSTRUCTION 27 HPI CONSTRUCTION BOXSCORE UPDATE 82 HPI MARKETPLACE • 85 ADVERTISER INDEX

2010 European Turnaround and Maintenance Services Directory Following page 88

A boost in accurate positioning

Trial-and-error tuning during start-up is a thing of the past.

Thanks to its precisely manufactured bypass restriction, the rugged Type 3755 Booster by SAMSON can be set exactly for its task and lead-sealed. As the booster is completely balanced, it works reliably and remains unaffected by changing pressure conditions. It supplies one-to-one signal pressure with a defined hysteresis. And the booster does all this very quietly.

Combined with a positioner, the booster has even more to offer: Both devices ensure a fast and accurate positioning of the valve, even when handling high flow rates or pressure drops.

SAMSON Type 3755 – boosting performance

www.HydrocarbonProcessing.com Houston Office: 2 Greenway Plaza, Suite 1020, Houston, Texas, 77046 USA Mailing Address: P. O. Box 2608, Houston, Texas 77252-2608, USA Phone: +1 (713) 529-4301, Fax: +1 (713) 520-4433 E-mail: editorial@HydrocarbonProcessing.com www.HydrocarbonProcessing.com Publisher Bill Wageneck bill.wageneck@gulfpub.com EDITORIAL Executive Editor Stephany Romanow Process Editor Tricia Crossey Reliability/Equipment Editor Heinz P. Bloch News Editor Billy Thinnes European Editor Tim Lloyd Wright Contributing Editor Loraine A. Huchler Contributing Editor William M. Goble Contributing Editor Y. Zak Friedman Contributing Editor ARC Advisory Group (various) MAGAZINE PRODUCTION Director—Editorial Production Sheryl Stone Manager—Editorial Production Angela Bathe Artist/Illustrator David Weeks Manager—Advertising Production Cheryl Willis ADVERTISING SALES See Sales Offices page 84.

CIRCULATION +1 (713) 520-4440 Director—Circulation Suzanne McGehee E-mail: circulation@gulfpub.com SUBSCRIPTIONS

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Outside USA and Canada, one year $239, two years $407, three years $530, digital format one year $140. Airmail rate outside North America $175 additional a year. Single copies $25, prepaid.

Because Hydrocarbon Processing is edited specifically to be of greatest value to people working in this specialized business, subscriptions are restricted to those engaged in the hydrocarbon processing industry, or service and supply company personnel connected thereto.

Hydrocarbon Processing is indexed by Applied Science & Technology Index, by Chemical Abstracts and by Engineering Index Inc. Microfilm copies available through University Microfilms, International, Ann Arbor, Mich. The full text of Hydrocarbon Processing is also available in electronic versions of the Business Periodicals Index.

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HYDROCARBON PROCESSING (ISSN 0018-8190) is published monthly by Gulf Publishing Co., 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. Box 2608, Houston, Texas 77252.

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Germany · SAMSON AG · MESS- UND REGELTECHNIK Weismüllerstraße 360314 · Frankfurt am Main Phone: +49 69 4009-0 · Fax: +49 69 4009-1507 E-mail: samson@samson.de Internet: www.samson.de U.S.A. · SAMSON CONTROLS INC. 4111 Cedar Boulevard · Baytown, Texas 77523-8588 Phone: +1 281 383-3677 · Fax: +1 281 383-3690 E-mail: samson@samson-usa.com Internet:4 www.samson-usa.com

John Royall, President/CEO Ron Higgins, Vice President Pamela Harvey, Business Finance Manager Part of Euromoney Institutional Investor PLC. Other energy group titles include: World Oil® Petroleum Economist Publication Agreement Number 40034765

Printed in U.S.A 䉳 Select 151 at www.HydrocarbonProcessing.com/RS

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© 2010 Thermo Fisher Scientific Inc. All rights reserved. Copyrights in and to the Matches and Blowtorch photographs are owned by a third party and licensed for limited use only to Thermo Fisher Scientific by maxx images and SuperStock.

Imagine one gas analyzer that does the work of ten.

Introducing Thermo Scientific Prima PRO, the online gas analyzer that uses high-speed mass spectrometry to increase yield, conserve energy, and enhance process safety.

In fact, a single Prima PRO can do the work of ten gas chromatographs to dramatically lower your cost of ownership and raise the bar on product quality.

This powerful yet easy-to-use, simple-to-maintain system offers automatic tuning and calibration and produces higher resolution for a number of process variables. So you have a better understanding of process dynamics and can implement more effective operating procedures. Plus, Prima PRO is built to deliver 99.9% uptime—making it a safe, reliable choice.

Thermo Scientific Prima PRO— Named 2010 Innovative Product of the Year by the International Society of Automation (ISA) Analysis Division for superior performance and ease-of-maintenance.

To learn more, visit www.thermoscientific.com/primapro, email us at sales.process.us@thermofisher.com or call 1 (800) 437–7979 or 1 (713) 272–0404.

Moving science forward Select 97 at www.HydrocarbonProcessing.com/RS

HPIN BRIEF BILLY THINNES, NEWS EDITOR

BT@HydrocarbonProcessing.com

ExxonMobil Research and Engineering Co. (EMRE) has signed an agreement with Badger Licensing LLC to jointly market EMRE’s BenzOUT technology, a catalytic process to reduce benzene in gasoline while delivering other additional benefits. The technology converts benzene into high-octane alkylaromatics by reacting benzene-rich streams with light olefins, such as ethylene or propylene. Developed by EMRE and licensed through Badger, this patented technology avoids the octane loss and hydrogen consumption associated with benzene saturation alternatives. This commercially demonstrated refinery process is an extension of Badger’s cumene and ethylbenzene processes, which are widely applied in the chemical industry. The multi-year agreement covers the marketing and commercialization of the technology to customers in the refining industry.

Honeywell UOP LLC’s technology was recently selected for use in Rentech, Inc.’s Rialto Renewable Energy Center for the conversion of biomass to transportation fuels. The renewable energy center, to be built in Rialto, California, will convert biomass, such as yard and tree trimmings, into renewable, ultra-clean diesel fuel and renewable electricity. The new facility will use UOP hydroprocessing technology, which converts hydrocarbons into clean-fuel products. The center is expected to produce roughly 640 bpd of liquid fuel and 35 megawatts of base-load electricity, enough to power approximately 30,000 homes each day.

BP has agreed to sell its interests in ethylene and polyethylene production in Malaysia to Petronas. The agreement concerns BP’s 15% interest in Ethylene Malaysia Sdn Bhd (EMSB) and 60% interest in Polyethylene Malaysia Sdn Bhd (PEMSB), both of which are operated by Petronas, and are located in Kertih, on the east coast of Malaysia. This announcement does not affect BP’s other businesses in Malaysia. Under the terms of the agreement, Petronas will, at closing, pay $363 million in cash to BP, inclusive of a balance sheet adjustment of $13 million and the repayment of a shareholder loan of $53 million. Subject to certain conditions, both parties anticipate completing the transaction by the end of 2010. Additionally, BP will also receive an EMSB pre-closing dividend payment amounting to $48 million, subject to EMSB board approval.

The world’s first plant for production of the renewable motor fuel BioDME was recently inaugurated in Sweden. The plant was built and is operated by Chemrec, a Swedish-based technology company, at the company’s development plant located at the Smurfit Kappa paper mill in Piteå, Sweden. In Sweden, up to one half of all heavy road transportation could be run on BioDME, and globally well over 30 million m3 diesel equivalents per year could be produced from the available black liquor feedstock, enough to fuel one million heavy trucks. BioDME from forest residues over the Chemrec process reduces net greenhouse gas emissions with about 95% compared to use of petroleum-based diesel oil, the traditional fuel for heavy road transports.

This pilot plant is part of the BioDME project where the production of BioDME and its use in heavy trucks is demonstrated. The syngas generation for the plant is based on Chemrec’s black liquor gasification technology. The BioDME synthesis and upgrading technology is provided by Haldor Topsøe A/S.

Dresser Masoneilan has launched a diagnostic tool for control valves with both conventional and digital positioners. Called the ValScope-PRO, it helps customers identify problems by providing a scientific evaluation of valves in operation.

The tool is portable, enabling users to troubleshoot valves in-line and in harsh environments to determine which valves need to be removed. A graphic interface allows users to view the valve as it is being tested, and provides real-time analysis. The diagnostic tool is compatible with analog, Fieldbus and HART communication protocols. HP

■ OU’s Biocorrosion Center The University of Oklahoma (OU) has joined forces with ConocoPhillips to create a new Biocorrosion Center within the OU Institute for Energy and Environment. The center will give OU researchers an opportunity to work closely with ConocoPhillips to develop new technologies to manage biocorrosion in US pipelines, storage facilities, separators, tankers and refineries.

ConocoPhillips will provide startup funding for the Center, but other major oil companies and entities will be invited to participate in the financial support of these efforts. Center researchers will explore the fundamental scientific issues that lead to new knowledge, understanding and technology for the diagnosis, mitigation and prevention of biocorrosion problems and fuel biodeterioration.

Joseph Suflita, center director, said that he is pleased to collaborate with ConocoPhillips to bring the talents of OU to bear on the relatively poorly understood but critically important issue of biocorrosion in the oil and gas sector.

“We must explore ways to maintain the integrity of equipment and prevent environmental releases in the first place,” said Mr. Suflita.

Gary Jenneman, corrosion management supervisor at ConocoPhillips, said that the collaboration with OU is unique. “While there are many corrosion centers around the world, there are few that specifically focus on the role of microorganisms in corrosion processes and none that have as much expertise in the study of anaerobic microorganisms.”

The energy industry is faced with increasing environmental pressures.

Newer fuel blends tend to be more susceptible to microbial decay compromising performance in a number of ways, including the biodeterioration of fuel quality and biocorrosion in downstream facilities. Anaerobic microorganisms often catalyze biocorrosion processes but are poorly understood and difficult to control. OU is uniquely positioned to address these problems with a greater concentration of anaerobic microbiologists than anywhere in the Western Hemisphere. HP HYDROCARBON PROCESSING OCTOBER 2010

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safety made simple

Sensepoint XCD Universal Gas Detector/ Transmitter — now with Modbus The Sensepoint XCD range provides comprehensive monitoring of flammable, toxic and Oxygen gas hazards in potentially explosive atmospheres, both indoors and outdoors. Users can modify detector operation using the LCD and magnet switches without ever needing to open the unit. This enables one-man, non-intrusive operation and reduces routine maintenance time and costs.

Make your chemical plant run more safely, efficiently and profitably. Easy to install, use and maintain.

• Toxic and flammable gas detection • Accepts IR, cat bead, EC sensors • Simplifies wiring

• Local display • Built-in alarm relays • Globally certified

Honeywell Analytics. Experts in gas detection.

To learn more, call 1-800-538-0363, or visit www.XCDbyHoneywell.com © 2010 Honeywell International Inc. All rights reserved.

Select 79 at www.HydrocarbonProcessing.com/RS

HPIN RELIABILITY HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR HB@HydrocarbonProcessing.com

Better equipment selection starts with understanding available upgrade options It all started with a letter we received from a major multinational petrochemical company: A reliability manager related that he had recently asked each maintenance department within the corporation’s businesses to submit the top 10 production-loss sources over the past few years. When his staff analyzed the various replies, it was discovered that most of the corporation’s problems related to equipment that had been recently commissioned as part of major projects.

Having discovered this common thread, the reliability staff asked the maintenance departments how much influence they had in equipment design and selection during the early stages of the project.

Due to resource limitations, it seems these maintenance departments had not been heavily involved. The letter asked how others manage this matter during earlier stages of major projects. “Are maintenance/reliability experts included in the project teams or is there any oversight from operations/maintenance on design quality and equipment selection?” he asked.

Limit bidders lists and specify details. We answered that

best-of-class performers manage to avoid the issue mentioned by the reliability manager by limiting their bidders’ lists to a few good and consistent performers. Then they add a corporate specification to their invitation to bid and make it clear to the bidder that the specification clauses must be met, and that it is expressly understood that the equipment will cost more than their standard offering.

In essence, the pump drive-end of Fig. 1 does not measure up to the expectations of reliability-focused owner-operators. The issue is relevant and may even negatively affect US pump manufacturers unless they pay very close attention.

1. Oil rings are rarely found acceptable by best-of-class plants.

These rings skip around and will abrade unless the shaft system is truly horizontal; ring immersion in the lubricant is as required; and ring eccentricity, surface finish and oil viscosity are all within limits. Taken together, these parameters are rarely found within safe limits in real-world situations. Therefore, a stainless steel flinger disc fastened to the shaft should be supplied. The disc contacts the oil and flings it into the bearing housing. The disc O.D. must exceed the thrust bearing’s outside diameter.

2. To allow the steel flinger disc to pass through the housing bore upon assembly, the back-to-back-oriented thrust-bearing set must be placed in a suitably sized cartridge.

3. Fig. 1 does not show bearing housing protector seals. An advanced version of such a protector seal must be supplied for both the inboard and outboard bearings. Lip seals are not good enough, and neither are old-style rotating labyrinth seals with “dynamic” O-rings in close proximity to sharp-edged geometries.

4. As a matter of routine, the housing or cartridge bore must have a passage at the 6 o’clock position to allow pressure equalization and oil movement from one side to the other side of the bearing. Note that such a passage is shown in Fig. 1 for the radial bearing, but needs to be added to the thrust-bearing set also.

5. Once items 1 through 4 have been implemented, the breathers (or vents) are no longer needed. They should be removed and one of them should be plugged.

6. A pressure-balanced constant-level lubricator should be supplied and its generously sized balance line should be connected to the second of the two breather ports.1 Reliability professionals must do better. Of course,

even the failure-prone configuration depicted in Fig. 1 will generally work “reasonably well,” but that characterization is no longer acceptable. Reliability professionals and pump manufacturers must do better and should know how to do better. Yes, we realize that pump manufacturers are able to submit test-stand data certifying that things work even if the aforementioned upgrade issues are disregarded. Then again, realistic engineers can prove how and why things tend to malfunction in the real world. If such malfunctioning occurs 10% of the time, considerable repair expenditures will result and the maintenance budget will be stressed.

Perhaps we might all agree on one premise: As we get further away from solid training and from taking the time needed to do things right, we become ever more vulnerable. One way to counteract this vulnerability is by designing-out maintenance. Users have to demand designs that accomplish this goal and must be willing to pay for these upgrades. HP 1

LITERATURE CITED Bloch, H. P. and A. Budris, Pump User’s Handbook—Life Extension, 2nd Ed. (2006), Fairmont Press, Lilburn, GA 30047; ISBN 088173-517-5.

The author is Hydrocarbon Processing’s Equipment/Reliability Editor. He holds BSME and MSME degrees from the New Jersey Institute of Technology and is a professional engineer with close to 50 years of industrial experience, including a long technical career with the Exxon Corp. The author of 17 textbooks on machinery reliability improvement and over 470 technical papers continues to advise process plants worldwide on reliability improvement and maintenance issues.

Breathers

Oil rings

FIG. 1

A typical bearing housing with a few elusive vulnerabilities.

HYDROCARBON PROCESSING OCTOBER 2010

I9

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HPIN EUROPE TIM LLOYD WRIGHT, EUROPEAN EDITOR tim.wright@gulfpub.com

How German refiners sped up clean fuels rules to save their heating oil business European refiners are nearing the end of a decade of rapid change—some might say a revolution—in fuel specifications. For road fuels, at least, sulfur levels have gone from being a political football in a long, goal-less match, to being simply a thing of the past. In heating oil, and especially in marine fuels, things have been slower. But rather than make a reactionary stand against progress, refiners here decided to borrow lessons from the red/green European Union (EU) politics of the late 1990s to speed things up.

A revolution in thinking. The industry itself has used methods, which were a game-changer when applied to the European Fuels Directive to effect a revolution of their own in German heating oil quality. (As I write, US distillate inventories are heading for the tank top; it may be useful to know that the powerful niche market has resulted and is today well-suited to receiving unwanted ultra-low-sulfur diesel cargoes.

Faced with a 30-year decline in market share for home heating oil, German refiners proposed slashing sulfur levels 40-fold, and even the imposition of punitive taxes, to whip any laggards in their industry into shape.

And heating oil’s no niche. Obviously, heating oil is a big business, with its own futures contract on the Intercontinental Exchange (ICE) and a trading hub between the large Dutch and Belgian oil ports. But nowhere is it more important than in the affluent hinterlands of Europe’s greatest inland navigable waterway: the Rhine.

Since the 1980s, the gradual growth of the gas pipeline network has given householders an alternative to heating oil—natural gas. It made economic sense to switch, and in the age of acid rain (the 1980s), a sulfur-free gas already had an environmental edge over diesel oil. Then carbon content, fuel efficiency and carbon dioxide (CO2) emissions all became issues, as German consumers and businesses turned their attention acutely to climate change.

At this point, German refiners might well have thrown their hands in the air. Our market is in decline, they might have argued; our heating oil profitability too frail to suffer legislative blows.

What now?

Changing the game. Instead, members of the German Heat-

ing Oil Institute began looking at how the gasoil specification could be optimized for efficient combustion. Instead of playing down the growing role of renewable energy, they thought about the opportunities which household-based and large-scale renewables may present to refiners.

Too much energy loss. The howling inefficiency of old oil boilers was flue-gas temperatures. With oil prices rising fast, consumers were sending 200°C flue gas through the roof. “The boilers were inefficient, but capturing the waste heat would mean condensation in the flue, and high sulfur levels would mean acids forming,”

remembers Dr. Christian Kuechen, who is the general manager of the Institute for Economic Oil Heating Germany (IWO) in Hamburg, and president of Eurofuel, the European Heating Oil Association. “We carried out extensive research in 2001 and 2002, and we realized that with a sulfur content of less than 50 ppm, we would be able to use more cost-effective materials in heat exchangers.”

The new quality would make possible the introduction of low-temperature, condensing boilers, and, critically, it gave the oil-fueled sector an environmental argument. “Every second installation based on heating oil in Germany today combines solar thermal panels with a backup boiler,” says Dr. Kuechen. “As long as you have daytime sun, you don’t need the boiler,” he says, “but you can bring in backup power quickly and easily.”

He notes that, in this way, oil is playing a better role in a country, which has embraced wind power. “You need some energy storage in a system like this, and the home and business oil tanks offer that,” he points out.

Legislative changes. On Jan. 15, 2007, a memorandum of understanding was signed by the German Federal Government and the country’s oil industry. The agreement paved the way for Germany to move ahead on heating oil quality. EU directives would, in any case, reduce heating oil sulfur from 2,000 ppm to 1,000 ppm in 2008. But the Germans wanted to go further.

During 2007, plans for a tax disincentive were made public, and the new condensing boilers quickly captured a large part of the new oil-heating installation market. On Jan. 1, 2009, 1.5 eurocents/l ($23/metric ton—6¢/US gallon) was added to the price of 1,000 ppm-S heating oil.

For its part, the oil industry association provided education to consumers; the importers’ association provided supply; and the German Association of Fuel and Petroleum Dealers agreed it would make the new grade available within 35 km (21 miles) of consumers living in cities and towns. The government’s side of the deal, aside for the punitive taxation of 0.1% gasoil, was a Euros 600 tax break for homeowners installing new furnaces.

“We needed some pressure and that was the role of the tax incentive,” says Dr. Kuechen. “The industry really wanted a better quality, and the tax helped to kill off demand for the old quality.”

In January 2008, ultra-low-sulfur heating oil represented less than 0.25% of German heating oil sales. By February 2010, it had 45% of the market and is about to replace further standard heating oil, as more desulfurization facilities are put into operation at refineries. HP The author is HP’s European Editor. He has been active as a reporter and conference chair in the European downstream industry since 1997, before which he was a feature writer and reporter for the UK broadsheet press and BBC radio. Mr. Wright lives in Sweden and is the founder of a local climate and sustainability initiative.

HYDROCARBON PROCESSING OCTOBER 2010

I 11

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HPIN ASSOCIATIONS BILLY THINNES, NEWS EDITOR

BT@HydrocarbonProcessing.com

Rice’s E&C Forum a well-rounded affair Rice University hosted its 13th annual Global Forum for Engineering and Construction last month. The theme of the gathering at Rice’s campus in Houston was “new pathways towards prosperity.” Key speakers included Bill Utt, CEO of KBR; Dr. Michael Economides, professor at the University of Houston; and Jim Scotti, senior vice president at Fluor Corp.

Mr. Utt was the forum’s morning keynote speaker, and he shared many tales describing his experiences leading KBR and the various issues he has encountered as an international engineering and construction contractor. Dr. Economides’ remarks were focused exlusively on natural gas. He explained how, less than two years ago, oil prices climbed to almost $150 per barrel and then completely and unexpectedly dropped to around $40.

He then detailed the further volatility of the natural gas market and the reasons behind it, including considerable demand destruction in Russia, large new capacity of LNG in Qatar and the inertia of the success in shale formation activities in the United States.

According to Dr. Economides, these price gyrations affect all aspects of the natural gas world including the import of LNG, the desirability of arctic pipelines, conventional and, especially unconven-

Bill Utt, CEO of KBR, was the keynote speaker at Rice’s E&C Forum.

tional production. One obvious bright spot for the future of natural gas, he said, is that energy consumption in the generation of wealth and the forms of primary energy sources have not been constant throughout the last two centuries. Of considerable significance is the change of fuels from wood to coal to oil and now to natural gas. Eventually, hydrogen will play a role.

He rounded out his remarks by saying that natural gas, at prices significantly below BTU parity with oil for a long time to come, will certainly play a pivotal role in world energy supply and will move toward becoming the premier fuel of the world economy.

Mr. Scotti’s remarks closed out the forum. He explained that, as companies emerge from the downturn, innovative capital project supply chain models will be vital to both contractors and owners.

His presentation included a look at the current materials market and the unique elements associated with the capital project supply chain process. He also discussed the state of the procurement profession and what Fluor is doing to demonstrate its commitment to improving supply chain education opportunities for the industry’s future procurement leaders.

Environmentally acceptable lubricants ASTM International is sponsoring a symposium on testing and use of environmentally acceptable lubricants. Sponsored

by ASTM Committee D02 on Petroleum Products and Lubricants, the symposium will be held on December 6, 2010, at the Hyatt Regency Jacksonville Riverfront in Jacksonville, Florida, in conjunction with the December 5–9 standards development meetings of the committee.

The general objective of the symposium is to hold a technical forum for discussions related to current trends for testing and use of environmentally acceptable lubricants. It also provides details on current research efforts to advance use of bio-based and other envi-

ronmentally acceptable lubricants, and to develop new and improved environment test methods.

Folks who should attend include those involved in bio-based lubricant testing; people concerned about environmentally responsible lubricants; university researchers; government agencies; lubricant formulators; and bio-based lubricant users.

For more information, visit www.astm. org/D02symp1210_1.htm.

Turbomachinery Symposium comes to Houston The Texas A&M Turbomachinery Laboratory is hosting its 39th annual Turbomachinery Symposium October 4–7, 2010, at the George R. Brown Convention Center in Houston, Texas.

The symposium promotes professional development, technology transfer, peer networking and information exchange among industry professionals. The event is being led by engineers with vast experience in the petrochemical, process, chemical, utility, contractor and consulting fields, along with manufacturers of rotating equipment and fluid-handling equipment from around the world.

The Turbomachinery Symposium will feature lectures, tutorials, case studies, discussion groups and short courses, as well as exhibits of the latest services and fullsized equipment available. These international meetings emphasize the technology and troubleshooting that users need in today’s challenging workplace.

The Turbomachinery Symposium continues to be the only gathering organized by users for users. The members of the Advisory Committee, which provides overall guidance, are recognized leaders in the rotating equipment and power generation community. The technical sessions provide an opportunity for attendees to select those lectures, tutorials, discussion groups and case studies that best meet their personal and professional needs and interests.

The exhibits feature products from many key companies in the industry. HP HYDROCARBON PROCESSING OCTOBER 2010

I 13

© 2009 Swagelok Company

In addition to tube fittings, we also make valves, regulators, filters, and happier customers.

Contrary to what you may think, we’re much more than a tube fitting company.

And we have our obsession with Customer Focus to thank for that. Yes, we’re known throughout the world for our tube fittings. And yes, we’ve been at it for over 60 years. But when companies are looking harder than ever for greater value, it’s our broad range of products, including orbital welders, modular systems, and a complete line of hose, that helps us offer more than you expect. See for yourself at swagelok.com/moreproducts.

Select 63 at www.HydrocarbonProcessing.com/RS

HPIN CONTROL PIERRE R. LATOUR, GUEST COLUMNIST clifftent@hotmail.com

Process control practice renewal 2010—performance In August 2010, I followed Allan Kern’s “Continuous Improvement or Core-Competency editorial”1 with a review of the purposes of process control and IT in the HPI. After 50 years, it is now time to standardize the method for determining the financial performance of instrumentation, control systems, IT and CIM, so we can justify them properly, set setpoints correctly, critique weaknesses, offer ways to strengthen the HPI operations and process control practices, and make more money.

No one should play a game until they understand how to keep score. Proper performance measures are central to any renewal of process control. If the purpose of HPI plants is to make products that create profit, then the purpose of all plant components, including process control and IT, is the same as all the other plant equipment and components.

In April and August 2010 editorials, I blamed the flawed logic used to quantify the financial value of all process control and IT since 1970 as a basic cause of the crippling disconnects between the layers, components and technologies. The flawed performance logic of process control since its inception is this: reduced CV variance is good but of no intrinsic value because the credits and debits cancel each other. It is just a necessary prerequisite for moving the CV mean in the profitable direction toward a limit, specification (spec) or constraint by some arbitrary amount, which produces steady-state benefits of one kind. This flaw was identified and corrected in 1996.2, 4 Missing method. The discovery that every CV/KPI has a risky expected-value profit tradeoff to be optimized provides the process industries with the mathematically rigorous method for setting operating conditions.2 They can be optimized independently; benefits are additive and application is greatly simplified.2–6 These tent-shaped profit tradeoffs often have penalty cliffs near specs and limits. Steep cliffs and chasms abound in refinery operations. Their location and magnitude should be identified and considered when setting setpoints. The clifftent profit tradeoff function for each CV/KPI must be determined before setpoints can be aligned properly with economics.5, 6 Once this knowhow is understood and adopted, the thinking is clear; the needed information is tied to a standard decision method and actions to make money, and, lo and behold, the financial value of dynamic process control to reduce CV variance is quantified.2–6 This is the knowhow needed for process control and IT renewal.

The reason IT and instrumentation cannot prove their financial merits is because the value of information depends on what is done with it; if nothing is done, it is just worthless data. Useful information is a universal component of operating decisions and actions to set CV/KPI setpoints and control tightly about them. Which is why adopting a standard best practice for setting setpoints provides the means for assuring that what is to be

done with instruments, computers and IT is worthwhile2, 4–6 It also defines the way they manifest themselves in improved plant performance. This is crucial for specifying and justifying instrumentation, control and IT requirements.

Benefit. The HPI can reap substantial, visible money by gather-

ing and using its appropriate business knowhow information to adjust setpoints to operate at their best. Operating conditions are aligned with economics.5, 6 The premium on modeling the consequences for exceeding specs, breaking limits, noncompliance and unsafe situations is clear and integrated with corresponding CVs. The thinking process is strengthened; the culture is changed.

The premium on forecasting near-term variance for profit risk management determines information and learning requirements, which BP has apparently lacked at its Texas City, Texas Refinery since 2005.

Watching Thad Allen’s C-SPAN reports on the Deepwater Horizon spill clean-up with clifftent knowhow, you see Allen describe risky value trade-offs with lots of cliffs everywhere, from drill hole pressure tolerances to wave heights for the BOP lift.

Adopting the rigorous method that optimizes risky tradeoffs for setpoints provides the way to evaluate the value of instruments, components, layers, models, IT and solutions.2 This is the proper path to renewal and success. In the end, Kern1 and Latour2–6 will unite to provide guidelines for renewing the process control engineering practice during refinery golden ages and downturns.

Next time, I will cover the consequences of violating limits to fulfill the purpose of process control. HP LITERATURE CITED Kern, A., “Continuous improvement or core-competency,” Hydrocarbon Processing, July 2010.

2 Latour, P. R., “Process control: CLIFFTENT shows it’s more profitable than expected,” Hydrocarbon Processing, December 1996, pp. 75–80. Republished in Kane, L., Ed., “Advanced Process Control and Information Systems for the Process Industries,” Gulf Publishing Co. 1999, pp. 31–37.

3 Latour, P. R., “Does the HPI do its CIM business right?” HPIn Control, Guest Columnist, Hydrocarbon Processing, V76, n7, July 1997, pp. 15–16 and “Optimize the $19-billion CIMfuels profit split,” V77, No. 6, June 1998, pp. 17–18.

4 Latour, P. R., “Demise and keys to the rise of process control,” Hydrocarbon Processing, March 2006, pp. 71–80, and Letters to Editor, Process Control, Hydrocarbon Processing, June 2006, p. 42.

5 Latour, P. R., “Set vapor velocity setpoints properly,” Hydrocarbon Processing, Vol. 85, No. 10, October 2006, pp. 51–56.

6 Latour, P. R., “Align HPI operations to economics—CLIFFTENT optimizes risky tradeoffs at limits,” Hydrocarbon Processing, Vol. 87, No. 12, December 2008, pp. 103–111.

The author is a principal consultant in advanced process control and online 1

optimization with Petrocontrol. He specializes in the use of first-principles models for inferential process control and has developed a number of distillation and reactor models.

Dr. Friedman’s experience spansInc., overis30 in the hydrocarbon industry, The author , president of CLIFFTENT anyears independent consulting chemical working with Exxon Research and Engineering, KBC sustaining Advanced Technology since engineer specializing in identifying, capturing and measurableand financial 1992 with holds acontrol, BS degree fromCIM the Israel Institute of Technology value fromPetrocontrol.

HPI dynamicHe process IT and solutions (CLIFFTENT) using (Technion) and a PhDshared degreerisk–shared from Purdue University. performance-based reward (SR2) technology licensing.

HYDROCARBON PROCESSING OCTOBER 2010

I 15

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H58646

09/10

HPIMPACT BILLY THINNES, NEWS EDITOR

BT@HydrocarbonProcessing.com

Global industrial valves market growing The world market for industrial valves will grow from $44 billion this year to $52 billion in 2015. This is according to a recent forecast by the McIlvaine Co. The biggest growth will be in power and wastewater in East Asia. The West Asian market will grow by 50% during this period. The market in Western Europe will only grow by 6% during the period.

Control valves are the leading product segment. There is increasing demand for “smart valves” that can communicate conditional and operational information remotely. The nuclear industry has again become a growth market for valve suppliers.

The newest reactor designs use fewer valves than existing ones. However, the life extension programs at existing nuclear plants provide a substantial revenue stream.

Some markets are growing while others are shrinking. Valves for regasification facilities in the US were a big potential market a few years ago. Now the potential market lies in gas shale. Many valves are required during the shale-fracturing and gas-extraction phases.

Asia is the dominant market for valves used in semiconductor and flat panel display manufacturing. It is also the big market for valves for new cement plants. However, there is a big retrofit potential at existing US cement plants. These plants need to comply with a new toxic air rule. This will result in purchases of knife gate valves for scrubber systems, control valves for pulsing new fabric filters and rotary valves for new pneumatic conveying equipment.

The large number of new coal-fired power plants planned in Asia will drive the market for valves used with super-critical coal-fired boilers. China is also leading the development of coal-to-liquids. At one time, the Sasol coal-to-liquids plant in South Africa, with 180,000 valves, was the leading user of valves in the world.

Carbon sequestration is at the development stage but even now there is a substantial valve market. Valve purchases for the billion-dollar plant demonstrating Oxyfuel combustion in Illinois will need to begin within the year. Valves for the Sas-

kpower project could be ordered as early as January 2011.

The valve market is served by 37 global suppliers with more than $100 million in valve sales and by 7,000 smaller companies. The top four suppliers enjoy valve sales over $1 billion each. There are only eight suppliers with valve sales in excess of $500 million.

recession caused steel output to fall drastically in recent years in many mature economies. However, as the steel industry recovers and returns to normal production levels, industrial gas demand in the metal market will register the fastest growth of any other segment. Geographically, the best growth opportunities will exist in China, Japan, the US, Germany and India (Fig. 1).

Industrial gas demand expanding

IEC calls for a global taskforce

The Freedonia Group says that world demand for industrial gases will increase 8% annually to $52 billion in 2014 (Table 1).

Volumetric consumption will expand 5% per year to 530 billion cubic meters in the same year. Industrial gases are used throughout the world in numerous applications, but the nations of fastest growth will be the emerging industrial economies of the AsiaPacific region, especially China and India.

Countries with advanced, highly developed industrial economies will grow more slowly.

Other developing regions (Central and South America and Africa-Middle East) will also experience above-average growth.

Industrial gases used by the chemical processing and petroleum refining industries comprise the largest gas-consuming category, accounting for 40% of merchant industrial gas consumption. The chemical manufacturing sector uses industrial gases as feedstocks or process gases for the production of a huge array of chemicals and petrochemicals. In petroleum refining, the drive toward cleaner-burning, low-sulfur fuels will stimulate demand for hydrogen.

Countries with strict mandates for clean fuel are already using voluminous amounts of hydrogen. Those where clean fuel standards are still to be implemented will require similar amounts of hydrogen, as they strive to reduce harmful environmental emissions.

Much of this incremental hydrogen will be supplied by merchant producers of the gas, and the supply of merchant hydrogen to refiners represents the largest growth opportunity for this industry.

Metal production and fabrication is the second-largest market segment for industrial gas consumption, and will account for 24% of total demand value in 2014. The global

The International Electrotechnical Commission (IEC) is calling for a global taskforce to coordinate technology-based energy efficiency initiatives in an effort to increase coherence and reduce duplication and wasted time. The details of the IEC’s plea can be found in its white paper, “CopTABLE 1. Valve expenditures by global region, 2010–2015, $ millions World Region

2010

2015

Africa

2,094

2,546

CIS

3,007

3,327

11,042

14,232

962

1,049

East Asia Eastern Europe Middle East

3,534

3,951

10,658

11,703

South and Central America

3,188

4,144

West Asia

1,052

1,573

Western Europe

9,063

9,551

44,303

51,755

NAFTA

Total

Western Europe 16%

North America 24% FIG. 1

Other regions 18%

Asia-Pacific 42%

World industrial gas demand totaled $35.7 billion in 2009.

This is the regional percentage breakdown.

HYDROCARBON PROCESSING OCTOBER 2010

I 17

HPIMPACT ing with the Energy Challenge,” which was released at last month’s World Energy Congress in Montreal, Canada.

The report attempts to outline how the energy chain needs to be altered to achieve ambitious carbon emission reduction targets of 20% by 2020. In light of its findings and with the demand for electricity expected to triple by 2050, it also identifies areas offering the highest potential for short- and medium-term energy efficiency

results and their underlying standardization needs.

“Business as usual is no longer an option, we need to fundamentally change how we generate and consume energy,” said Jacques Regis, president of the IEC. “The IEC calls for a coordinated effort to reach emission targets. All stakeholders need to work together on a planetary scale to reduce currently occurring duplications and ensure better outcomes for technology-based cli-

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mate change initiatives. A key element to achieving those emission targets will be the broad adoption of the concept of smart electrification. While as an organization we have always delivered the underlying frameworks needed to enable the roll out of energy-efficient technologies, we must now broaden our scope to include a systems approach on a global scale and to achieve a closer cooperation with governments and regulatory bodies.”

The white paper focuses on the potential for “smart electrification” to help meet the challenge of a growing global population, diminishing natural energy supplies and the need to reduce carbon emission levels.

Proposing that electric energy is the most versatile and controllable form of energy, the easiest and most efficient to distribute, with little wastage and the potential to be produced cleanly, the white paper explores what must be done to achieve the highest levels of energy efficiency. Through its assessment of the entire energy chain—from generation to distribution, consumption and storage—the IEC uses a projection model to identify future standardization needs over the next 20 years.

The IEC believes that there needs to be a redesign of the energy chain.

“There is a need to look at how we generate and consume energy, to redesign systems on a global scale, not individual products in specific countries/regions. This will directly impact how standards will be written and used,” the white paper said.

The group also argues for greater efficiency in how raw energy is used. The smarter use of electric energy, what the IEC calls “smart electrification,” can reduce emissions by using energy more efficiently through a system wide approach. It is anticipated that the energy saved can help drive economies everywhere and provide more power to the energy poor.

The final major argument contained within the white paper is that technology coordination needs to be put in place.

“There is a need to ensure global coordination between all stakeholders to ensure technical feasibility is guaranteed globally and standardization is consistent internationally,” the white paper said.

As the result of the findings of the white paper, the IEC will now develop necessary reference and systems architectures to achieve a smart-electrification future, and seek greater collaboration and cooperation with international organizations, governments and regulatory bodies.

HPIMPACT The new biofuel: it’s whisky in a car Edinburgh Napier University in Scotland has filed a patent for a new biofuel made from whisky byproducts, which it says can be used in ordinary cars, without any special adaption needed.

The fuel process has been developed over the last two years by Edinburgh Napier’s Biofuel Research Center. As part of its research, the center was provided with samples of whisky distilling byproducts from Diageo’s Glenkinchie distillery. The £260,000 research project was funded by Scottish Enterprise’s Proof of Concept program.

The Edinburgh Napier biofuel research team focused on the £4 billion whisky industry as a ripe resource for developing biobutanol—the next generation of biofuel which gives 30% more output power than ethanol. It uses the two main byproducts of the whisky production process—“pot ale,” the liquid from the copper stills, and “draff,’”the spent grains, as the basis for producing the butanol that can then be used as fuel.

With 1,600 million liters of pot ale and 187,000 tons of draff produced by the malt whisky industry annually, there is real potential for this biofuel. Unlike ethanol, the nature of this biofuel means that ordinary cars could use the more powerful fuel, instead of traditional gasoline. The product can also be used to make other green renewable bio chemicals, such as acetone.

The university now plans to create a spinout company to take the new fuel to market and leverage the commercial opportunity, in the bid to make it available at gas pumps.

“The EU has declared that biofuels should account for 10% of total fuel sales by 2020. We’re committed to finding new, innovative renewable energy sources,” said Martin Tangney, the director of the Edinburgh Napier Biofuel Research Center.

“While some energy companies are growing crops specifically to generate biofuel, we are investigating excess materials such as whisky byproducts to develop them. This is a more environmentally sustainable option and potentially offers new revenue on the back of one of Scotland’s biggest industries. We’ve worked with some of the country’s leading whisky producers to develop the process.”

Studying the future of transportation fuels The National Petroleum Council (NPC) is a federal advisory committee to

the US Secretary of Energy. At its September meeting, the NPC discussed the progress of one of its ongoing studies. The study examines future transportation fuels prospects through 2035, with views to 2050, for auto, truck, air, rail and waterborne transport. Specifically, the study is designed to: • Address fuel demand, supply, infrastructure and technology.

• Describe accelerated technology path-

ways to improved fuel efficiency, reduced environmental impact, and deployment of alternative fuels at scale.

• Describe actions industry and government can take to stimulate the technological advances and market conditions needed to reduce life-cycle greenhouse gas emissions in the US transportation sector by 50% by 2050 relative to 2005 levels, while enhancing the nation’s energy security and economic prosperity. HP

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19

PROCESS INSIGHT Comparing Physical Solvents for Acid Gas Removal Physical solvents such as DEPG, NMP, Methanol, and Propylene Carbonate are often used to treat sour gas. These physical solvents differ from chemical solvents such as ethanolamines and hot potassium carbonate in a number of ways. The regeneration of chemical solvents is achieved by the application of heat whereas physical solvents can often be stripped of impurities by simply reducing the pressure. Physical solvents tend to be favored over chemical solvents when the concentration of acid gases or other impurities is very high and the operating pressure is high. Unlike chemical solvents, physical solvents are non-corrosive, requiring only carbon steel construction.

A physical solvent’s capacity for absorbing acid gases increases significantly as the temperature decreases, resulting in reduced circulation rate and associated operating costs.

PC (Propylene Carbonate) The Fluor Solvent process uses JEFFSOL® PC and is by Fluor Daniel, Inc. The light hydrocarbons in natural gas and hydrogen in synthesis gas are less soluble in PC than in the other solvents. PC cannot be used for selective H2S treating because it is unstable at the high temperature required to completely strip H2S from the rich solvent. The FLUOR Solvent process is generally limited to treating feed gases containing less than 20 ppmv; however, improved stripping with medium pressure flash gas in a vacuum stripper allows treatment to 4 ppmv for gases containing up to 200 ppmv H2S. The operating temperature for PC is limited to a minimum of 0°F (-18°C) and a maximum of 149°F (65°C).

Gas Solubilities in Physical Solvents All of these physical solvents are more selective for acid gas than for the main constituent of the gas. Relative solubilities of some selected gases in solvents relative to carbon dioxide are presented in the following table.

The solubility of hydrocarbons in physical solvents increases with the molecular weight of the hydrocarbon. Since heavy hydrocarbons tend to accumulate in the solvent, physical solvent processes are generally not economical for the treatment of hydrocarbon streams that contain a substantial amount of pentane-plus unless a stripping column with a reboiler is used.

Typical Physical Solvent Process

Gas Component

DEPG at 25°C

PC at 25°C

NMP at 25°C

MeOH at -25°C

DEPG (Dimethyl Ether of Polyethylene Glycol)

H2

0.013

0.0078

0.0064

0.0054

DEPG is a mixture of dimethyl ethers of polyethylene glycol.

Solvents containing DEPG are marketed by several companies including Coastal Chemical Company (as Coastal AGR®), Dow (Selexol™), and UOP (Selexol). DEPG can be used for selective H2S removal and can be configured to yield both a rich H2S feed to the Claus unit as well as bulk CO2 removal. DEPG is suitable for operation at temperatures up to 347°F (175°C).

The minimum operating temperature is usually 0°F (-18°C).

Methane

0.066

0.038

0.072

0.051

Ethane

0.42

0.17

0.38

0.42

CO2

1.0

1.0

1.0

1.0

Propane

1.01

0.51

1.07

2.35

n-Butane

2.37

1.75

3.48

-

COS

2.30

1.88

2.72

3.92

MeOH (Methanol)

H 2S

8.82

3.29

10.2

7.06

The most common Methanol processes for acid gas removal are the Rectisol process (by Lurgi AG) and Ifpexol® process (by Prosernat). The main application for the Rectisol process is purification of synthesis gases derived from the gasification of heavy oil and coal rather than natural gas treating applications. The two-stage Ifpexol process can be used for natural gas applications. Methanol has a relatively high vapor pressure at normal process conditions, so deep refrigeration or special recovery methods are required to prevent high solvent losses. The process usually operates between -40°F and -80°F (-40°C and -62°C).

n-Hexane

11.0

13.5

42.7

-

Methyl Mercaptan

22.4

27.2

34.0

-

NMP (N-Methyl-2-Pyrrolidone) The Purisol Process uses NMP® and is marketed by Lurgi AG. The flow schemes used for this solvent are similar to those for DEPG. The process can be operated either at ambient temperature or with refrigeration down to about 5°F (-15°C). The Purisol process is particularly well suited to the purification of high-pressure, high CO2 synthesis gas for gas turbine integrated gasification combined cycle (IGCC) systems because of the high selectivity for H2S.

Choosing the Best Alternative A detailed analysis must be performed to determine the most economical choice of solvent based on the product requirements. Feed gas composition, minor components present, and limitations of the individual physical solvent processes are all important factors in the selection process.

Engineers can easily investigate the available alternatives using a verified process simulator such as ProMax® which has been verified with plant operating data.

For additional information about this topic, view the technical article “A Comparison of Physical Solvents for Acid Gas Removal” at http://www.bre.com/tabid/147/Default.aspx. For more information about ProMax, contact Bryan Research & Engineering or visit www.bre.com.

Bryan Research & Engineering, Inc. P.O. Box 4747 • Bryan, Texas USA • 77805 979-776-5220 • www.bre.com • sales@bre.com Select 113 at www.HydrocarbonProcessing.com/RS

HPINNOVATIONS SELECTED BY HYDROCARBON PROCESSING EDITORS editorial@gulfpub.com

Platform technology improves cooling system efficiency GE has introduced a technology platform called TrueSense. This technology gives users previously unavailable tools to optimize productivity and increase water savings in the monitoring and control of cooling-water systems that are used in heavy-manufacturing industries and large commercial and institutional facilities to cool production equipment and for air conditioning. TrueSense automation and knowledge-management capabilities will allow users to free up time and resources to focus on critical processes that are core to their business.

TrueSense integrates three new and unique functionalities into one platform: direct online monitoring of critical water chemistries; personal instrumentation that dramatically cuts offline testing time; and a powerful data analysis and display capability that provides deep insight into system status. TrueSense is a tangible result of GE’s focus on developing solutions to address water-management challenges even in the toughest operating conditions.

“Maintaining cooling system efficiency to manage costs and minimize our water footprint is a critical aspect of our operation,” said Terry Black, water treatment supervisor at NMLK Indiana. “With TrueSense, we now have seen the impact of a much more precise and timely understanding of our water chemistry. This information has enabled us to optimize the amount of chemicals and water that we use, and it gives us the ability to operate the system more efficiently, leading to cost savings and less water used.”

Decisions about how to operate a cooling system from a water-treatment perspective impact total operational costs related to fresh-water consumption, energy consumption, cooling-tower treatment chemicals and wastewater discharge. Optimization of a cooling system using TrueSense can yield an estimated total operating costs savings of 25% or more when enabled with the right treatment chemistry. In a moderately sized industrial cooling tower, a system running under optimal conditions could save

nearly $400,000 per year in fresh-water acquisition costs alone.

TrueSense is the result of simultaneous technical advances in the measurement and control of critical cooling system parameters, in both online and offline modes of operation. Key elements of the new TrueSense platform include: • TrueSense Online for Cooling— The platform’s core element. This is a single unified online technology that can directly measure and monitor multiple core chemistries that are applied for effective cooling-water treatment, such as orthophosphate for corrosion control; proprietary polymers for deposit control; and the management of halogens like chlorine or bromine for microbiological control. TrueSense Online provides a better understanding of cooling system status, enabling users to tighten control parameters to avoid or better respond to system variations and upsets, reduce water use and costs, and to lower total cost of operation.

• TrueSense Personal Water Analytics (PWA)—A digital field-deployable, rugged, personal water sampling system that complements GE’s online offering.

TrueSense PWA (Fig. 1) measures multiple critical parameters with a single 3-ml water sample, accomplishing this in minutes vs. the half-hour that offline testing protocols typically require, slashing sampling times by an estimated 80%. It minimizes the need to maintain an inventory of reagent chemicals and equipment for testing and considerably cuts testing costs.

• TrueSense View—A knowledgemanagement solution for system visualization, analysis, alarming and reporting.

TrueSense View arms plant personnel with the right information in terms of content, frequency and form, with the flexibility to have data stored either locally and/or on the Web. In addition, wireless features minimize deployment time and cost.

TrueSense View is compatible with other platform components.

The TrueSense platform is designed to work in conjunction with GE’s most advanced cooling chemistry, GenGard with stress-tolerant polymer. The synergy between these two technologies enables

optimal performance of cooling water systems with forgiving chemistry that performs even in the toughest conditions.

While TrueSense is designed to be a highly accurate, easy-to-use, cost-effective and integrated tool set, all components can perform separately as needed, maximizing the efficiency of existing systems. These technologies will be available in major markets around the world.

Select 1 at www.HydrocarbonProcessing.com/RS

New user interface lowers running costs A new breed of laboratory information management system (LIMS) that features a breakthrough user interface was launched by Two Fold Software Limited. The easy-to-use Qualoupe LIMS solution greatly simplifies LIMS use and lowers running costs. It offers productivity gains, improved quality management and reporting flexibility, and an intuitive, configurable user interface designed to enhance the user experience and revolutionize work flow.

A powerful, versatile laboratory tool, Qualoupe delivers the information that users need, while distancing them from

FIG. 1

GE’s TrueSense Personal Water Analytics system.

As HP editors, we hear about new products, patents, software, processes, services, etc., that are true industry innovations—a cut above the typical product offerings. This section enables us to highlight these significant developments.

For more information from these companies, please go to our Website at www.

HydrocarbonProcessing.com/rs and select the reader service number.

HYDROCARBON PROCESSING OCTOBER 2010

I 21

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HPINNOVATIONS having to understand or see the underlying LIMS data structures. It’s easy to install, which saves time and money while minimizing installation disruption.

The Web-based Qualoupe user customizable interface is principally icon-driven and features uncluttered screens using a just-enough information model (JEIM) that requires minimal mouse clicks to operate. For most applications there are a maximum of four action buttons located in the same area of each screen to simplify user operation.

Qualoupe’s self-learning interface (SLI) monitors data that is commonly used by each user, facilitating faster selection of records, which, coupled with native data queries, offers very powerful ad-hoc realtime information access in support of decision making. The interface features microformats associated with fields that are capable of linking to other systems or services. Third-party application access via the user interface can be readily implemented.

Qualoupe can also be easily configured to be multilingual throughout.

Qualoupe offers full audit trails and helps to simplify compliance with UKAS, FDA, ISO 17025, MRC, GLP and GMP. The system’s software is optimized to share data across and between an organization’s sites, and it supports both manual and automated data capture.

Two Fold Software’s development team has used its own extensive LIMS experience to evaluate the market needs and rival LIMS products. Evaluation of end-user feedback showed that the user community wanted an easy-to-use and intuitive product. Two Fold’s analysis of the LIMS products currently on the market shows that they are all extremely complicated to operate and feature poor user interfaces. Qualoupe elegantly solves these user-related issues. The design team’s philosophy is to create a LIMS interface that offers: “The user experience you want, with the information you need.”

double the efficiency of current methods.

“Since HOPES technology does not involve steam reformation, all CO2 emissions are removed from the process,” said Jetstream Wind, Inc. CEO, Henry Herman. “This lays the foundation for a viable economic bridge by creating savings on excessive hydrogen transportation costs and through emissions reductions, allowing for additional revenue streams through the sale of carbon credits. These are key

factors that play a large role in the bottom line of the industry.”

Through onsite hydrogen production, Jetstream Wind, Inc., provides technology to alleviate financial and environmental risks, highlight sustainable corporate responsibility, reduce operational costs, and create larger profits to maintain shareholder value in the petroleum refining industry and the global community.

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Clean hydrogen technology— economical gain for US industry Jetstream Wind, Inc., a developer of breakthrough energy technology, hits another milestone in the clean energy industry. The well-anticipated hydrogen overage production efficiency system (HOPES) will safely provide emissionsfree, 99.9% high-purity hydrogen with an elevated rate capacity and more than Select 154 at www.HydrocarbonProcessing.com/RS 23

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modules keep your project on schedule with consistent, reliable performance anywhere in the world. ®

Anchor-Loc 3 insulating fiber modules are specifically designed and manufactured for the global market, providing a winning combination of performance, reliability and consistency you can count on anywhere in the world. This new generation ® Insulating Fiber Modules of Anchor-Loc modules is designed to meet a wide range of application requirements in a variety of heat processing vessels. They provide continuous S-folded blanket construction for improved thermal performance in high temperature applications and are available in various fiber chemistries, temperature grades and densities to meet the most demanding requirements. Anchor-Loc 3 modules offer:

Consistent design & quality assurance Anchor-Loc 3 module design features construction from a continuous fold of spun blanket, stainless steel alloy hardware and center mount attachment. The design allows for consistent furnace layout, ease of installation and dependable service life. All components meet or exceed established industry standards assuring the same high quality worldwide.

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Select 68 at www.HydrocarbonProcessing.com/RS

HPIN CONSTRUCTION BILLY THINNES, NEWS EDITOR BT@HydrocarbonProcessing.com

North America Science Applications International Corp. (SAIC) announced its wholly-owned subsidiary, Benham Constructors, LLC, has been awarded two new contracts by a subsidiary of Holly Corp. to provide engineering, procurement and construction services. The contracts have a combined value of approximately $27 million. Work will be performed in Oklahoma City and Tulsa, Oklahoma.

Holly produces gasoline, diesel and jet fuel, as well as specialty lubricants, oil and waxes at its Tulsa refining facility. The first contract will support Holly’s interconnecting piping project and is valued at $14 million. Under the contract, Benham will help integrate piping interconnections at Holly’s east and west refining facilities by performing tasks such as site preparation; utility relocation; foundation design and installations; and piping and structural steel design, fabrication and installation.

Under the second contract, valued at $13 million, Benham will support Holly’s diesel hydrotreater revamp project by developing a front-end process design package and providing detail engineering, procurement and construction for the modified facilities.

Nalco Mobotec, Inc., has signed a contract with Hoosier Energy Rural Electric Cooperative, Inc., to provide two Rotamix selective noncatalytic reduction (SNCR) systems for nitrogen oxide (NOx) control at the Frank E. Ratts generating station in Petersburg, Indiana. The generating station is a coal-fired power plant consisting of two 125-megawatt boilers, originally built in 1970. Nalco Mobotec will begin work immediately with both units scheduled for continuous operation of the new system by December 2011. Nalco Mobotec’s patented technology reduces NOx emissions from utility and industrial boilers. The technology will build on previous significant NOx reduction provided by Nalco Mobotec’s patented rotating opposed fired air (ROFA) technology to contain and reduce NOx emissions.

Williams Partners LP has commenced operations on the fourth cryogenic processing train (TXP4) at the Echo Springs natural gas processing plant in Carbon County, Wyoming. The TXP4 plant adds approxi-

mately 350 million cfd of natural-gas processing and 30,000 bpd of natural gas liquid (NGL) production, roughly doubling Echo Springs’ capacity in both cases. Current gathered volumes exceed 475 million cfd and are expected to grow with producer drilling plans. This expansion provides the ability to process currently flowing bypass gas, as well as the ability to process expected future increases in third-party gas production.

Construction began on the expansion in the second half of 2009 and it was placed into service nearly two months ahead of schedule and significantly under budget.

Including this expansion, Williams Partners’ Opal and Echo Springs processing plants in Wyoming have a combined daily inlet capacity of more than 2.1 billion cfd of natural gas and 130,000 bpd of NGL production capacity.

Engineering, procurement and construction (EPC) activities are underway for Fulcrum BioEnergy’s Sierra BioFuels plant.

Fulcrum entered into a contract with a subsidiary of Fluor Corp. for the EPC services.

The plant will convert common household garbage into transportation fuel for cars and TREND ANALYSIS FORECASTING light trucks. It is scheduled to begin operaHydrocarbon Processing maintains an tions in 2012. extensive database of historical HPI proj-

sultancy (PMC) services for Gulf Farabi’s linear alkyl benzene (LAB) plant expansion at Al-Jubail, Saudi Arabia. The new plant will have a production capacity of 100,000 tpy of LAB, which is a basic ingredient in the formulation of synthetic detergents. The first phase of the project covers the preparation and issue of an invitation to bid (ITB) for the engineering, procurement and construction management (EPCm), EPCm bid evaluations, preparation of the EPCm contract and support to Gulf Farabi during the engineering and procurement phase of the project. For the second phase, Foster Wheeler will provide support to Gulf Farabi during the construction phase, with key personnel based onsite in 2010 through 2011 when the project is scheduled for completion.

Asia-Pacific Indian Oil Corp. Ltd (IOCL) has chosen Axens to supply the technology for its coker gasoil (CGO) hydrotreating unit at its refinery in Haldia, India. With a design capacity of 1.4 million tpy, the new unit will hydroprocess light coker gasoil, heavy coker gasoil and coker naphtha. In addition, the unit will be able to process straight run gasoil and straight-run vacuum gasoil.

In view of the complexity of the feed, the

ect information. Current project activity

is published three times a year in the HPI Europe

Construction Boxscore.

When atoproject Air Products has a contract supply is completed, it is removed from current Voronezhsintezkauchuk, part of the listings and retained in a database. The petrochemical company SIBUR,ofwith database is a 35-year compilation proj- a ectson-site by type, operating unit company, licennew air separation (ASU).

The sor, will engineering/constructor, location, etc.

ASU have the capacity to produce up companies use the historical data for toMany 3,000 m/hr of gaseous nitrogen when trending or sales forecasting.

onstream in 2012, plus up to 16,000 m/ The historical information is available in hrcomma-delimited of dry compressed air.

In addition ® and or Excel can be cus-to providing tom sortedVoronezhsintezkauchuk to suit your needs. The costwith of depends ongas the requirements, size and complexallthe of sort its industrial Air ity of the sort you request and whether a Products will supply liquid product to the customized program must be written. You Russian market.

As partrequest of thissuch agreement, can focus on a narrow as the Air Products’ first with state-owned history of a particular typea of project or you can obtain 35-yearwill Boxscore Russian firm, the theentire company own, database, or portions thereof. operate and maintain the ASU to be located send a clear description of the data atSimply Voronezhsintezkauchuk’s site. you need and you will receive a prompt cost quotation. Contact:

Middle East Lee Nichols

Foster Wheeler Global EngineerP. O. AG’S Box 2608 Houston, Texas,Group 77252-2608 ing and Construction has a contract Fax: 713-525-4626 with Gulf Farabi Petrochemical Co. for e-mail: Lee.Nichols@gulfpub.com. the provision of project management con-

TREND ANALYSIS FORECASTING Hydrocarbon Processing maintains an extensive database of historical HPI project information. The Boxscore Database is a 35-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 of the sort depends on the size and complexity of the sort you request and whether a customized program must be written. You can focus on a narrow request such as the history of a particular type of project or you can obtain the entire 35-year Boxscore database, or portions thereof.

Simply send a clear description of the data you need and you will receive a prompt cost quotation. Contact: Lee Nichols P.O. Box 2608, Houston, Texas, 77252-2608 Fax: 713-525-4626 e-mail: Lee.Nichols@gulfpub.com HYDROCARBON PROCESSING OCTOBER 2010

I 25

HPIN CONSTRUCTION design of this unit will be the first of its kind at IOCL. IOCL’s Haldia refinery currently has a 7.5 million-tpy crude oil capacity.

After the expansion, the unit will be producing Euro-III and Euro-IV grade gasoline and diesel.

Uhde Inventa-Fischer and Hangzhou Hangding Nylon Tech have signed a contract for the delivery of a PA-6 polymerization plant to produce textile grade chips,

based on Uhde Invtenta-Fischer’s technology. The new plant (to be located in Zhejiang Province, China), with a capacity of 47,000 metric tpy, will produce high performance polyamide-6 (HPPA) textile grade chips for Hangding’s modern high-speed spinning plants. This technology improves the rate of yield of the raw material caprolactam and optimizes the yield increase in the FDY and POY spinning process, as well as in the subsequent downstream processing.

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Contact us by phone or on the web for details on how to order.

The GLT heat transfer fluid is an alkylated-aromatic based fluid for mainly closed-loop, liquid-phase heating systems to 550°F using fired heaters (and to 575° in waste-heat recovery systems).

The Paratherm HR heat transfer fluid is also an alkylated-aromatic based fluid formulated for liquid-phase heating to 650°F in fired heaters and 675°F in waste-heat recovery and full-convection heaters.

Paratherm MG is biodegradable, aliphatic-hydrocarbon based and runs at 550°F in fired heaters and at 580°F

in full-convection heater and electric immersion units.

For these fluids or any other of our nearly dozen fluids or cleaners pick up the phone and call one of our technical specialists. It’s part of our program called Immersion Engineering™ that insures you get the finest products and services for all your heat transfer fluid needs.

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Stocking & Sales Locations: USA • Canada • Mexico • Brazil • Argentina • Guatemala • Netherlands • Belgium • Denmark • United Kingdom • Australia • China • Japan • Thailand Copyright© Paratherm Corporation 2010.

26

Select 155 at www.HydrocarbonProcessing.com/RS

®

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Uhde Inventa-Fischer’s scope of supply and services includes the license, the basic and detail engineering, the supply of all proprietary and key equipment, as well as the supervision of the erection and commissioning activities, including the training of the operating personnel at the plant site.

Startup is planned before the 2012 Chinese New Year.

PetroChina’s 1 million-metric tpy refinery in Qinzhou, China, recently started operations. PetroChina had delayed the startup of the refinery from June. The plant is designed to process crude from Sudan and may be reconfigured to process more crude from West Africa. The refinery is expected to supply 8.3 million tpy of fuel and 900,000 tpy of chemical products to the southwest China market. PetroChina has put the first phase of its crude oil storage depot with capacity of 4.2 million cubic meters in Qinzhou into a test run.

A plant using the combined DMTO methanol-to-olefins technology of SYN Energy Technology Co. Ltd. and Lummus Technology successfully started-up in Baotou, China. It is the world’s first methanol-to-olefins unit to be operated on a commercial scale. The plant is owned by China Shenhua Coal to Liquid and Chemical Co. Ltd. The technology enables licensees to produce olefins (ethylene and propylene) from methanol. The plant is designed to produce 600,000 tpy of olefins from methanol. Onspec ethylene and propylene product were achieved less than 72 hours after methanol was introduced to the unit. The unit is the first of several that have been licensed by SYN and Lummus Technology under a worldwide partnership to offer the reactor and olefins recovery technologies jointly. SYN licensed the reactor and catalyst technology used in the plant and Lummus Technology licensed the olefins recovery technology.

China Petroleum and Chemical Corp. and Kuwait Petroleum Corp. received government approval to start initial work on an oil refinery and chemical project in southern China. The proposed ethylene plant in Nansha, Guangdong Province, will produce 1 million metric tpy of the chemical. The Nansha complex, with a planned investment of $5 billion, would be the largest joint venture in China, exceeding the nearby Nanhai petrochemical facilities built by Royal Dutch Shell Plc and China National Offshore Oil Corp. HP

HPI CONSTRUCTION BOXSCORE UPDATE Company

City

Plant Site

Project

Capacity Unit Cost Status Yr Cmpl Licensor Engineering

Constructor

UNITED STATES Colorado Williams Partners LP North Carolina Chemetall Foote Corp Virginia Western Refining

Parachute Creek Parachute Creek Kings Mountain Kings Mountain Yorktown Yorktown

Gas Plant Lithium Hydroxide Refinery

TO EX EX

Esmeraldas Guarico Guarico

Esmeraldas Guarico Guarico

Isomerizer Preflash Pressure Hydrofinishing

RE RE RE

Anqing Dagang Gaoqiao Guangdong Huaibei Huizhou Jinling Jiujiang Luoyang Maoming Ningxia Quanzhou Shijiazhuang Sichuan Zhenhai New Delhi Balongan Indramayu Java Lhasa

Anqing Dagang Gaoqiao Jieyang Huaibei Huizhou Jinling Jiujiang Luoyang Maoming Ningxia Quanzhou Shijiazhuang Sichuan Zhenhai New Delhi Balongan Indramayu Java Lhasa

Refinery Refinery Refinery Refinery Refinery Refinery Refinery Refinery Refinery Refinery Refinery Refinery Refinery Refinery Refinery Refinery Refinery Refinery Refinery (2) LNG Terminal

EX EX EX EX EX EX EX EX EX EX EX EX EX EX EX EX TO TO TO TO

Maissan Al Jubail Abu Dhabi

Maissan Al Jubail Habshan Gas Complex

Cracker, FCC Alkylbenzene Refinery

Enerkem/Greenfield Ethanol JV Edmonton Grizzly Oil Sands ULC Fort McMurray

Edmonton Fort McMurray

Air Products ConocoPhillips

Ghent Cork

450 Mcfd bpd 28.4 70 bpd

P U H

2013 2011 2010

H P P

2011 2013 2013

P H P P P S H P P H P P P P H P S S H U

2012 2014 2010 2013 2012 2020 2012 2012 2011 2015 2011 2014 2013 2012 2015 2017 2011 2011 2016 2011

EX 47500 bpd EX 100 tpy None

U U T

2011

KBR FW

Waste to Biofuel Plant SAGD

TO EX

36 MMl/y 75 5000 bpd

U U

2011 2011

Enerkem/Greenfield Ethanol JV Enerkem/Greenfield Ethanol JV SNC-Lavalin SNC-Lavalin

Air Separation Unit Sulfur Recovery Unit

EX EX

2000 tpd 10 tpd

U H

2012 2011

KBR

LATIN AMERICA Ecuador Venezuela Venezuela

Petroindustrial Intevep Intevep

3 Mbpd 40 tpy 40 tpy

6

UOP Viscolube Axens

ASIA/PACIFIC China China China China China China China China China China China China China China China India Indonesia Indonesia Indonesia Tibet

Sinopec PetroChina Sinopec PetroChina PetroChina CNOOC Sinopec Sinopec Sinopec Sinopec CNPC Sinochem Sinopec PetroChina Sinopec IOCL Kuwait Petro Corp Kuwait Petro Corp Pertamina PetroChina

60 200 34 400 100 440 100 60 80 240 100 240 60 200 180 300

bpd bpd bpd bpd bpd bpd bpd bpd bpd bpd bpd bpd bpd bpd bpd bpd bpd 300 bpd 300 bpd bpd

6.6

Rosneft PDVSA WorleyParsons

MIDDLE EAST Iraq Saudi Arabia UAE

Iraq Ministry of Oil Gulf Farabi Petrochemical TAKREER

KBR

FW

CANADA Alberta Alberta

EUROPE Belgium Ireland

Ghent Cork

Air Products Jacobs Nederland BV

See http://www.HydrocarbonProcessing.com/bxsymbols for licensor, engineering and construction companies’ abbreviations, along with the complete update of the HPI Construction Boxscore.

BOXSCORE DATABASE

ONLINE

THE GLOBAL SOURCE FOR TRACKING HPI CONSTRUCTION ACTIVITY For more than 50 years, Hydrocarbon Processing magazine remains the only source that collects and maintains data specifically for the HPI community, publishing up-to-the-minute construction projects from around the globe with our online product, Boxscore Database. Updated weekly, our database helps engineers, contractors and marketing personnel identify active HPI construction projects around the world to: • Generate leads • Market research • Track trend analysis • And, decide future budget planning.

Now, we’ve made our best product even better!

Enhancements include: • Exporting your search results to Excel so you can compile your research • Delivering the latest updated projects directly to your inbox each week • Designing customized construction reports for your company using our 50 years of archived projects.

For a Free 2 -Week Trial, contact Lee Nichols at +1 (713) 525-4626, Lee.Nichols@GulfPub.com, or visit www.ConstructionBoxscore.com

Select 156 at www.HydrocarbonProcessing.com/RS HYDROCARBON PROCESSING OCTOBER 2010

I 27

Select 74 at www.HydrocarbonProcessing.com/RS

PROCESS CONTROL AND INFORMATION SYSTEMS

SPECIALREPORT

How to have a successful data reconciliation software implementation Follow these guidelines to ensure success H. WON, W-S. CHO and T. AYRAL, Inlibra Software Solutions Corp., Calgary, Canada; I. SAMAD, FertiNitro

O

ver the past 20 years, many data reconciliation (DR) projects have been completed but unfortunately are not considered successful and do not produce usable results even after many years of work and large sums of money have been spent.

The classic failed DR project follows the pattern described below: • Inexperienced programmers create a feature-deficient DR software tool that is then subsequently deployed by equally inexperienced DR implementation consultants.

• The DR implementation consultants perform little plant personnel training, very little communication occurs between the consultants and the clients, and no discussion occurs about the unique balance problems for the plant.

• This leads to a never-ending list of surprise results that erode user confidence to the extent that the user never views the model as complete and does not use reconciled results in their reports and key performance indicator (KPI) calculations.

Result: The project is viewed as a failure.

• At least two months of previous days’ data must be balanced to provide an initial historical basis and to validate the model robustness in dealing with unusual operating conditions that are bound to have occurred.

• Every new day’s plant movements can be reconciled, no day’s data are missed; therefore no falling behind occurs.

Clients should not settle for anything less than the ability to complete reconciliation

How to have a successful data reconciliation project. The authors

have seen this pattern repeat time after time and have developed some methodologies for having a successful DR project.

These methodologies and technology are described in the following article sections: Well-defined success criteria.

To declare a successful project, a clearly defined criteria definition is required. The following are obtainable and realistic completion criteria:

FIG. 1

An example graphical trend screen shot.

HYDROCARBON PROCESSING OCTOBER 2010

I 29

SPECIALREPORT

PROCESS CONTROL AND INFORMATION SYSTEMS

of the previous day’s data and perform reasonable reconciled data verification in less than an hour per day. The software itself may offer some assistance to list probable measurement errors in a way that allows the plant engineers to quickly see if there were data problems or unusual results. But plant engineers may also create summary report screens that quickly shed light on which key plant parts may

require investigation. Investigating such problems and fixing them where necessary can usually be done within a half hour. Very unusual problems may require a one-time investigation that takes a little more time. If the daily DR work takes up too much key plant personnel time, then the DR will not get performed daily.

• All streams that represent consumption or production, or contribute to the

balance of any process in the plant, are incorporated into the model.

• All reports that would benefit from showing reconciled data do so.

In addition, regarding the services provided by the DR implementation consultants and when they are completed, the following four requirements must be met to demonstrate reliance from the DR consultants: • The consultants should not work alone in developing and testing the model, but instead should work closely with more than one plant personnel.

• The plant configuration should be clear and transparent so that even plant personnel who did not participate in the model’s creation can understand it.

• Sufficient training (formal and informal) must be a planned milestone, scheduled as part of the project.

• There must not be hidden tricks and obscure features in the software itself, which the DR consultant uses to resolve situations that would otherwise not be independently solvable by the plant DR staff on their own.

Field-proven DR software with the proper features. If someone

30

FIG. 2

An example full plant model.

FIG. 3

An example separate model.

I OCTOBER 2010 HYDROCARBON PROCESSING

who has not had to perform daily data reconciliation creates a software tool to perform that task, the result will probably be a piece of software that lacks basic usability features. While users have no control over the software design philosophy from a particular DR software company, they should evaluate the software usability issues and features as described here: • The DR tool should be able to show not only the measured and reconciled values for the day being reconciled, but in addition it should be able to show and contrast data from other days that were reconciled in the past. Ideally, it should be easy to create a graphical trend of historical measured and reconciled data (Fig. 1).

• How many times have software users been frustrated by applications that show some data as a graph or plot but won’t let the user access it as tabular text? Every modern application, and specifically DR software, should permit users to easily dump or paste numerical data, preferably in a format acceptable to Microsoft Excel.

• The application should permit both the functionality of building a large configuration model in one graphical user

PROCESS CONTROL AND INFORMATION SYSTEMS interface (GUI) screen and also dividing the configuration model up into separate screens while still treating the configuration as an integrated whole for balancing as one model. Fig. 2 shows the complexity of a full plant model and Fig. 3 shows a separate part of the full model.

• The potential purchaser of DR software must watch for size or performance limitations that pertain to size (model object count). With today’s processor capabilities, DR software should be able to reconcile an almost unlimited number of streams, with the real limiting factor being physical plant size.

• The DR software should assist the user by presenting in one or a small number of places enough key information to determine whether the balance was made without problems. Users don’t want to spend much time reviewing the daily reconciled values, especially on days when the plant reconciled well with no issues.

• The software tool should permit the use of formulas and a calculation engine so that in the user’s balance model the users can utilize values derived from measurements, reconciled or other calculated values.

• Stream components must also balance. Does the software support simultaneously enforcing a component balance (e.g., carbon, water or hydrogen) along with the overall mass balance? This is a powerful way to increase the mass balance accuracy when the amount of flow measurement in the plant is on the low side for an accurate mass balance. Fig. 4 shows an example component balance.

• It should be possible to edit the model without losing the historical data associated with the changed stream or plant object. This is extremely important when clients need to make modifications to their plants after the initial project lifespan.

• Automatic gross-error detection is indispensable. Software that relies on human intuition to identify and remove faulty measurements from the reconciled data set is subject to errors when the human engineer misses something or removes a value that should not be omitted. Mechanization of the process of detecting and removing faulty measurements also ensures that results are consistent regardless of who is operating the software. Fig. 5 shows an example of a gross-error detection screen shot and Fig. 6 shows a screen with reconciled and raw data shown that are used for error detection.

Experienced team to properly configure the model. One of the

challenges with DR software is that, because it is software, a DR software provider may utilize IT personnel for implementation who may not have a solid understanding of the basic plant operations and DR theory and practice.

In addition, a DR implementation team’s field consultants may lack experience with successful DR deployment projects. In unsuccessful projects, plant model development often seems to stall at the mythical 90% level. This is a very subjective judgment, and the model may actually be nowhere near 90% complete if it needs to be revamped. The stall happens because, as more of the plant is mod-

SPECIALREPORT

eled, cumulative inaccuracies arising from incomplete and inaccurate modeling start to impede the ability to balance the data from any particular day. Unfortunately, 90% completion is the same as 0% in terms of data usability. Nevertheless, in unsuccessful projects, both the DR consultants and the plant’s project team naturally try to put a positive spin on how close to completion the model is when reporting to plant management. In successful projects all streams that represent consumption or production, or contribute to the balance of any process in the plant, are incorporated into the model. DR consultants who in the past walked away from 90% complete projects will not be able to get a client’s project to 100% success.

FIG. 4

An example component balance (balancing nitrogen, carbon).

FIG. 5

An example gross error detection screen shot showing the problem balance equipment in red.

HYDROCARBON PROCESSING OCTOBER 2010

I 31

SPECIALREPORT

PROCESS CONTROL AND INFORMATION SYSTEMS

Not only do the DR consultants need to speak the client’s process engineers’ jargon, they also need to understand the

FIG. 6

normal plant operation and the client’s processes in particular. They also need to be familiar with how to troubleshoot

a balance, what streams and components can be balanced, how to tune parameters to perfect a balance, tricks for compensating for faulty or missing instrumentation and similar DR-specific knowledge. An experienced DR implementation team is well versed in all of these tasks.

A trained plant DR team. One sign of a failed DR project is that after implementation the DR consultant’s active assistance is required each day to routinely balance the plant. To have a successful project, plan for and include the training of at least two, and hopefully more, plant personnel into the project. In successful projects the teams don’t let just one plant staff member become the sole knowledge custodian needed to configure DR and run it daily. The DR implementation may die if that person leaves or gets promoted out of that position.

The DR implementation consultants should be planning for this at the project’s start. At least one of the plant personnel should be involved daily with the implementation consultants.

Screen with raw and reconciled data shown.

Teamwork and good communication. A DR consultant requires commu-

nications skills, general process industry background knowledge and the ability to quickly acquire each plant’s process flow knowledge from the client. Creating a good DR consultant takes many years of experience. The DR consultant needs to have communication skills (and patience) to train the plant personnel on DR theory and practice.

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plant’s management must maintain enthusiasm for the DR project, which means that the DR project schedule must not slip and become unreasonably long. If plant management loses enthusiasm, it may start to reallocate key plant personnel time who were critical to the DR project, essentially sounding the DR project’s death knell.

On-schedule completion. The DR project schedule should be short, preferably on the order of about half a year.

Only in this way can the clients keep the interest level high on the plant parts management and the plant staff who will have to work with DR each day. Reliable results must be achieved in this time frame to avoid confidence and defeatism

PROCESS CONTROL AND INFORMATION SYSTEMS crises. Successful project teams get the DR project done in six months.

Producing a complete model.

Despite the arguments for making a large, integrated and complete model, inexperienced amateur DR implementers often propose making a partial plant model.

Why? Shortcomings in the software may limit the ability to deal effectively with large or complex models. Software deficits that may prompt simplification: • Data retrieval from external systems as well as data validation (by human) may take too long on large models.

• The software may force all modeled objects to be represented on one screen.

This is visually overwhelming unless the model is simplified.

• A GUI that does not adequately show spatial relations between objects may limit the ability to represent large configurations comprehensively.

Another reason for simplifications is to eliminate troublesome model parts by encapsulating them within a larger balance envelope.

The result of model simplification by the DR consultant who is not well versed is the “black-box” approach, where a process unit or even several units are treated as an unanalyzed black box with a few known input and output streams. This is illustrated in Fig. 7.

The black-box model simplification obscures the flows and inventory changes in the interior, and removes from the reconciliation algorithm useful, redundant measurements that could improve the reconciled value accuracies for the flows exterior to the black box. Black-box reconciliation tells us nothing about the interior flow or tank inventory measurement accuracies within the box, so the DR may lose much of the diagnostic ability that was a motivating factor for performing reconciliation in the first place.

In some cases, data reconciliation models are reduced ad absurdum to the point where the whole plant is essentially a black box. When DR projects have bogged down, treating the whole plant as a black box is sometimes a way that amateur DR consultants try to salvage some part of the software purchase usefulness. In such cases, the DR software becomes an expensive way to calculate net consumption and production without leveraging the redundant meters within the plant (Fig. 8).

If the client’s only goal was to calculate net consumption and production, then perhaps this approach makes sense. But if that was truly the only goal, then it’s valid to call this a case of overkill, because the software statistical reconciliation capabilities are wasted on this simple case. Keep in mind that the consumption and production are not as accurate as they could be if the redundant meters within the plant contributed to the balance. Another important drawback of this approach is that if the software reports that there is loss, the software cannot pinpoint the loss location within the black box as it would otherwise be able to do.

A model that has been simplified to the extent described is probably primarily using the plant’s battery-limit meters. A model that had not been simplified into a black box would be capable of calculating the discrepancy between the plant’s redundant set of meters and the battery limit meters (which, as custody transfer meters, are treated as not reconcilable for accounting purposes). There is a benefit to knowing this discrepancy, because the model can then reconcile the plant’s internal meters without forcing that battery-limit discrepancy into the unit balances.

Company published KPIs. As long as the company’s KPIs are not expressed using the reconciled results, the DR project might as well never have taken place.

While many plants are engaged in efforts to calculate and make KPIs easily available, those efforts are misplaced if they are based solely on measured, unreconciled values that may not acceptably mass balance.

The cost-saving packing system

HAVER ® FFS DELTA NT

Multiple process units become one black box.

Consumption

Production

My plant

FIG. 8

The Solution Provider

Filling of free-flowing granular, micro-granular or powdery bulk materials into plastic tubular film bags made of PE or PP

Section 1

FIG. 7

HAVER & BOECKER

In the worst case, the whole plant becomes one black box.

HAVER & BOECKER, Germany Phone: +49 2522 30-271 E-mail: chemie@haverboecker.com

www.haverboecker.com

The designation ® indicates a registered trademark of HAVER & BOECKER OHG in Germany. Several indicated designations are registered trademarks also in other countries worldwide. M 914-E4

I

HYDROCARBON OCTOBER 2010 33 Select 158 atPROCESSING www.HydrocarbonProcessing.com/RS

PROCESS CONTROL

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When the company-published KPIs are calculated using the reconciled data the DR project is well along the path to success.

Plants that follow the methodologies and technologies described in this article have proven that DR can and does work successfully in accordance with the success criteria described in this article.

The authors hope that this article has given DR users and potential users some insight into the problems that beset DR projects and thereby, has increased client company’s chances of avoiding those pitfalls. HP

Hong Won is president of Inlibra Software Solutions Corp., a data reconciliation software consultancy based in Calgary, Canada. He has an MS degree in chemical engineering and is a professional Engineer in Alberta, Canada. Mr. Won has both practical, refinery-based experience as well as 12 years of software consulting experience in process control and advanced solutions for major oil companies, some of which was acquired during his time working for Honeywell. His work has taken him to three continents. Mr. Won is a certified Oracle DBA.

Woo-Seok Cho is vice president development of Inlibra Software Solutions Corp., a data reconciliation software consultancy based in Calgary, Canada. He is a chemical engineer with an MS degree in chemical technology from the Seoul National University of Korea. Mr. Cho has 17 years’ experience with data reconciliation in the context of production accounting (yield accounting) systems in the petroleum refining and petrochemical industries and has implemented 20 production-accounting data reconciliation systems for the refining, petrochemical, polymer, fertilizer and gas industries. He is the software author of Inlibra Suite.

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Ikbal Samad is general manager of FertiNitro (Fertilizantes Nitrogenados de Venezuela) and has 30 years of experience in the process industries. He has a master of engineering degree in chemical engineering and environmental engineering. Mr. Samad oversaw successful deployment of mass-balance reconciliation software in 2009 at the FertiNitro plant, for ammonia and urea production.

Tom Ayral is vice president of sales at Inlibra Software Solutions Corp. He has a BS degree in chemical engineering and an MBA and over 30 years of experience in the process industries.

At Inlibra, Mr. Ayral prepares the business cases and financial value proposition for clients. Before Inlibra, he worked for Arco, Mobil, Meridium and KBC, and was a founder and president of Key Control, which he sold in 2003. Mr Ayral has authored of over 50 articles and received the award of “Engineer of the Year” in 1996.

PROCESS CONTROL AND INFORMATION SYSTEMS

SPECIALREPORT

Improve exploration, production and refining with ‘add-at-will’ wireless automation After the technology was validated, a wireless infrastructure was installed blanketing 80% of a US refinery G. LAFRAMBOISE, Chevron Corp., Richmond, California; and B. KARSCHNIA, Emerson Process Management, Austin, Texas

C

hevron is committed to leadership in exploration, production growth and profitable refining utilization. Process automation is an important enabler of these goals.

As part of its continuous focus to add business value, the company’s automation experts participated in very early wireless sensor and mesh network development and testing and IEC 62591 (WirelessHART) technology. Positive results with wireless field trials in upstream installations at San Joaquin Valley, California, led Chevron to reason that new “add-at-will” wireless technology could enable improvements at all of its upstream and downstream facilities, leading to immediate and ongoing efficiencies.

To investigate the feasibility of wide scale deployment, the company conducted in-depth research of wireless technology at the Chevron Wireless Center of Excellence. After the technology was validated and a supplier selected, a wireless infrastructure was installed blanketing 80% of a US refinery.

This installation verified the add-at-will capability of wireless, enabling improvement by simply installing and turning on instruments without the expense and delays of engineering and installing wiring, cable trays, conduit, trenching and more (Fig. 1). It showed the scalability that enables loop-by-loop application for entire plant coverage.

Chevron also learned how to gain the wireless advantages for improved flexibility, reliability, safety, environmental and business performance across its upstream and downstream facilities.

Many of the company’s global operating businesses are now leveraging the investigation results and best practices to move forward with wireless planning and installation.

Additional wireless functionality is being investigated for future use, including enhancing mobile-worker productivity, enabling wireless video for process applications and plant security, and allowing safety mustering and employee, product and equipment location tracking.

producing. Production must continue efficiently for decades to pay back the large investments. Automation to help meet these needs must be small, lightweight and easily implemented in the compact environment of offshore platforms and floating production, storage and offloading (FPSO) facilities.

Onshore land-based fields also need to maximize well life and production. Advancements are needed to provide better production gathering system monitoring, enhanced-recovery distribution systems and process facilities, and to make the improved information available to operations centers controlling geographically dispersed wells and facilities. Through all, personnel safety, environmental protection, reliability and profitability need to be served by technology.

Automation can help improve refining margins while matching output to demand. This calls for improved equipment, instrument and process monitoring to improve uptime and performance and to reduce operating and maintenance costs while meeting new environmental regulations.

Chevron engineering and operations employees have been challenged to develop economic business cases for install-

Business challenges. The opportunity for upstream is clear:

Offshore platforms needed a way to get more and improved information to optimize well production—especially important, since wells can take a decade to find and another decade to begin

FIG. 1

Wireless networks can blanket facilities to enable add-at-will automation.

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ing instrumentation to improve monitoring, reliability and overall business performance of existing facilities. While the instrument cost has been relatively low, planning, engineering connecting and commissioning wired instruments costs in existing plants has been prohibitive. It was estimated that a facility-wide technology to dramatically lower these capital costs would save millions of dollars and enable justifying business-improvement projects.

Could wireless help? Wireless technology has been part of

the Chevron automation landscape for many years, especially as used for SCADA applications across expansive onshore and offshore fields. By contrast, the use of wireless measurement instruments and networks for more confined, contiguous industrial plants and on offshore platforms and FPSOs had previously been unsuccessful. The technology available in the 1990s was not suited for the industrial environment, with deficiencies in communications reliability, security and battery life.

These drawbacks, along with a complete lack of industrial wireless standards and a serious shortage of functionality needed for process applications, led Chevron to postpone the use of wireless field sensor networks for monitoring and measurement that would have been so valuable in their operations. Yet the needs persisted, both upstream and downstream.

Fortunately, semiconductor and battery power technologies suitable for industrial wireless technology matured and in the late 1990s, major process automation suppliers began investing in wireless research and development for the industrial plant environment. Standards development soon began in parallel,

including drafting and then beta-testing approaches with Chevron and other end users to meet communications reliability and security needs.

These efforts culminated with a broad range of wireless measurement instruments built on an open IEC 62591 (WirelessHART) technology communications standard that could deliver 99.9% communications reliability while enabling applying wireless functionality ranging from a few loops to an entire plant.

Chevron automation experts believed that these changes opened the door for another look at wireless technology. A wireless architecture with communications reliability and process functionality approaching that of wired installations could enable step-change improvements in new and existing facility performance around the world. Less engineering and installation would simplify construction and lower wireless project capital costs to enable important field measurements that were previously unaffordable. Additionally, lower installed costs would enable upgrading existing plants in applications where wired additions were precluded by economics.

Investigating wireless. Determined to pursue their wire-

less ideas, Chevron automation experts established a corporate Wireless Center of Excellence at their Energy Technology Company offices in Richmond, California. The center includes a wireless test bed and laboratory that is a staging area for investigating wireless technology and instrumentation from various automation manufacturers. Experts from Chevron upstream, downstream and midstream operating companies consult with corporate technologists at the center and use the laboratory for investigations leading to their own wireless applications piloting around the world.

The laboratory tested wireless communications reliability by presenting a radio frequency (RF) environment even more challenging than that of operating plants where signals must coexist with those from existing sources. Chevron checked software and performed coexistence testing with other equipment and instruments in the RF environment. The laboratory testing was followed by installation in a US refinery that presented typical obstacles including steel structures, moving vehicles, roads and challenging terrain within the approximate 2.5- by 2-mile refinery boundaries.

After validating the new wireless technologies and thoroughly testing and reviewing available wireless offerings, Chevron selected their supplier of choice that could best provide standard wireless instrumentation for Chevron’s present and future needs of improving unit and plant-wide performance and profitability. Selection took into account cost, security, communications reliability, power management, breadth of offering for plant-wide functionality and resources and knowledge to grow and expand wireless in conjunction with wired technology as part of a complete plant automation architecture. As is part of The Chevron Way approach to business, the automation supplier’s technologists would partner with Chevron to co-develop the technology and best practices to help achieve Chevron’s vision.

Implementing wireless. One of Chevron’s earliest experiences with the new wireless technology from the selected supplier was with steam injection for oil and gas recovery at its existing San Ardo, California, oil field. A network of wireless

Select 160 at www.HydrocarbonProcessing.com/RS 36

PROCESS CONTROL AND INFORMATION SYSTEMS transmitters delivers reliable data that help minimize oversteaming and reduce wastewater discharge. Since the injection data are sent to the oil field’s control room, personnel no longer need to visit the injection wells to collect data from traditional chart recorders or to check instruments for proper operation.

In addition, operators no longer need to make and break highpressure and temperature connections. As a result, personnel safety is improved.

A second wireless network in the oil field uses wireless battery-powered transmitters to measure downhole well pressure.

Chevron uses the data collected for its proprietary oil formation calculations, including determining steam injection requirements, oil flow patterns and new well locations. The new wireless network saves installation costs and reduces maintenance compared with the existing remote telemetry units.

The California installation illustrated the benefits of select wireless applications integrated into the existing upstream fields and working with existing long-range communications.

Further exploration of the new technology was underway at a Chevron refinery where a multidiscipline engineering, operations, maintenance and IT personnel project team was leading Chevron’s pursuit of an add-at-will capability. This innovative project was envisioned to blanket the refinery with wireless communication infrastructure consisting of an integrated network of gateways, access points and software that, once in place, would enable the refinery to quickly and easily add monitoring points to improve operations.

For this plant-wide network, Chevron would install wireless communications coverage at key locations across the refinery, using IEEE 802.11 Wi-Fi access point coverage that would integrate (or “backhaul”) smaller wireless field networks (Fig. 2).

Process measurement and control instruments would be added to the field networks and communicate using IEC 62591 (WirelessHART) technology.

The plant-wide network development began with a site assessment. As a first step, the automation supplier used satellite mapping to help envision where the Wi-Fi access points might best be mounted. Then Chevron and the automation supplier used the supplier’s kit of access points and communications equipment to test and measure locations around numerous tanks and facility units to complete the site assessment for the plant-wide Wi-Fi infrastructure. This process allowed determining the Wi-Fi equipment optimum location.

Using this information, Chevron and the supplier planned, engineered and specified the equipment to be installed. This was followed by factory acceptance testing to ensure that all devices in the plant-wide Wi-Fi network would communicate. Finally, site acceptance testing was conducted to ensure reliable facility-wide communications. The resulting plant-wide installation included 16 Wi-Fi access points providing wireless communications for 12 field device networks distributed across the refinery grounds.

Field devices communicate within their own networks using IEC 62591 (WirelessHART) technology. Added devices serve as range extenders where needed to help with difficult, more distant refinery areas. The access points in the Wi-Fi network connect, or backhaul, all of the field network data to the central process control facility and IT computers.

A broad range of field instruments would eventually be commissioned for applications such as pump and motor vibration monitoring, utilities monitoring, column temperature profiling, water flows, tank overfill protection and corrosion. It is easy to

SPECIALREPORT

optimally locate additional wireless field devices since further site assessments are not required. The time span from device installation to providing measurements is relatively quick. A graphical software package provides a clear network view for maintenance or network administration personnel, as well as for continuous online views for operators to verify data reliability passing through the network.

The plant’s IT department took plant-wide network ownership. IT best practices for wireless were established and internal security standards ensured. Security was easily achieved and managed by having only one connection between IT and process networks. This firewall safe zone connection enabled secure communication between networks.

Through the firewall safe zone (demilitarized zone—DMZ— in IT parlance), field data were sent up-network to an historian and asset optimization software for functions like machinery health management. The software enabled maintenance personnel to observe and manage equipment, such as reactors, using current and historic information in maintenance console displays. Condition monitoring and predictive maintenance information was sent down-network to process automation systems for use by operators. Data were also represented on operator screens for process operation.

A wireless governance team was established to evaluate and prioritize field network applications. The team included the corporate wireless technology leader and engineering, maintenance and operation representatives. The team tracks the wireless measurement application results that have been implemented and reviews proposals for new applications.

Results and lessons learned. Now that the infrastructure has been installed, requests for projects to add field measurements are frequently received from operating, reliability and engineering groups. The Wireless Governance Committee meets regularly to evaluate these proposals for wireless applicability. This is exactly what was expected from the infrastructure

FIG. 2

Field devices are often widely and remotely distributed throughout a plant. Wireless field data backhaul solutions integrate field instrument data with the process control system.

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project—the applications that have been stalled for many years due to cost or difficulty are now being easily implemented. The original estimate of millions of dollars in savings for electrical construction and associated engineering related to the wireless applications is being validated.

Although the original infrastructure project included only enough field measurement devices to allow verifying backhaul operation, the wireless device count is already growing and expansion continues.

The following wireless findings and practices were among those from the overall wireless investigation: • The IEC 62591 (WirelessHART) technology performs very well in the industrial environment.

• Small field network projects deliver high returns; wireless plant-wide infrastructures extend the benefit by enabling improvements to be added at will.

• Site assessments are the valuable starting point for locating access points and gateways in plant-wide Wi-Fi networks; additional site assessments are not required for optimally adding wireless field devices.

• Wireless support group roles and responsibilities need to be clearly defined (IT infrastructure, instrument technicians, process control, etc.).

• Engage IT security staff, wireless subject-matter experts and operations and engineering staff early in project design.

• Implement a cross-functional Wireless Governance team to prioritize and manage installing new wireless applications.

• Clearly define how wireless instrumentation will be used in your facilities (example: control vs. monitor).

38

I OCTOBER 2010 HYDROCARBON PROCESSING

• Use open standard communications: e.g., IEEE 802.11 (Wi-Fi) for plant-wide networks; IEC 62591 (WirelessHART) for field networks.

Future outlook. Following successful testing, laboratory validation and refinery installation, various Chevron operating businesses are developing their plans for wireless applications. The ability to economically add wireless measurements at will has been demonstrated. Additional projects are currently under investigation around the world in both upstream and downstream businesses. HP Greg LaFramboise has worked in instrumentation, automation and electrical for Chevron for 29 years. He has been involved in many automation project phases including project development, engineering and construction. Mr. LaFramboise has worked in several locations within the US and overseas, including a resident assignment in Indonesia. For the past five years, his position has been wireless technology lead, focusing on wireless sensor technologies.

Bob Karschnia, vice president of wireless for the Rosemount Measurement Division, has over 18 years of experience in the process control industry. He currently manages the Wireless Business Unit for Rosemount’s wide wireless product offering and coordinates wireless initiatives across all of Emerson Process Management. Prior to his current role, Mr. Karschnia held various design engineering and management roles throughout the company. Before joining Rosemount, he developed rotating equipment control systems at Compressor Controls Corp. and satellite control systems for Lockheed Martin. Mr. Karschnia also served as an officer in the United States Air Force, working on satellite control and communications systems.

He has a BS degree in aerospace engineering from the University of Minnesota and an MS degree in electrical engineering from the University of Colorado.

Select 161 at www.HydrocarbonProcessing.com/RS

PROCESS CONTROL AND INFORMATION SYSTEMS

SPECIALREPORT

Building and installing a reliable industrial Ethernet infrastructure Here are six practical guidelines to consider B. SHUMAN, Belden, Richmond, Indiana

W

ith industrial Ethernet becoming the preferred data communications infrastructure for mission-critical industrial automation and control, the challenge is to design a system made to withstand extreme and often hazardous environmental conditions.

Built on the same standards-based networking platform as enterprise Ethernet (Ethernet LAN standard IEEE 802.3), industrial Ethernet provides secure and seamless interoperability when connecting the plant to the central administration office and the Internet. As a result, more companies in the oil, gas and petroleumrelated industries are looking to leverage the capabilities of Ethernet communications across all their operations.

Perhaps no other industry group faces the type of harsh conditions that can threaten communication system component performance. Whether installed in an oil or natural gas exploration site, extraction operation, processing plant or refinery, the signal transmission must be tough enough to withstand the destructive effects of temperature extremes, moisture, humidity, dust, mud, oil, solvents and potentially corrosive chemicals. The network’s sensitive electronics may also be exposed to sunlight, electromagnetic interference (EMI) and the ever-present fire and explosion danger.

Here are six practical guidelines that oil, gas and petroleum plants should consider in planning, building and installing a data communications network rugged enough to stand up to the environmental rigors and hazards to which it is exposed.

network faults can be attributed to failure at the open systems interconnection (OSI) layer 1 (physical media), layer 2 (data link) and/ or layer 3 (network).

In mission-critical operations, downtime is not an option. If a switch, connector or cabling system should fail, the parts replacement and repair costs represent only a tiny fraction of the overall costs associated with downtime. The indirect Ethernet system failure costs include lost productivity, delayed processes, system shutdown and startup costs, possible lapses in security and safety, and the loss of service to customers relying on the plant’s mission-critical output. These indirect effects can send total downtime costs soaring to hundreds of thousands, even millions, of dollars.

Be sure to specify industrialgrade network components. In

Calculate real cost of downtime.

office settings, the Ethernet infrastructure is typically installed in a clean, quiet setting in which cables, hardware and connectivity components are fully protected.

Industrial facilities present a starkly different reality. Here, many network components reside in harsh environments, which even well-made commercial off-the-shelf (COTS) Ethernet systems cannot withstand. Sunlight, moisture, dirt and other contaminants can all degrade the cables’ physical integrity and electrical performance, resulting in intermittent outages or even total system shutdown. Only fieldproven, industrial-grade components offer the rugged construction and durability required to provide optimal performance over a long service life.

Analysts report that a large percentage of unplanned downtime in industrial operations can be attributed to network infrastructure failure. In fact, as many as 72% of

Choose standard-based cables and connectivity components to fit each application. Industrial-grade

cables that conform to the Ethernet LAN. IEEE 802.3 standard are made to resist the effects of sunlight, volatile temperatures, moisture and chemicals. They operate effectively in a wider temperature range (–40°C to +85°C) than commercial cables (0°C to +60°C).

Depending on the application within the plant, some industrial Ethernet products to look for include: • Heavy-duty, all-dielectric, indoor/outdoor-rated optical-fiber cabling in singleand multimode constructions. Many feature water-blocking agents for added protection in moisture-laden environments.

• Industrial-grade cat 5e and cat 6 cables with heavy-duty oil- and UV-resistant jackets. Some category cables feature a bonded-pair inner construction in which the pairs conductor insulation is affixed along their longitudinal axis to ensure consistent conductor concentricity to prevent any performance-robbing gaps between the conductor pairs during installation and use.

• Upjacketed and armored cables that add extra protection in more extreme environments.

• Continuous flex cables designed for use with continuous-motion machines and automation systems.

• Low-smoke zero-halogen (LSZH) cables and waterblocked and burial cables are also available.

• Cables designed for use with leading industrial automation networking and communications protocols, such as EtherNet/IP (ODVA), Modbus TCP/IP, ProfiNet and Fieldbus HSE. • Industrial-grade connectivity components, such as: IP67- or IP20-rated UTP or FTP patch cords, connectors, modular jacks and plug kits, adaptors, faceplates and surface-mount boxes.

HYDROCARBON PROCESSING OCTOBER 2010

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PROCESS CONTROL AND INFORMATION SYSTEMS

• Industrial-grade cat 5e RJ45 and micro (M12) cordsets and patch cords, including high-flex versions Select ruggedized switches, active network devices and accessories.

A wide range of hardware is available to enable managing industrial Ethernet networks at the information, control and device levels. There are products to support both copper- and optical-fiber media, as well as switches capable of data

speeds as high as 10 gigabits per second.

At a minimum, all of these components—switches, connectors and other hardware—should offer robust construction and resistance to high temperatures, vibration and EMI. Typical COTS hardware is designed to operate from 0°C to +40°C, while industrial-grade Ethernet hardware operates efficiently from 0°C to +60°C—extendable to –40°C to +85°C (a conformal coating is also available for humid/moist

applications). Also, excessive moisture and corrosive chemicals can inflict serious damage to the electronics in commercial switches, whereas ruggedized industrial switches are securely sealed to prevent ingress of these substances.

Industrial Ethernet hardware components include: • Hardened managed and unmanaged switches, which come in a variety of copper/fiber port configurations, port densities, industry approvals and mounting options.

• Firewalls to secure and isolate a network while still permitting authorized data communications to pass through. Firewalls with VPN capabilities also allow secure, encrypted communication from a remote location through the Internet.

• Wireless access points, clients and bridges in either DIN rail mount or IP67 enclosure-less housings now also support the faster, more secure and noise-immune 802.11n standard.

• Related accessories, such as hardened power supplies; SFP fiber transceivers; and even software that provides network status, alerts and control from the automation network’s software or PLC. Build in power source and data path redundancy. In selecting indus-

trial Ethernet switches, be sure to build in power source and data path redundancy.

Both are essential to maintaining uninterrupted signal transmission and uptime.

Power source redundancy requires switches with dual-power input capabilities so if one power source fails, the other takes over. Data path redundancy provides an alternate data transmission path should a link between switches fail, threatening system shutdown. A qualified network system designer can help in creating redundant power and data paths.

This bench top analyzer tops all others in its price range for features and performance. It’s equipped with an intuitive user interface, full-color touch screen and on-board Windows XP computer. Ethernet electronics that permit remote access for calibration, diagnostics or service support. Plus, the Phoenix II has a large sample compartment that accommodates spinners and special holders yet requires little or no sample preparation.

It all adds up to the lowest cost of ownership, backed by AMETEK’s reputation for reliability and world class customer support. Visit: ametekpi.com

Look for end-to-end integration.

Lastly, taking an end-to-end “total system” approach is the ideal way to ensure seamless interoperability and the longterm reliability oil, gas and petrochemical plants require in an industrial Ethernet network. HP

Brian Shuman, RCDD, is a senior product development engineer for Belden, a world leader in designing and manufacturing signal transmission solutions for industrial and enterprise networking. For more information and for an industrial Ethernet white paper, visit: www.beldenautomation.com.

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PROCESS CONTROL AND INFORMATION SYSTEMS

SPECIALREPORT

Increase your margin by 25% Here’s how to make sure that the planning LPs always match the plant A. BEERBAUM, Chevron, San Ramon, California; W. KORCHINSKI, Advanced Industrial Modeling Inc., Santa Barbara, California; and D. GEDDES, PREP Consulting Inc., Denver, Colorado

I

n today’s over-constrained work environment, planning model accuracy does not get the attention it deserves. In this article, we discuss order-of-magnitude LP (planning linear program) errors, what effect they have on margins and how to improve your LPs. Oil refiners and petrochemical plant operators plan and optimize their operations using LPs. Typical uses for planning LPs include crude oil/feedstock selection, production planning and monthly shutdown planning. Despite the fact that LPs have been in use for more than 40 years, and that major improvements have been made in their numerical techniques,1 it is difficult to keep them running accurately—mainly because of the complexity of the process facilities they are used to model.

Getting LPs accurate and keeping them that way is valuable.

A 2004 NPRA Annual Meeting paper presented by Solomon Associates documents the value of planning model accuracy (Table 1).2 Applying a midrange value of 0.50 $/bbl from Table 1 to a 300-thousand-bpd refinery results in a savings of over $50 million per year. This figure is large because in many cases involving crude oil selection and monthly plans, errors in the planning model lead directly to incorrect economic decisions.

Because of these large benefits, industry best practice is to continuously monitor plant yields, compare them to planning process model yields and update the planning process unit models when necessary. It is common for these updates to occur every three to four months. These frequent updates help leading refiners and petrochemical operators to squeeze more profit from their assets.

This article explores planning LP accuracy best practices. We will review the kinds of planning model errors found in practice, and how an inaccurate LP negatively impacts a company’s margin.

We will also look at how individual planners can keep their LPs running in top condition.

A note on LP model structure. Fig. 1 is an overview of a

simple refinery LP. Economics include the current pricing and volumes for available feedstocks and expected sales, operating costs and constraints and the definition of the overall refinery objective (e.g., maximum profit). Feedstocks include a set of yield and property assays for crudes and other feedstocks available for purchase by the refinery. Blend volumes and properties define sales, which reflect expected product demands.

Unit operations are the process unit models referred to previously, for example alkylation, visbreaker, fluid cat cracker and hydrocracker.

Some terms relating to LP modeling in common use include:

• Row and column vectors: Each vector includes numerical coefficients that model how changes in independent variables result in changes in dependent variables.

• Columns are usually independent variables (from an engineering modeling perspective).

• Rows are usually equations for material balances, product flows and properties or dependent variables.

• Base vector refers to a special kind of column vector. A base vector converts a measured feedrate into a set of product flows and properties.

• Shift (or delta) vector refers to a column vector that is used to modify product flows and properties to capture the effects of changes in operating conditions (e.g., feed quality, reactor severity).

LP accuracy or LP assurance (LPA) refers to an efficient methodology for keeping an LP model accurate. This means quickly TABLE 1. Value of LP accuracy Accuracy

$/bbl

Standalone

0.50–1.00

Different crude types

0.25–0.50

Similar crudes

0.10–0.25

Major shift in operations

0.50–1.00

Example refinery LP Economics, objectives, constraints Other Lt crude

Process 1

Hy crude Ext feeds Feedstock purchases FIG. 1

Process 2

Process 3

Process 5

Process 4

Process 6

Light

Medium

Heavy

Unit operations

Sales

Example refinery LP.3

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comparing the LP predictions to actual plant operation over time and quickly improving the predictions.

LP prediction errors. Refinery planning LP models approximate the steadystate behavior of actual operation. A refinery LP model contains many discrete modeling blocks (“unit models” or “submodels”), where each block represents a single process unit in the refinery. Examples of unit models are crude units, fluid catalytic crackers, hydrocrackers and so on. The LP’s unit models process crude the same way the process units in a refinery process crude.

When first built, planning LPs generally match the plant operation well. However, like everything else, LPs age, and as they do, their ability to match actual operation falls off. With time, unit model predictions deviate further from real operation. Eq. 1 defines LP error over time:

Percent error =

100 N

N

i =1

LP Predictioni Measurement i

Measurementi

(1)

Where: Percent error = Error between a predicted value and the plant (e.g., for gasoline) i = Sample number N = Number of samples over time period LP predictioni = LP unit model prediction at each point i in time (e.g., for gasoline in bpd) Measurementi = Measured value at each point i in time (e.g., for gasoline in bpd)

bpd

Gasoline

Measured Unimproved Improved Six months FIG. 2

LP prediction error (gasoline example).

LP prediction error defined. How do LP predictions look in practice? Fig. 2 shows an example for gasoline. The blue line is the measured gasoline flow over a six-month period. The red line is the prediction from the LP over the same period. The green line is the LP prediction from a well-tuned LP unit model (more about this later).

Fig. 3 shows similar results for propane. Two observations are important. First, the LP errors are quite large (red line compared to blue line). This means that the LP is not modeling plant behavior accurately. The consequence of inaccurate predictions like this is that the refinery will not be run optimally, which is very expensive. We discuss this in more detail later. Second, adjusting the coefficients improves the LP unit model enabling it match the plant very well (green line). The coefficient adjustment step requires care. For example, treating the coefficient-fitting problem as a statistical fit over a range of data, rather than at a single point enormously improves results.

Fig. 4 shows prediction errors for a number of familiar refinery streams. Each of the bars in Fig. 4 represents the error for a particular stream averaged over one year for a number of refineries.

The taller bars (labeled “Base LP”) are the average errors from the LP that was in use at the time the analysis was done. The shorter bars (labeled “Improved LP”) represent the relative improvements made after adjusting the LP coefficients. In many cases, the improved LP errors are half as large as the base errors.

Fig. 5 shows the minimum and maximum LP prediction error for each of the refinery streams. “Before” and “After” refer to the LP before and after it was improved. Neither the minimum nor the maximum errors are all from a single refinery; that is each refinery included some streams that had low LP prediction errors, as well as other streams that had high LP prediction errors. The maximum LP errors were dramatically smaller after the LPs were improved. In most cases, the minimum LP errors are also smaller after improving the LP. Fig. 6 summarizes the improvement in overall LP prediction made by adjusting the coefficients to match plant operation over one-year. For most streams, the improvement is between 40% and 50%.

To put this kind of improvement in perspective, Table 2 shows an example of what a 60% improvement means. The naphtha flow “before” improving the LP is 15,000. Since, this is half of the measured flow of 30,000 bpd, the “before” error is 50%. The naphtha flow “after” improving the LP is 24,000, which is now only a 20% error compared to the measured naphtha flow. The error reduction Average LP errors Base LP Improved LP

bpd

LPG

Measured Unimproved Improved Six months FIG. 3

42

LP prediction error (LPG example).

I OCTOBER 2010 HYDROCARBON PROCESSING

Offgas

FIG. 4

C3

C4

Average LP errors.

Naphtha

Light Heavy Bottoms distillate distillate

PROCESS CONTROL AND INFORMATION SYSTEMS

LPs drift over time. LP predictions drift over time for many

reasons (catalyst activity changes, process problems, lack of time or resources to tune LP submodels, lack of a good methodology for keeping LP submodels tuned and frequent staffing rotation between jobs). When this happens, some of the consequences include the refinery running against wrong constraints, spending too much on crudes, purchasing unnecessary and expensive external feedstock or blending components, making too much product (sell excess at a loss) or making too little of a product (buy at a premium).

A number of refiners use process simulators to update LP models.4 Either this is done on an as-needed basis or, in some cases, the simulators are linked to the LP models. One problem with this approach is that the process simulators require tuning to match current operations. Retuning these simulators usually requires a significant amount of detailed test-run data, which can be expensive and time-consuming to collect. Another problem with simulators is that maintaining the in-house expertise to run the simulators is difficult, given the frequent rotation of engineers through process engineering jobs.

LP solution vs. controller solution. What other problems

do inaccurate LPs cause?

Refiners run the LP each month to calculate the refinery optimal operation for that month. For example, the blue dotted line in Fig. 7 shows an illustration of an optimal FCC feedrate. Typically, planners divide the month into several periods to correspond to crude or product schedules (red dotted line). The small dotted line in the figure shows feed rates corresponding to these periods. Generally, the total scheduled feed for the month is close to the total optimal feed for the month (red and blue dotted lines are close).

Console operators at the FCC implement the scheduled FCC feedrate by entering a feedrate setpoint into a multivariable controller that is running the FCC on a minute-by-minute basis. Modern multivariable controllers run the process safely and economically.

Unfortunately, however, the objectives built into multivariable controllers can be quite different from the objectives built into the LP. When this happens, the plant will run at a different operating point from the one suggested by the LP or the schedule. The green solid line in the figure shows this. Many reasons for a controller to be running suboptimally (compared to the LP) include: Minimum and maximum LP errors Min. before Min. after Max before Max after

• LP models are not accurate relative to the plant • Controller’s bounds are different from the LP • Controller economics different from LP • LP constraints are out-of-date.

Planners and control engineers must always work together to understand when the plant is operating optimally, and when it is not. There is significant lost opportunity when the LP and controller solutions do not match.

How to keep your LP accurate. The previous discussion

shows how to identify LP errors, and how large they are in practice. What are the best practices?

Because refinery staffing is stretched so thin, it is critical to have in place a fast easy-to-use way to identify which parts of the LP are not accurate. After flagging large errors in a specific LP unit model, the planner must quickly correct the model’s coefficients.

TABLE 2. 50% improvement in LP prediction bpd

% error

Measured naphtha flow

30,000

LP before

15,000

50

LP after

24,000

20

Error reduction

60

Reduction in LP errors

60 50 Percent

is 60%, i.e., 50%–20%/50%. While the LP will never match the plant perfectly, significant improvements are possible.

SPECIALREPORT

40 30 20 10 0 Off-gas

FIG. 6

55,000

C3

C4

Naphtha Light Heavy Bottoms Overall distillate distillate

Reduction in LP errors.

FCC feedrate for one month

50,000

45,000

40,000 Monthly LP Weekly schedule Controller setpoint

35,000

Off-gas FIG. 5

C3

C4

Naphtha

Light Heavy Bottoms distillate distillate

Minimum and maximum LP errors.

30,000 1/3/2010 FIG. 7

1/10/2010

1/10/2010

1/24/2010

1/31/2010

LP, schedule, controller solutions.

HYDROCARBON PROCESSING OCTOBER 2010

I 43

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SPECIALREPORT

PROCESS CONTROL AND INFORMATION SYSTEMS

The workflow is: • Get unit model from LP into LP assurance tool.

• Collect plant data.

• Validate plant data.

• Measure LP unit model accuracy.

• Then, for unit models which have large errors: o Calculate new submodel coefficients. o Validate accuracy of new coefficients. o Get improved coefficients back into LP model. o Test new coefficients.

This entire process should only take a few minutes of a planner’s or process engineer’s time.

Historic refining margins. How do we translate the prob-

lems caused by LP errors into economic terms?

To get some perspective, let’s look at historic refining margins (Fig. 8). Refining margins represent the profitability for running a refinery—the more positive the number, the more profitable the refinery. Recognizing that each refinery in the world has its

Worldwide average refining margin

12

Monthly Averaged

10 8

$/bbl

6 4 2 0 -2 -4 Sep-94 FIG. 8

Jun-97

Dec-02

Sep-05

Jun-08

Worldwide refining margin.5

Assemble LP inputs

Buy crudes, feedstocks

Make blends

Financial accounting FIG. 9

Mar-00

Pricing, crude availability, demands ...

Production schedule

Finished products

Make monthly LP run (0.39 $/bbl)

Run process units

Ship and sell products

Refinery margin

From LP inputs to refining margin.

Monthly plan

Controller setpoints (0.12 $/bbl)

Revenue

own specific margin (based on geography, plant configuration and feedstocks), we will use the average margin shown in Fig. 8 to illustrate how a more accurate planning LP translates into an improved margin. Notice that recently refining margins have declined rather dramatically. In the economic analysis that follows, we will use a historically representative refining margin.

Improve LP, improve corporate margin. There are many ways to use planning LPs. Sometimes LP errors cancel out and do not affect refining margins. This can be the case in crude evaluation when a planner makes many LP runs and compares the results. Other times, however, LP model errors have a large impact on refining margins. This is the case when using the LP for production planning or crude optimization. Our focus is on this latter class of LP runs.

Fig. 9 illustrates how setting up and running a refinery production-planning LP ultimately affects the refinery margin. The two colored boxes in the diagram show a $, indicating significant impacts from an inaccurate LP. We will focus on these two steps since they are the ones that influence the refinery’s margin in the context of LP assurance.

We used typical LP errors (e.g., Figs. 4–6) to estimate the effect of an inaccurate FCC process unit model. To do this, we ran a typical refinery LP once with the “correct” FCC model and again with an “incorrect” FCC model. Table 3 shows the results. In the example, an incorrect planning model for the FCC leads to an error of $0.39/bbl in refining margin. Some key solution variables shown in Table 3 illustrate the effects of an inaccurate model on refinery volume balance.

Some or all of the $0.39/bbl error of the incorrect LP model propagates through the rest of the planning process (Fig. 9). So, for example, corporate traders may not purchase the right crudes, the operating schedule and operator targets will be incorrect, production targets may remain unmet and so on. This is where real money is spent and real margins are adversely impacted.

Console operators use the production schedule to guide the hour-by-hour operation of their process units. This means that the console operators enter setpoints and limits into multivariable controllers, which then run the plant on a minuteby-minute basis. If the multivariable controller constraints do not match the ones in the LP, the result is that the actual unit

TABLE 3. LP solution–incorrect FCC unit model Correct

Incorrect

Objective function ($/bbl)

Base

+0.39

Regular gasoline (Mbpd)

101.0

103.3

Premium gasoline (Mbpd)

25.3

25.8

Diesel (Mbpd)

50.2

54.9

Fuel oil (Mbpd)

12.7

5.2

TABLE 4. LP and plant controllers do not match Correct

Incorrect

Objective function ($/bbl)

Base

–0.12

Result 1

25.8

101.0

Result 2

54.9

25.3

5.3

50.4

103.3

14.4

Result 3 Etc.

46

I OCTOBER 2010 HYDROCARBON PROCESSING

PROCESS CONTROL AND INFORMATION SYSTEMS operation can be quite different from what the planners expect.

The differences usually do not become apparent, however, until days or weeks have passed and the actual inventories in the refinery do not match the expected ones. We have estimated the economic impact of mismatched multivariable/ planning LP constraints re-running the test LP with an improper set of FCC constraints. Table 4 shows the economic impact.

Referring again to the diagram in Fig. 9, errors between the plant and LP have accumulated, so that suboptimal amounts of finished products are shipped and sold, causing less revenue hits the refineryâ&#x20AC;&#x2122;s books than was planned. Combining the results of the two LP cases, an improved LP FCC unit model can generate up to 50 cents per barrel of margin on the business.

Increase your margin. In the low-margin environment of 2010, a 50-cent per barrel improvement can mean the difference between staying in or going out of businessâ&#x20AC;&#x201D;especially if a refinerâ&#x20AC;&#x2122;s margin is persistently negative. To put this in perspective, a 50-cent per barrel margin increase is 25% of a $2.00 refined products margin. HP

3

)R FR P ) U D Z DQD SUH 5(( ED O\ V OVW VLV VH RQ J G D Ă&#x20AC;OW R W LU HU R V F RP FD

2

LITERATURE CITED White, D., L. and Trierwiler, L. D., â&#x20AC;&#x153;Distributive Recursion at Socal,â&#x20AC;? ACM, Issue 28, pages: 22â&#x20AC;&#x201C;38, 1980, ISSN:0163-5786.

Gilbert, Peter, â&#x20AC;&#x153;Planning and Optimization Best Practices,â&#x20AC;? presented at NPRA Annual Meeting, March 21-23, 2004, Marriott Rivercenter Hotel, San Antonio, Texas Master, S. and W. Korchinski, â&#x20AC;&#x153;A Better Way To Keep Your LP Accurate,â&#x20AC;? presented at Haverly Systems 43rd Annual MUG Conference, San Antonio, Texas, September 13â&#x20AC;&#x201C;16, 2009.

ZZ

1

4

5

SPECIALREPORT

Tucker, M. A., â&#x20AC;&#x153;LP Modeling-Past, Present and Future,â&#x20AC;? presented at NPRA Computer Conference, October 1â&#x20AC;&#x201C;3, 2001, Adams Mark Hotel, Dallas, Texas.

Oil Market Report, â&#x20AC;&#x153;Historical Monthly Refining Margins (New Methodology),â&#x20AC;? International Energy Agency Web site http://omrpublic.iea. org/refinerysp.asp.

Al Beerbaum has worked at Chevron for 30 years. During this time, he has held numerous positions within the areas of refinery planning, process control and optimization. Mr. Beerbaum has worked at a number of refining sites within Chevron, most recently in Global Refining where he has developed new approaches to real-time optimization. Al attended the University of California, Berkeley, where he obtained his MS in mechanical engineering.

Bill Korchinski is president of Advanced Industrial Modeling (AIM) Inc., which provides innovative technology and services to the oil refining, petrochemical and chemical industries. AIMâ&#x20AC;&#x2122;s main goal is to increase customer profitability and efficiency by applying solutions in the areas of LP planning, multivariable control and optimization. Prior to starting AIM, he worked for both operating and consulting companies, and has worked throughout of the world. Mr. Korchinski holds a B Sc. degree in chemical engineering from Queenâ&#x20AC;&#x2122;s University, and an M Eng. degree in chemical engineering McGill University.

Dave Geddes is president of PREP Consulting, Inc. He is involved with training and consulting in petroleum refining economics. Mr. Geddesâ&#x20AC;&#x2122; experience is in the areas of refinery planning, economic studies and training. He holds a BS degree in petroleum refining from the Colorado School of Mines, and an MS in chemical engineering from the University of Colorado.

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HYDROCARBON PROCESSING OCTOBER 2010

I 47

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CREATIVE SOLUTIONS FOR OUR ENVIRONMENT

PROCESS CONTROL AND INFORMATION SYSTEMS

SPECIALREPORT

Advanced process control in the plant engineering and construction phases Testing MVC performance using a dynamic model offers several benefits V. SAKIZLIS, Bechtel, London, UK; K. VAKAMUDI, Bechtel Corp., Houston, Texas; A. COWARD and I. MERMANS, Honeywell Process Solutions, Southampton, UK

T

he profit in process industries is a function of effective plant operation. This energy and economic-based incentive leads to developing advanced operation and control strategies.1,2 Advanced process control (APC) success in the oil and gas industry, in particular, over the past 30 years is widely acknowledged. Successful applications have been reported in olefins plants,3 refineries4,5 and gas plants.6 Payback times of a few months have been achieved, in addition to improved economics by 5–10%. Success of these projects is attributed to increased profit margin and reduced energy consumption. The main research and development trends in that field focus on centralized coordinated plant-wide control solutions,7 nonlinear models8 and multivariable optimizing solutions that can be incorporated in PLC or DCS hardware.9 Predominately, however, APC is developed, installed and commissioned after the plant startup. Dynamic simulation expedites the step-testing and plant model development; however, the system set-up is still held until at least after the plant commissioning.

This conventional strategy (Fig. 1) inadvertently introduces a delay in the APC implementation and consequently postpones relevant benefit capitalization.

In the novel work presented here, we have minimized this delay by designing APC at the early process design and engineering stages. The work concerns designing, testing and installing APC—also termed multivariable control (MVC)—as the engineering and construction part of an approximately 1,300-MMscfd gas plant in the Middle East.

The MVC scope of work in the engineering procurement and construction phase included: • MVC hardware and software supply, installation and integration • Developing a dynamic simulation model for testing the MVC performance • DCS-OPC interface communication supply and configuration. This interface comprises software, hardware and the necessary graphics and logics.

The contractor managed, supervised and provided information to the supplier that developed and delivered the MVC. Definitions:

• Dynamic simulation model: Nonlinear process plant model based on first principles and built on commercial software • Linear dynamic model: Model derived from plant excitation data. The model can be finite-time impulse responses,

transfer functions, state space or an AutoRegressive eXogeneous model (ARX). This model is in general used to derive an MVC solution for the plant.

• MVC refers to control algorithms that simultaneously compute the optimal value of a manipulated variables set based on a selected set of current plant measurements. The computation is the online solution of an optimization problem consisting of: º An economic or tracking objective function º The system linear dynamic model º Performance and operational constraints.

For more information on MVC, also called APC or model predictive control (MPC), refer to Qin and Badgwell.1 Process description. This gas plant facility includes process units for gas and condensate separation, condensate stabilization, gas treating, gas dehydration, NGL recovery and residue gas injection. The simplified plant flowsheet is shown in Fig. 2. The main products from the plant are outlined in Table 1.

The MVC scope concerned the three main separation units that are directly linked with the plant production: the condensate stabilizer and the feed liquid separation unit that remove the heavy components from the gas stream and the NGL recovery system that includes a demethanizer distillation column.

Plant design/ engineering

Option: Dynamic model

Plant commissioning

Dynamic model development

MVC design t %FUFSNJOF DPOUSPM TUSVDUVSF t .PEFM JEFOUJmDBUJPO t $POUSPMMFS QSFUVOJOH

Testing on the model

MVC commissioning t $PNNVOJDBUJPO XJUI %$4 t $POUSPMMFS UVOJOH t 0QFSBUPST USBJOJOH FIG. 1

Conventional multivariable control approach.

HYDROCARBON PROCESSING OCTOBER 2010

I 49

SPECIALREPORT

PROCESS CONTROL AND INFORMATION SYSTEMS

The unit that provides most of the plant production and the one that benefits the most from applying MVC optimization is the NGL recovery system. Fig. 3 is a simplified NGL recovery system process flow diagram that omits the details that are not relevant to MVC. The NGL recovery unit efficiently recovers the ethane from the dehydrated gas while maintaining 99+% propane and heavier component recovery for the wide range of ethane recoveries.14 The resulting residue gas is routed to the residue gas manifold for reinjection after being recompressed by two compressors in series that control the unit pressure.

The NGL recovery process includes a multistage propane refrigeration circuit to provide the additional cooling duty required to meet the product specifications.

MVC objectives and control scheme. Here, we describe the control structure formulation for the NGL unit. The same approach was used in the rest of the relevant units.

The prime MVC objectives were to: • Minimize the C3+ overhead product composition and the C3 recovery in the bottoms product • Minimize the C2+ concentration in the NGL stream during C2 recovery and the reverse during C2 rejection • Maximize plant production rate • Minimize plant energy usage.

At the same time, operational constraints should not be exceeded.

For example, the C1/C2 ratio in the bottoms product should be maintained below a designated setpoint, while the pressure in the overhead gas stream should not deviate from its given value.

To satisfy the aforementioned constraints and objectives the contractor compiled the set of manipulated and control variables that constitute the MVC structure. The main selection criteria were: • The manipulated variables (MVs) should have a large impact on the process objectives and constraints. Additionally, the effect of the MVs on the process objectives should ideally be immediate without large delays. For example, reducing the feed temperature to the demethanizer at constant pressure leads to a reduction in the column temperature—thus increasing the liquid ethane recovery.

Gas reinjection or sale

NGL product

NGL recovery

Feed gas separation and condensate stabilization

Gas treating

Condensate product

FIG. 2

Dehydration and feed liquid separation

Condensate or NGL product

Gas plant flowsheet.

Multivariable control MVs FFIC

FFIC FT

PI

PIC

HIC FC

PT

SC

FT

PIC

SC TIC FT LIC

HS

TIC HS

FC

FIC

FC

FT

FT

LC

PIC

PT

FT

TIC FT

FC

PDI TIC

FIC

LIC

AIC FT

FIG. 3

50

NGL recovery flowsheet and representation of MVC manipulated variables.

I OCTOBER 2010 HYDROCARBON PROCESSING

PROCESS CONTROL AND INFORMATION SYSTEMS

Dynamic model. A dynamic plant model was under construc-

No. Product

Plant unit

1

Condensates, C5+

Condensate stabilizer bottoms and liquid separation bottoms

2

Natural gas liquids (NGL), mostly C3 and C2

NGL recovery unit and liquid separation bottoms

3

Sweet natural gas, C1 and C2

NGL recovery overhead

FIR/PEM/CLid step responses CV1–C1C2 ratio 0 112 0 -112 -224

ARCA Flow Group worldwide: Competence in valves, pumps & cryogenics

-134 -268 -402 -535

0

FIG. 4

30

60

90

120

0

30

60

90

120

C2/C2 ratio response to demethanizer feed temperature.

Stainless Steel Valves

Tank Level Instruments

Visual Level Indicators

tion by the contractor to conduct design studies and to serve as a platform for the operator training plant simulator (OTS). Developing the model was a joint effort by the contractor’s advanced simulation group and gas plant project process discipline. This model is a detailed representation of the plant steady-state and dynamic behavior. For instance, it accounted for hydraulics,

TABLE 1. Gas plant products

MV2–reboiler

MVC Controller configuration and testing. Because the “real” process for this project did not exist at the time of the MVC project, the developed MVC application testing could be handled in one of two ways: • Testing against a “perfect” inverted linear dynamic model • Testing of the MVC controller against the control loops and the process model within a dynamic simulation model.

To demonstrate how the MVC controller would act with unmeasured and process disturbances, the latter option was chosen.

compressor performance curves and modeling of the dominant stream components. The NGL portion was extracted from the plant model, and after a set of modifications, it was handed over to the control system supplier. The main modifications were: • The unit boundaries were modeled as constant pressure points. These are the feed to the unit, the residue gas to the reinjection compressors and the NGL product.

MV1–chiller

• The controlled variables (CVs) had to be directly linked to the process objectives and constraints. For example, the column overhead pressure is a constraint and, therefore, it was included in the structure.

• The number of MVs and CVs should be kept relatively low to avoid complexities during tuning and commissioning and to prevent negative effects on the NGL or other parts of the plant.

For example, the NGL inlet pressure was not used in the structure since it may adversely affect the downstream units.

The contractor awareness here on the plant operation and design was paramount in determining the control structure.

SPECIALREPORT

WEKA AG · Switzerland Schürlistrasse 8 · CH-8344 Bäretswil Phone +41 43 833 43 43 Fax +41 43 833 43 29 info@weka-ag.ch · www.weka-ag.ch Armaturen AG von Rohr

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HYDROCARBON PROCESSING OCTOBER 2010

I 51

SPECIALREPORT

PROCESS CONTROL AND INFORMATION SYSTEMS

• The two ratio controllers were configured. These were the side stream over the feed flow ratio and the bypass to the turboexpander over the feed flow ratio.

• The level and column bottoms temperature controller settings were revisited.

Step-testing for MVC controller. Any linear multivariable

controller requires dynamic response models of the process it is controlling. These responses are normally obtained by perturbing MVs, i.e., introducing step changes in the control loop setpoint (hence step-testing). This activity requires that the process move close to limits and quality constraints and it also requires that all other process disturbances are minimized. This limits the operator in his or her normal role and introduces the risk of going off specification or facing an abnormal situation.

By developing a dynamic response matrix from the dynamic simulation, the response models are obtained in a risk-free environment. The time to develop the models is also reduced.

The step-testing activities alone on a demethanizer would normally take at least a week—even using efficiency tools, featuring closed-loop step-testing with online model identification— because of the time to the fractionation column takes to reach a steady state after a process move. Utilizing automated dynamic simulation meant that a step-test sequence could be configured once and then left to run, with the simulation set to run as fast as possible. This meant that the dynamic model starting from a steady state could be saved and run as required, depending on the results. Because the process is a simulation, variables that cannot normally be fixed (such as ambient temperature) could

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also be held constant to improve the overall model quality.

If base control loops needed retuning, they could be adjusted and then the step-testing sequence run again overnight to provide data for analysis in the morning. On the live process, this activity would require retesting the process, with delays for the project, additional cost and potentially additional risk for the customer.

Results from the simulation model were extremely encouraging and compared favorably in terms of gains and dynamics to models obtained from a similar unit in another project, which had been step-tested using conventional methods. This demethanizer, located in the Middle East, used the same licensor design and provided a good reference for model gains and dynamics. Examples of the responses obtained from simulation are shown in Fig. 4.

Fig. 4 indicates that if the demethanizer feed temperature is increased (gets less cold), then the methane-to-ethane ratio in the demethanizer bottoms would increase. This agrees with expectations—less “cold” entering the system with constant reboil would recover less ethane. Similarly, increasing the reboil would decrease the ratio because more methane would be driven up the column.

As can be seen, the responses are very clean, with no disturbances and very self-similar models for different settling times.

The main benefits from the testing activities via a dynamic simulation model are: • The linear model derived from the dynamic simulation can potentially be used for commissioning the real plant MVC. • Generating the dynamic model, and subsequently the realistic linear model, enabled testing the MVC graphics and databases.

• The models provided insight into the correlations between the MVs and CVs that can be essential during commissioning and tuning the real plant MVC. MVC controller configuration and performance evaluation. Once the linear dynamic model was derived, the

MVC controller configuration was completed in the MVC design package where the objective function weights and constraints are set. This activity allowed installing the MVC controller on the real MVC hardware and generating the MVC graphics, database and the MVC-DCS interface.

95 93 91 89 87 85 83 81 79 77 75

C2 recovery With MVC

Time C1/C2 ratio

C1/C2 ratio

2.4

Automatic Calibration

Without MVC

Fast & Easy Maintenance Automatic Lubrication

C2 recovery

1.6

NEW!

With MVC 0.8 0

FIG. 5 Select 164 at www.HydrocarbonProcessing.com/RS 52

Time

C1/C2 ratio and C2 recovery trends with and without MVC.

PROCESS CONTROL AND INFORMATION SYSTEMS The MVC controller was integrated with the dynamic model to evaluate the controller performance. The dynamic simulation software contains an option where MVC can be added to the process–MVC controller is one of those options and can be added and then connected to relevant points across the process.

In this case, the MVC controller application was configured to link to the setpoint of all the base control loops.

Controlled variables are also connected to the MVC controller from different points in the process. Where specific instruments were going to be connected to the MVC controller, the stream properties (temperature, pressure or flow) at the location closest to where the instrument would be situated were used, converted to the appropriate units to be used at site. Where a property or composition was used, the particular component or stream composition was used as the source value.

Utilizing the dynamic model meant that where qualities or compositions were required, preliminary inferential models could also be identified. For example, the online application would require the methane and ethane concentrations in the demethanizer bottoms stream to be inferred by online calculations. Using information from the dynamic simulation, preliminary inferential models were developed and then tested over the expected operational range. The actual inferential models will be validated against the laboratory results once the process is commissioned. Subsequently, the inferential model will be adjusted accordingly if necessary.

MVC simulated cost benefits. During the ethane recovery mode, the MVC application objective on the demethanizer column was to maximize the ethane and heavier component recovery from the methane stream and, therefore, the methodology used was to compare the ethane recovery data both before and after MVC implementation.

The simulations were started and allowed to stabilize; the data for key parameters were collected then forming the base case for the pre-MVC scenario. The MVC controller was then switched on and data was collected with the MVC controller controlling the process—this data then formed the post-MVC case. Comparing these two cases’ data provided the expected MVC benefits on the demethanizer column.

During a conventional project, this methodology would be very conservative, since improvements in base-level control loop design and tuning would also contribute to the overall project benefits. However, in this case, the approach served to highlight the benefits.

Fig. 5 shows trends of the process data as the MVC was commissioned on the virtual dynamic model-based plant.

From the data extracted from dynamic simulation, the MVC controller benefits on the demethanizer are expected to be approximately a 1.37% increase in the ethane recovery. This could translate to $5–6 million per year savings based on the current NGL and natural gas prices.

Additional benefits are anticipated if the MVC controller is allowed to change the NGL unit upstream pressure that consequently controls the feed flow to the unit. However, this variable is currently excluded since it may cause instabilities in upstream units. During the actual commissioning activities, the decision to utilize this variable will be re-examined to potentially increase the MVC benefits.

DCS–MVC interface. The MVC implementation was designed as follows:

SPECIALREPORT

• The MVC execution software was installed on the MVC server.

• The MVC user interface was installed on the MVC workstation to allow monitoring and tuning capabilities.

• The MVC server is connected to the DCS via OPC. Redundant links between the MVC server and the DCS OPC servers were used to enhance the system’s reliability. Fig. 6 illustrates the architecture.

The expected operation is: • MVC server will receive a set of measurements through the plant DCS. • MVC will perform calculations to compute the optimal control actions.

• The computed control action will be fed back to DCS controllers in the form of regulatory controller setpoints.

• The MVC workstation user interface permits the MVC engineer to change the underlying MVC model or even add/ remove controllers on the plant units.

The DCS had to be configured accordingly to enable the appropriate communication between the two systems. The DCS modifications and the reasons behind them are listed here: DCS graphics. Although full MVC operation can be performed from the MVC viewer workstation, the DCS human machine interfaces should still allow the operator to adjust online a selected set of the MVC settings. For example, the operator should be allowed to enable and disable the MVC control or manipulated variables. Hence, the DCS vendor developed graphics as per the contractor and MVC supplier instructions. The graphics were integrated with the DCS with appropriate links to the process graphics, while they bear resemblance to the MVC viewer graphics.

This is a feature that can only be materialized at the early construction phase, where there is sufficient time to review the graphics and ensure consistency and compliance with the project philosophy.

DCS logic. The controllers admitting MVC setpoints had to be configured accordingly to allow automated switching from the MVC to the DCS operation modes. Additionally, a portion of logic was implemented to fall—back the relevant DCS controllers to a safe operation mode for the following cases: • Lack of communication between MVC and DCS • Manual selection to switch MVC off.

DCS watchdog. The watchdog timer monitors the MVC controller application and DCS-MVC communication health.

Switch 310-PLS-500

Switch 310-PLS-510

Time server MVC server EXAOPC 310-GPS-601 310-GPS-001 310-DW-140

Workstation Printer 310-PW-002 310-MCP-500

V-net

FIG. 6

MVC hardware architecture and connections with DCS.

HYDROCARBON PROCESSING OCTOBER 2010

I 53

SPECIALREPORT

PROCESS CONTROL AND INFORMATION SYSTEMS

When either the MVC-DCS communication fails or one of the MVC controller applications degrades, the watchdog alerts the operator and ensures a safe and seamless fallback from the MVC to the DCS operating mode. Traditionally, the watchdog logic resides in the DCS and one watchdog is implemented per MVC controller application. Here, there was a limitation on the DCS loading that restricted installing the watchdog on the DCS. Thus, a new approach was developed that transferred a portion of the MVC logic to the MVC server.

MVC server side. The MVC server part of the watchdog is implemented as a custom-made application. This application receives a watchdog reset signal from each MVC controller application it is monitoring. If it does not receive a reset signal in a configurable time period from one of the MVC controller applications, then the pertinent MVC controller application has been degraded or corrupted. Hence, it sends the corresponding shed signal to the DCS. The reset signal is a value that is incremented ProďŹ t controller application 1

ProďŹ t controller application n

Watchdog reset signal

Watchdog reset signal

t t t

MVC testingâ&#x20AC;&#x201D;DCS integration. When any APC applica-

Watchdog reset signal

n shed signal

1 shed signal

Watchdog application

t t t

MVC server DCS

FIG. 7

t t t

n MVm mode

t t t

n MV1 mode

1 MV1 mode

1 MV1 mode

Watchdog application

t t t

DCS and MVC watchdog implementation.

Plant design/engineering phase .7$ EFTJHO t %FUFSNJOF DPOUSPM TUSVDUVSF

Dynamic model development

.7$ DPNNJTTJPOJOH activities t $PNNVOJDBUJPO XJUI %$4 t 0QFSBUPS USBJOJOH

.7$ UFTUJOH t .PEFM JEFOUJmDBUJPO t $POUSPMMFS QSFUVOJOH t .7$ CFOFmUT

Plant commissioning

Post plant commissioning t .7$ TUFQ UFTUJOHoNPEFM WBMJEBUJPO t .7$ DPOUSPMMFS UVOJOHoGVSUIFS .7$ USBJOJOH FIG. 8

54

Advanced control prior to commissioning. Note in red the MVC elements in the engineering phase.

I OCTOBER 2010 HYDROCARBON PROCESSING

every time the MVC controller engine executes. This value is always incremented, even if the controller is not online.

DCS server side. The DCS part of the application performs two tasks: â&#x20AC;˘ It monitors the communications link health between the MVC server and the DCS. To do so, it receives a watchdog reset signal from the MVC server side of the application. If it has not received the reset signal after a configurable time, it switches all the DCS base-level controllers that are used by all the MVC controller applications back to their fallback DCS mode. The reset signal is incremented every time the watchdog application executes. â&#x20AC;˘ It monitors the MVC controller individual application health. When it receives a shed signal from the MVC server side for one application, it switches the DCS base-level controllers used by that MVC controller application back to their fallback mode.

This configuration (Fig. 7) maintains the DCS watchdog logic to a minimum and thus gives priority to the critical DCS tasks. This is desirable from operational and maintenance points of view. Note that this implementation reduces the DCS watchdog loading by â&#x2030;&#x2C6; 80%. tion is implemented onto a DCS, the entire system must always be fully tested to ensure that communication paths and DCS displays are correctly configured. Limits and values that are entered into schematics by the operator reside in the DCS and these values are then read up to the supervisory computer. Each schematic entry point is checked to ensure that the value is being stored in the correct location and then read correctly into the correct location within the MVC application.

Fallback strategies need testing where situations such as network disruptions and power or system failures are simulated.

In each case, on a live system, there is risk of interrupting the process because mode changes and alarms are being triggered on the system controlling the process.

Utilizing the dynamic model to develop the MVC controller application allowed testing the integration to be performed in complete safety in the factory and at site prior to plant startup. All schemes, fallback logic, control loop mode shedding and schematics were fully tested using the developed MVC controller and the system architecture that would be in place onsite. All Ethernet switches, cables, computers and implementation specifics were tested to ensure that they performed as expected. This significantly reduces the risk onsite, but more importantly will reduce delays to the project once the process equipment is commissioned.

MVC training. Operator training is a fundamental part of any MVC project, since without the operatorâ&#x20AC;&#x2122;s understanding and acceptance, MVC will not be used. The best MVC application, if not accepted by the operator, will never remain turned on.

Utilizing MVC technology is normally a change from the operator workflow. Because brownfield sites have been in operation for some time, operators have been trained on how to run the unit and have developed their own way of â&#x20AC;&#x153;drivingâ&#x20AC;? the process. Between different shifts, significantly different process performance can be observed when historical data are reviewed.

Trying to change this behavior is time-consuming and sometimes problematic.

Training the operators in the MVC technology, and how to use it from the outset, means that the MVC operation becomes

PROCESS CONTROL AND INFORMATION SYSTEMS an integral part of their workflow. Standardizing the operational methodology from commissioning onward also means that the operators achieve the best possible performance all the time.

Because the MVC controller applications were configured at an early stage, all the operators were trained on what the technology would look like, what the objectives would be, what the schematics would look like and how they would control the process using MVC technology. Their work flow was then defined including using the MVC controller.

Conclusions. APC has realized substantial economical benefits

to operating companies. However, its conventional implementation postpones its installation and testing until after plant commissioning. In this work (outlined in Fig. 10), the MVC project was started long before the process construction is completed.

Hence, the long lead time items have been completed before the process commissioning starts: • NGL unit MVC application design and requirements are well understood and so can be accomplished with a high degree of accuracy at an early stage. In that respect, the engineering firm that designs and builds the plant uses its experience with plant design and operation to ascertain the MVC control structure.

• Control loop interactions and strategies are tested and proven ahead of time, reducing the process commissioning time.

• Risky and time-consuming activities such as the plant production unit step testing (NGL unit, etc.) and DCS interfacing and testing are all performed in a zero-risk environment or prior to plant startup before the system is taken to site.

• Operators are trained and expect the MVC applications as a

SPECIALREPORT

part of their fundamental workflow, rather than having to adapt to using the technology at a later stage.

The MVC design, installation, testing and commissioning at site would normally last six to nine months. This new approach of transferring a portion of these activities to the engineering phase reduces the site engagement to: • Stabilizer and liquid separation unit step-testing and commissioning • Validating the process response model for the NGL unit • MVC controller performance tuning and monitoring.

Hence, duration of these activities can potentially be reduced to around one month. This approach significantly accelerates the benefit delivery and enables an earlier improvement in process operation. It thereby leads to an early MVC project investment payback.

This work was executed using proprietary MVC software. The findings of this work, however, can be potentially applied by any reputable MVC supplier using any commercially available MVC software with the following minimum requirements: • Software should implement the standard industrial MVC functionality described in API 557 (2000).

• Software should allow the user and the designer to implement custom-made functions and diagnostics. HP ACKNOWLEDGMENTS The authors thank Dave Parry and Prasad Sethuraman (currently with BP, UK) from the Bechtel Process group and Ram Tekumalla from the Bechtel Advanced Simulation group for their support regarding the dynamic model and the plant control structure. The contribution of the DCS engineers Andrew Lawrance and

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HYDROCARBON PROCESSING OCTOBER 2010

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SPECIALREPORT

PROCESS CONTROL AND INFORMATION SYSTEMS

John Capstack toward the DCS-MVC integration is gratefully acknowledged as is the assistance from the Yokogawa subsystem’s lead Paul Lim. LITERATURE CITED Qin, S. A. and T. A. Badgwell, “A survey of industrial model predictive control technology,” (2003), Control Engineering Practice, Vol. 11, pp. 733–764 2 Christofides, P. D., J. F. Davis, N. H. El Farra, D. Clark, K. R. D. Harris, and J. N. Gipson, “Smart Plant Operations: Vision Progress and Challenges,” (2007), AIChE Journal, Vol. 53, No. 11, p. 2734 – 2741.

3 Shindo, H., K. Lau, R. Kaneko and J. S. Ayala, “Furnace optimizer in Naphtha Cracker,” (2004), AICHE 16th Annual Ethylene Producers’ Conference.

4 Moro, L. F. L. and D. Odloak, “Constrained Multivariable Control of Fluid Catalytic Cracking Converters,”(1995), Journal of Process Control, 5, No. 1, 29.

5 Haseloff, V., Y. Z. Friedman and S. G. Goodhart, “Implementing coker advanced process control,” (2007), Hydrocarbon Processing, Vol. 86, (6), pp. 99–103.

6 Hotblack, C., “Connoisseur Advanced Process Control of Condensate Stabilisation Process,”(2004), Automation and Computing, pp. 20–21.

8 Kumar, A. and P. Daoutidis, “Nonlinear dynamics and control of process systems with recycles,” Journal of Process Control, 12 (2002), 474–484.

9 Dua P., K. Kouramas, V. Dua, E. N. Pistikopoulos, “MPC on a chip— Recent advances on the application of multi-parametric model-based control,” Computers and Chemical Engineering, (2008), Vol 32, pp.

754–765.

10 API Recommended Practice, 557, Guide to Advanced Control Systems, (2000), First Edition.

11 Cheng R., J. F. Forbes and W. S. Yip, “Price-driven coordination method for solving plant-wide MPC problems,” Journal of Process Control, 17 (2007), 479–438.

12 Honeywell Success Story, “ONGC Improves Process Performance with Profit Controller and Profit Sensor Pro,” (2005), Honeywell Process Solutions.

13 Tookey, B., U. Rejek, S. Park, S. Goodhard and S. Finlayson, “Universal Process Identification Revamps FCCU APC,” (2003), Plant Automation and Decision Support Conference.

14 Cuellar, K. T., J. D. Wilkinson, J. T. Lynch and H. M. Hudson, “Hydrocarbon gas processing,” 2005, UOP/Ortloss U.S. Patent 7191617.

1

Vassilis Sakizlis is a senior advanced process control engineer for Bechtel London since 2005. His professional experience includes advanced process control, online optimization, dynamic simulation, real-time information, distributed control systems, emergency shut-down systems, instrumentation and relief system design. He has worked on Front-end engineering design and engineering procurement construction projects for gas processing plants, refineries and air-separation units. Dr. Sakizlis has been the coauthor for the European patent entitled “Improved Process Control” that demonstrates implementing explicit advanced control in a PLC/DCS level. He graduated with a PhD in 2003 from Imperial College, London and with a diploma in chemical engineering from Aristotelis University in Thessaloniki, Greece.

Andy Coward is a solutions consultant for Honeywell Process Solutions and is based in Southampton, UK. He is responsible for advanced control and optimization solution sales across Europe, the Middle East and Africa. Mr. Coward has been with Honeywell since 1996, first implementing advanced control projects then working in a consulting role. Before working for Honeywell, he spent six years working for ExxonMobil as a process engineer. Mr. Coward has a chemical engineering degree from the University of Newcastle Upon Tyne in England.

Kumar Vakamudi is a project manager in the oil and gas and chemicals business unit of Bechtel Corporation. He has a BS degree in mechanical engineering from India. Mr. Vakamudi has earned an MS degree in biomedical engineering and also completed academic requirements for a doctoral degree in bioengineering from Texas A&M University. A registered professional engineer in Texas, he is a senior member of the International Society of Automation. Mr. Vakamudi has a total of 28 years’ experience in the medical, aerospace, oil and gas, power and telecommunications industries.

Ivan Mermans is a consultant for Honeywell Process Solutions and is based in Southampton, UK. He is responsible for the development of interfaces between Honeywell APC software and third-party DCSs. Mr. Mermans has been with Honeywell since 1996. Before working for Honeywell, he spent nine years working for Fina Refinery Antwerp (now Total), Belgium. Mr. Mermans has a chemical engineering degree.

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In this webcast, Dan Kernan of ITT Industrial Process will share best-practice advice to help attendees improve the effectiveness of the pumps they use in oil and gas processing.

• Operational do’s and don’ts for using pumps properly in refining applications • An overview of condition monitoring options to improve safety and reduce maintenance costs • Case studies that illustrate the real-world impact of different approaches to pump operation and monitoring This webcast will provide practical advice for anyone who oversees the use of pumps–including refinery managers, maintenance/reliability engineers and production supervisors.

Presenter: Dan Kernan, Manager–Monitoring and Control Group, ITT

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I OCTOBER 2010 HYDROCARBON PROCESSING

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PROCESS DEVELOPMENTS

Mitigate fouling in ebullated-bed hydrocrackers New monitoring tools help track and control asphaltene levels and solubility issues in resid products J. KUNNAS, Neste Oil, Porvoo, Finland; O. OVASKAINEN, Baker Hughes, Finland; and M. RESPINI, Baker Hughes, Italy

Conversion vs. fouling. Conversion reaction rates (thermal cracking), leading to fouling by asphaltenes decomposition, increase more rapidly with rising temperatures compared to the hydrogen-saturation reactions that inhibit sediments formation.6 Accordingly, increasing temperature and conversion above certain limits and beyond the optimal operational window will lead to uncontrolled sediments and coke generation. These generated foulants will deposit in critical plant sections or will cause problems regarding sediments specification for heavy fuel oil (Fig. 1).

However, operating below the optimal operational window creates no major advantages, and decreasing severity will not impact fouling rates significantly. Such actions will only result in lost conversion with no major advantages in terms of sediments deposition control and run lengths.

Most exposed to fouling. The sections most exposed to

heat exchangers, as shown in Fig. 2. At very high conversion, the reactor and separator may also suffer from high coke generation.

Due to extensive fouling, the separators and columns can lead to unplanned shutdowns, downtime and lost production.

The same increasing trends can be seen for sediments generation in fuel oil products, depending on the ebullated-bed hydrocracker severity. Below certain conversion limits, fuel oil will be stable.

While above the optimum operating window, the tendency to generate sediments over time is very high during fuel oil storing requirements. Consequently, it’s clear that setting the appropriate operating conditions are important. It allows the best tradeoff between maximizing conversion and producing stable fuel oil in relation to acceptable fouling control.

Parameters that define severity. The optimal severity

depends on the feed processed, unit operating conditions and catalyst properties. The ebullated-bed hydrocracker feed will change whenever the refinery feed quality, residual feed makeup or the plant feed rate is changed.3,5 Therefore, optimal plant management requires continuous control of the feed along with resid products stability. Several feed composition-related factors do influence ebullated-bed unit severity and conversion, such as: • Stability reserve of asphaltenes in the vacuum resid (also known as the p-value) • Asphaltene content • Solubility of the asphaltenes.

Conversion loss

Fouling increases

T

he global supply of high-quality crude is decreasing and, at the same time, the requirement for clean sulfur-free products is increasing. During the last decade, ebullated-bed residue hydrocracking has gained increasing interest due to its capability to produce high-quality, light and middle distillates in an economically effective way from heavy residuum oils.1 Major economical drivers for ebullated-bed hydrocracker processes are run length, maintenance costs and most important, the achieved conversion. Very often, a compromise is made between unit operations and conversion due to fouling.2 The limiting factor is fouling of the ebullated-bed unit fractionation section, especially the bottom stream areas, atmospheric- and vacuum-column bottoms, and vacuum-column furnace.3–5 The bottom-stream heat exchanger run lengths and maintenance requirements typically limit total unit conversion and dictate unit economics efficiency. Fouling can also occur in the high- and mid-pressure separators downstream of the ebullated reactors. The ebullated-bed unit distillation columns and related furnaces can also foul significantly.

The deposit generation mechanism from distillation residuals caused by thermal cracking is mainly due to polymerization and condensation of asphaltenes. This mechanism is slowed and partly controlled by catalytic hydrogenation.5 This allows much higher yields compared to thermal processing, such as visbreaking and delayed coking.

Fouling Increased maintenance cost Shorter run lengths

Optimal operational window

Conversion increases

FIG. 1

Exponential fouling curve.

fouling are the atmospheric and vacuum columns and bottoms HYDROCARBON PROCESSING OCTOBER 2010

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PROCESS DEVELOPMENTS Typically, a low-stability reserve, high-asphaltene content and high insolubility will result in higher fouling tendencies in the ebullated-bed unit and increased coke formation, thus yielding an unstable resid product.

Additionally, the amount of metallic contaminants can affect process performance by impacting catalyst performance, and, in some cases, by increasing coke formation. Sodium and iron, in particular, have a high impact on coking tendency.

To avoid deposit generation in the ebullated-bed unit, the extrudate catalyst plays a major role.5 Catalyst type itself can have a great impact on unit performance. In ebullated-bed reactors, the catalyst is changed continuously to maintain catalyst activity and

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metals removal efficiency. In addition, catalyst and unit operations affect the reactor-effluent quality and ebullated-bed unit fouling.

The quality of the catalyst and the effect of the extrudate catalyst management to downstream unitsâ&#x20AC;&#x2122; bottoms oil quality and fouling tendencies are directly observed with monitoring techniques.

Traditional fouling control. Traditionally, the ebullatedbed reactor units are controlled by measuring asphaltenes stability by adding asphaltenes precipitants (paraffins) to the cracked resid or fuel, and then measuring the precipitant quantity needed to cause flocculation. These detection methods may be based on simplified paper chromatography (spot test) or microscopybased methods, known generally as p-value.

Apart from detecting the â&#x20AC;&#x153;stability reserveâ&#x20AC;? by probing with paraffinic-solvent addition, the sediments can also be measured by filtration methods. These are known as hot filtration tests (HFTs)â&#x20AC;&#x201D;e.g., IP375 and ASTM D4870â&#x20AC;&#x201D;when performed on heavy fuel oil.

When fuel oil is submitted to aging procedures to reproduce long-term fuel oil behavior with respect to sediments deposition, it is usually reported as total sediment potential and total sediments by accelerated aging. These are included in the IP 390 A&B and ASTM D4870 A and B procedures. In addition, the toluene insoluble test is often used to detect the amount of coke formed by the process.

However, these methods have some limitations due to inherent errors and low accuracy of the analytical techniques. In practice, this can lead to incorrect monitoring results and to a reduced capability to operate at optimal severity. When these methods are applied, there are possible consequences, such as: â&#x20AC;˘ Lost conversion â&#x20AC;˘ Ineffective fouling control leading to reduced run lengths, high maintenance costs and increased safety risks â&#x20AC;˘ Difficulties in reaching fuel oil quality or sediments specifications.

The pressure drop, Î&#x201D;P, and loss of heat transfer in the fractionation-bottom-stream heat exchangers are monitored continuously because they typically foul. A large majority of the maintenance costs are directed in this area, as Î&#x201D;P sets processing limits for the hydrocracking unit. However, if the refiner wants to operate just below where major exponential fouling increases, the processing limits must be found by other monitoring methods rather than just observing Î&#x201D;P. Ebullated-bed unit vacuum-column wash grids can also be affected by fouling.

Unstable resid flashing can increase coking rates at the column-wash grid. The same problem can occur in the vacuum-column furnace. The column-furnace pass tubes

PROCESS DEVELOPMENTS

Techniques for unit conversion optimization. To overcome these difficulties from traditional methods, several proprietary technologies for analyzing impacts on refinery conversion unit operations by fouling and fuel oil stability have been developed. These developments have been used successfully for over 10 years in visbreakers and cokers.7,8 More important, the advanced monitoring programs are proving to be vital solutions for optimizing hydrocracker operations, controlling fouling and fine-tuning antifoulant chemical treatment. The processing objective is to obtain maximum conversion, with the best balance between conversion and run length, while avoiding uncontrollable depositions of foulants. The end result will determine the most economical operating scope for an ebullated-bed reactor unit.

Neste Oil was interested in developing more advanced monitoring methods for an ebullated-bed hydrocracker. The methods described here have been adopted by this refiner as part of their process monitoring routine and are used to maintain the process at the optimal operating window. These methods also help in identifying sudden process changes that may affect fouling control. Continuous reporting and information exchanges take place with the refinery operations, as well as with the refinery technology and process development.

Ebullated-bed hydrocracker optimization. The methods discussed here are based on monitoring two aspects related to controlling the impacts of severity/conversion on fouling and sediments: Stability measurement for asphaltene-containing resids. This measurement is based on adding paraffin precipitants. Compared to the traditional methods, asphaltene flocculation is detected by a very accurate turbidimetric measurement in the near-infrared spectrum. This technique offers very good accuracy and low analytical error. It is fast, easy to operate and provides test results in less than 30 minutes. A wide database from refinery conversion units was constructed, and specific correlations for fouling and sediments after accelerated aging procedures (IP 390 A&B and ASTM D4870 parts A and B) were further developed. Therefore, this technique can be used effectively to optimize unit conversion.

Separator section (several in series)

Technology application areas. Key areas prone to fouling in ebullated-bed hydrocracking units include: Ebullated-bed reactor bottom-stream exchangers fouling control. The stability of cracked resid will impact fouling in the bottom-stream exchangers and this is a typical location for extensive fouling. However, fouling in this section can be controlled by adapting severity until the stability limit is reached where excessive fouling potential can occur.

Fouling control for atmospheric- and vacuum-column sections. Fouling in atmospheric and vacuum columns is related to reaction severity and flash-zone temperature in the columns. Raising severity will increase conversion while a flash-zone temperature increase will enable recovery of more distillates. Both aspects have Stability index vs. reactor temperature

Products

Typical processing asphaltene stability

Very unstable asphaltenes Totally insoluble asphaltenes Average reactor temperature

FIG. 3

Hydrogen puriďŹ cation unit

H2 recycle and makeup

Particle measurement of coke and precursors. High severities in thermal cracking reactions cause exponential coke generation due to thermal stress at high conversion. For ebullated-bed processes, coke generation must be controlled. Otherwise, it will cause catalyst problems and generate excessive coke levels that will deposit downstream of the reactors. This impact can also be seen as fouling and as sediment issues in the fuel.

Generation of unstable asphaltenes will easily create fouling.

These asphaltenes are measured as sediments (HFT) in the fuel.

A new method based on sizing and counting coke particles and highly insoluble asphaltenes, using a patented technique with a light obscuration-based instrument, is available. This technique is very accurate measuring trace levels of coke; accordingly, sediments-generation control significantly improves unit management when compared to traditional methods.

Fouling increases

fouling rate, as determined by the increasing tube-skin temperature, can become too high, thus decreasing run length. Therefore, furnace parameters must be monitored continuously, especially skin temperatures.

Asphaltene stability vs. unit severity.

Insolubility index vs. reactor temperature

Products Vacuum residue feed

Products Reactors (several in series)

Products

Vacuum distillation column

Insolubility Index

Products

Atm. distillation column Areas affected by fouling

FIG. 2

Ebullated-bed hydrocracker sections affected by fouling.

Average reactor temperature

FIG. 4

Insolubility index vs. unit severity.

HYDROCARBON PROCESSING OCTOBER 2010

I 61

PROCESS DEVELOPMENTS an exponential impact on column fouling, thus causing columnbottom coking and fouling above the flash zone. All will contribute to gasoil blackening and, sometimes, excessive pressure drop across the column. A new monitoring approach prevents fouling in this section and optimizes column management.

Fluxing of ebullated-reactor streams. It is a common practice in ebullated-bed hydrocrackers to flux with aromatic-rich streams such as fluid catalytic cracking heavy cycle oil to increase asphaltenes stabilization, and decrease coke and foulants generation. Fluxants can be added at various locations within the ebullated reactor processes, thus allowing increased conversion. The impact of this operation depends, apart from flux quantity, on the resid-feed quality and fluxant quality. In some situations, the fluxant is not able to stabilize the resid feed. Using the analytical techniques described here, the refiner can determine the capability of selected fluxants to stabilize designated streams and the stablization as a function of percent fluxant. This allows an optimal choice for type and amount of fluxants applied.

Asphaltenes stabilization increases

Solubility blending index

Resid feed

FIG. 5

Atmospheric bottom

Vacuum bottom

Solubility blending index changes in ebullated-bed hydrocracker streams.

Coke formation increases

Coking index vs. reactor temperature

Average reactor temperature

FIG. 6

Coking Index vs. unit severity.

Blending fuel oil with fluxants. Resid fuel oil is often fluxed with lighter distillate refinery streams to control viscosity and specific gravity specifications. The fluxant will impact asphaltene stability and alter sediment generation for fuel-oil aging. The previously mentioned techniques can be used to quantitatively and accurately measure the impacts from fluxants on stability and on sediments generation.

Monitoring experience at Neste Oil. Typically, ebullated-

bed units are operated very close to the limits of total insolubility of asphaltenes (Fig. 3). To produce a more stable, high-quality bottom product for heavy fuel-oil blending, unit severity is decreased so that conversion and total unit economics do not suffer. However, the asphaltene stability measurement provides a good indication of the medium- and long-term fouling trends and related unit operating conditions. It provides a good measurement to detect whether the reactor conditions influence the insolubility of asphaltenes or the solubility blending capability of the oil matrix. In addition, the asphaltene stability measurement shows how distillation will impact the stability of the column-bottom products. As the distillation process extracts more paraffinic compounds, it will also increase asphaltenes dispersion.

Additional stability-related indices. Asphaltenes insolubility index is a quantitative measurement of precipitation of the asphaltenes. It is highly increased by thermal cracking, as shown in Fig. 4. This index is of particular interest as the ebullatedbed hydrocracker and thermal cracking causes dealkylation of asphaltenes to yield polynuclear aromatics-type structures. These asphaltene structures have increasingly higher aromatic-carbon content and will impact the solubility of the resid matrix.

Solvating power/solubility blending index determines the capability of the resid to keep asphaltenes dissolved. It can also be applied to measure the impact of distillate fluxants on asphaltene stability. As catalytic hydrogenation in the ebullated-bed hydrocracker decreases, the resid capability to solvate asphaltenes decreases; the resulting ebullated-bed resid product has a lower solubility blending index compared to the parent feed resid.

Part of this asphaltene solvating capability is recovered when atmospheric resid is distilled in the vacuum column. Paraffinic components are removed as light- and heavy-vacuum gasoil, while aromatics are not extracted to the same level. Therefore, more aromatics remain in the vacuum resid, which increases the capability to disperse asphaltenes. This stability index is not impacted greatly by temperature as the catalytic hydrogenation rate has a 60 Day 1 Day 2

50 Particle amount index

Coke particle index

Particle index vs. reactor temperature

40 30 20 10 0 1

Average reactor temperature

FIG. 7

62

Coke particle index vs. unit severity.

I OCTOBER 2010 HYDROCARBON PROCESSING

FIG. 8

2

3

4

5

6

7 8 9 10 11 12 13 14 15 16 Particle size index

Typical particle size distribution.

PROCESS DEVELOPMENTS lower activation energy compared to thermal cracking. Therefore, no clear correlation can be observed against temperature.

As shown in Fig. 5, there is a definitive decrease in the solubility blending index due to the catalytic hydrogenation when comparing the residue feed to the ebullated-bed hydrocracker atmospheric bottom. Also, a partial recovery is seen when atmospheric resid is distilled in the vacuum column.

The coking stability index is a measurement of the most insoluble asphaltenes, otherwise called coke precursors. The lower the index, the higher the level of coke precursors, as shown in Fig. 6. These precursors are quickly converted to coke at temperatures above 400°C; Fig. 6 can be used to evaluate and to support the coke-particle measurement method.

The coking stability index defines the asphaltene class that polymerizes at cracking temperatures to produce coke. Therefore, this index can be used to measure coke-formation tendencies of a feed when reactor temperatures increase. The lower the coking stability index, the higher the consequence increase in coke generation.

Particle analysis. The coke particle index measures the content and size distribution of solids/coke precursors and coke particles within a certain range of particles.

The advantages, compared to traditional toluene insoluble methods, are: â&#x20AC;˘ Quantitative accuracy of the method â&#x20AC;˘ Particle size range and its changes can be detected â&#x20AC;˘ Very sensitive to process changes â&#x20AC;˘ Very quick test method.

The amount and size of these particles can be related to fouling and unit run length. Typically, the coke particle formation follows an exponential curve with increasing reactor temperature and severity; therefore, a threshold can be found.

Fig. 7 illustrates the coke particle index increase as a function of the ebullated-bed hydrocracker conversion.

The particle distribution is measured in micron-sized range and shows the distribution of solids, coke precursors and coke particles. The changes in coke-particle size and number can be detected, as shown in Fig. 8. Comparing samples at different unit severities or feed qualities in Fig. 8 show particle growth and increase in quantity that will lead to more severe fouling conditions. Larger particles accumulate easily in various places in the fractionation section, such as in separators and column bottoms.

Particles size will also affect the fouling in heat exchangers as larger sized particles can be easily deposited even when velocities, by design, are elevated to minimize foulant deposition. Coke and solid particles create a very hard deposit on heat-exchanger surfaces that require mechanical cleaning.

The very small toluene insoluble particles (< 1.6 microns) are not filtered in the HFT procedure; but, by growth mechanism, they will lead to increases in fuel-oil sediments.

The particle analysis is also an excellent method to detect fractionation-column operation errors and problems. By analyzing the particles in the gasoil streams above the flash zone, the refiner can detect fouling in upper parts of the columns. Coke particles in gasoil can also be a sign of foaming issues in the column.

Antifoulant program. Neste Oil decided to test an antifoulant program to improve unit fouling control and run length.

Before the trial, a baseline for process and monitoring values was

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PROCESS DEVELOPMENTS created. The program was adopted and modified for the ebullatedbed hydrocracker from high-severity and high-temperature applications.7,8 The program improved operations through controlling different related mechanisms: • Thermal degradation of oils • Asphaltene destabilization • Foulant creating catalytic effects of metals in feedstocks and on equipment surfaces • Precipitation of organic and inorganic solids.

The run length of the bottom-stream heat exchangers depended on the ebullated-bed hydrocracker severity, catalyst management and feedstock. Therefore, it is important to consider the process and catalyst conditions when comparing different operating cases.

On average, the antifoulants have shown a clear increase in the bottom-stream heat exchanger run lengths (Fig. 9).

Time in service between cleanings

Treated with antifoulants Untreated

Results. The economics of ebullated-bed hydrocracking units

are greatly affected by fouling and control methods. Stability methods detect asphaltene destabilization and precipitation tendencies; whereas, the particle method detects the amount and size of coke particles generated in ebullated-bed hydrocracker reactors and downstream units.

For both methods, a target value was determined. The ebullated-bed hydrocracking process was driven by using target control values close to the fouling threshold where rapid exponential fouling occurs.

Different indices can be calculated from these methods to evaluate unit performance and to develop mitigation strategies that minimize fouling impacts and adverse fuel oil specifications.

The methods can be used to determine the best economical operating window for the unit. Process changes affecting fouling can be rapidly seen with these methods. An antifoulant program was introduced after setting the baseline. The antifoulants immediately decreased the ΔP of the fractionation section bottom-stream heat exchangers and the heat exchanger run length was clearly increased. HP 1 2

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Period of heat exchanger being in service between cleanings 3

FIG. 9

Heat exchanger run length.

4

5 6 7 8

LITERATURE CITED Edwards, B., P. Thiel and L. de Bruyn, “Maximizing High Quality Distillates From LC-Fining,” 5th BBTC 2007, Athens.

Sundaram, K. M., U. Mukherjee and M. Baldassari, “Thermodynamic Model of Sediment Deposition in the LC-Fining Process,” Energy and Fuels, September/October 2008.

Putek, S. and A. Gragnani, “First Resid Hydrocracker to Produce Stable, Low-Sulfur Diesel Fuel from Ural Vacuum Residue,” 10th ERTC 10th annual meeting, Vienna.

Sherwood, Jr., D. E., “Barriers to High Conversion Operations in An EbullatedBed Unit Relationship Between Sedimentation and Operability,” NCUT Workshop, Edmonton, 2000.

McNamara, D. J., D. E. Sherwood Jr. and O. K. Bhan, “Getting More Out of Your Resid Upgrading Unit,” 6th BBTC 2008, Barcelona.

Bartholdy, J. and S. I. Andersen, “Changes in Asphaltene Stability During Hydrotreating,” Energy and Fuels, 2000.

Spanu, U., A. Sesselego, M. Respini and G. Jones, “Avoiding Foul Play,” Hydrocarbon Engineering, November 2006.

Wright, B., ”Reducing Fouling in Delayed Coker Heaters,” Hydrocarbon Engineering, October 2007.

Joni Kunnas is a development manager at the Neste Oil Porvoo refinery in Finland. He has 15 years of experience in the chemical and refining industries. At present, Mr. Kunnas focuses on the Porvoo refinery’s production line 4 (HMU, LCF, MHC) process development work, and manages their research projects. He has specialized in LC-Finer-related items since the construction and startup of production line 4. Mr. Kunnas graduated from the Helsinki University of Technology with an MS degree in chemical engineering.

Ossi Ovaskainen is a Baker Hughes account manager based in Finland and is responsible for Baker Petrolite industrial product line sales. With 15 years of experience in industrial chemical applications, he has spent the past seven years as an account manager for Baker Hughes, specializing in refinery and petrochemical applications. Mr. Ovaskainen holds an MS degree in chemical engineering from the Helsinki University of Technology.

Marco Respini is a Baker Hughes technology development specialist in the Baker Petrolite Industrial Technology Group in Europe, specializing in refinery process fouling control. He has 12 years of refining experience and is currently involved in developing new technologies for monitoring fouling and severity control in resid conversion processes. Mr. Respini has extensive experience in asphaltene-related problems in oil production and refining. An inventor of two US patents, he has published four technical papers and three conference papers on visbreakers and heavy fuel oil stability problems. A graduate of Milan University with a degree in industrial chemistry, he has been a research fellow in the field of organometallic catalysts and is a registered professional chemist in Italy.

Select 170 at www.HydrocarbonProcessing.com/RS 64

PETROCHEMICAL DEVELOPMENTS

Troubleshoot silicon contamination on catalysts What are the sources, impacts and possible solutions to controlling this problem in your hydrotreater?

J. M. BRITTO, M. V. REBOUCAS and I. BESSA, Braskem S.A., Camacari, Brazil

Olefin process overview. Ethylene production from naphtha steam cracking (naphtha pyrolysis) produces several byproducts, including a C5+ stream (called pyrolysis gasoline or pygas). Pygas is a highly unsaturated C5–C14 hydrocarbon mixture that is rich in dienes, olefins and aromatics, especially benzene.

CH3

FIG. 1

Al2O3

Al2O3

H

––

H2

[–– O –– Si]n –– O –– ––

---

H

---

–––

O –– H

O– –

––

conducted extensive studies to determine the mechanism of catalyst deactivation when subjected to coker naphtha feedstocks containing silicon.1,2 They found that polydimethylsiloxane and similar compounds decompose at high temperatures, and this conclusion was confirmed by detecting a homologue series of cyclic siloxanes

––

––

H

Silicon adsorption mechanism. The authors have recently

CH3

O

––

[–– O –– Si]n–– O –– -

[–– O –– Si]n –– O ––

––

CH3

---

Changing feedstock origins. The global trend of increased feedstock diversification stocks from different oil origins and application of new upstream technologies has initiated challenges for petrochemical producers. Diverse feedstocks usually contain higher contamination levels that can impact facility and process unit reliability. For example, over the past few years, an increase in silicon content in naphtha fractions has been observed.

The main source of this contaminant is degradation of silicone oil (polydimethylsiloxane) used as an antifoam additive in crude oil extraction. Excess silicone will crack or decompose in refining processes, thus generating modified silica gels and fragments. These gels and fragments are mostly distilled into the naphtha-range products and are sent to downstream naphtha hydrotreaters. Naphtha hydrotreaters use catalyst systems that are very sensitive to poisoning.

Key questions to understand on this problem are: What is already known about the deactivation mechanism of catalysts poisoned by silicon? At what contamination levels does the situation become critical? What are the impacts of naphtha contaminated with silicon on downstream units? What are the best methods to detect silicon in naphtha? How do you minimize these impacts?

in coker naphtha. These compounds quickly adsorbed onto catalyst surfaces. The studies also showed that silicon is present as modified silica gels consisting partly of bulk SiO2 with surface groups SiOH and Si(OH)2 and modified gels with methylated surface species.

Catalyst deactivation is caused by adsorption onto surface, as illustrated in Fig. 1; thus reducing the number of active sites for hydrogenation and hydrodenitrogenation. Activity loss due to silicon contamination is irreversible and cannot be restored by catalyst regeneration.3 The deposition is an activated and diffusionally controlled reaction catalyzed by the surface alumina sites. Briefly put, the silicon uptake capacity is higher for catalysts with a greater number of specific surface areas. With increasing average catalyst bed temperatures, silicon catalyst adsorption capacity, likewise, increases. The influence of silicon deposition on catalyst activity is more pronounced for hydrodenitrogenation (HDN) than for hydrodesulfurization (HDS) activity. Therefore, the HDN activity can be used to track silicon contamination.

A silicon content of 20 %w/w SiO2 (10 %w/w Si) on the catalyst surface may reduce as much as 90% of the desulfurization activity for most catalysts. Another undesirable effect from silicon deposition is that the catalyst cannot be regenerated, as the silicon would be adsorbed on the entire catalyst surface. Result: An irreversible loss of surface, pore volume and active sites is observed.1,3 Only a few studies have been published about upgrading the quality of straight-run (SR) naphtha fractions by silicon removal. Most studies that have been published about silicon contamination and removal process are focused on coker naphtha.

––

U

sing new upstream technologies and diversified feedstocks from different sources has increased the level of silicon contamination that has a significant impact on hydrotreating catalyst activity. Silicon deposition on hydrotreater catalyst surfaces significantly reduces its desulfurization activity. In addition, silicon deposition renders the catalyst non-regenerable. During regeneration, the silicon would be irreversibly adsorbed onto the entire catalyst surface, thereby further deactivating active sites.

This article discusses the impact by silicon on pygas and naphtha hydrotreatment catalysts at Braskem’s petrochemical plants.

Mitigation actions taken by the process engineering team are presented, including changes in the catalytic cycle management, strict control in the feedstock quality and an improved analytical method for silicon monitoring.

Al2O3

Schematic of silicon molecules adsorption on alumina in hydrogen presence.

HYDROCARBON PROCESSING OCTOBER 2010

I 65

PETROCHEMICAL DEVELOPMENTS TABLE 1. Hydrotreating catalysts cycle length Reactor Pygas 2nd stage—Plant 1 Pygas 2nd stage—Plant 2

Second reactor inlet temperature, °C

Naphtha HDS

Cycle number

Year

Cycle length, months

Performance

1st 2nd 1st 2nd 3rd Single cycle Single cycle

2007–2008 2008–2009 2006–2007 2007–2008 2008–2009 2005–2007 2007–2009 2009–2010

13 5 12 12 7 30 18 6 onstream

good poor good good poor good poor poor

or poor hydrogenation\HDS performance. Particularly, Braskem’s policies apply a single cycle for the naphtha hydrotreater reactor, due to the tight specification required by the reforming catalyst.

240 240 2nd cycle startup 240 240 1st cycle: May 2007–June 2008

Temperature profile for pygas second-stage reactor throughout the two first cycles.

FIG. 2

Bromine index, mg/100 g

2nd cycle: July, 2008–Nov. 2008

2,500 2,000

2nd cycle startup

1,500 1,000 500 0 1st cycle: May 2007–June 2008

FIG. 3

2nd cycle: July 2008–Nov. 2008

BI product profile from the pygas second-stage reactor (plant 1).

Pygas hydrotreating process involves two stages: a diolefin monohydrogenation step followed by an olefin saturation and sulfur removal step.4 The second stage involves hydroprocessing all or a specific cut of the first-stage product to remove olefins and sulfur, which prepares the feed for aromatic extraction and/ or addition in the motor-gasoline blending pool.

Product from the first-stage reactor is sent to a second-stage reactor that uses cobalt-molybdenum (CoMo) and/or nickelmolybdenum (NiMo) catalysts to remove sulfur. This unit is typically operated at pressures of 30 bar–40 bar and at temperatures of 260°C–310°C. Unconverted styrenic compounds and dienes increase rates for coking and polymer formation when exposed to higher temperatures in the second stage. This is the main cause for unplanned plant shutdowns.

The naphtha HDS is another hydrotreating unit that processes a naphtha cut. In this case, the C6–C10 comes from the naphtha fractionation unit. This unit removes impurities including nitrogen, oxygen, metals and most sulfur from the naphtha, which is then sent to the naphtha catalytic reformer.

Catalyst service life depends on feed-space velocity, feed composition, number of regenerations, reactor design and conditions for regeneration. Typically, the second-stage pygas and naphtha hydrotreating reactors can demonstrate a lifetime from three to four years, with at least a one-year cycle length. The end-of-run (EOR) is usually defined by a high pressure drop across the bed 66

I OCTOBER 2010 HYDROCARBON PROCESSING

Hydrotreater feedstock. SR naphtha is an important feed-

stock for petrochemical production. Also, SR naphtha consists mainly of aliphatic hydrocarbons, along with small amounts of naphthenic and aromatic hydrocarbons. Processed naphtha feedstocks typically have a silicon concentration below 50 ppb.

However, higher values have been detected. Silicon contamination is often related to the coker naphtha, and it is not a typical contaminant of SR naphtha. Silicon presence in SR naphtha is attributed to contamination during oil extraction in deep water (which is common in Brazil), requiring an antifoam injection in the wells, during the extraction process.3 It is believed that changes in this procedure have led to accumulation of some silicon species in the naphtha cut from the refining process.

When feedstocks with low silicon content are processed, the usual approach is to allow the silicon to be absorbed on the bulk catalyst, since only a small amount of catalyst is required to remove silicon. However, with increasing levels of contaminated material to be processed, the silicon contents have increased. Therefore, it is common to confine the silicon deposition onto guard material to protect high-activity catalysts, which is the bulk catalyst.

In this context, feedstock-quality control is essential to protect downstream hydrotreating catalysts.

Process problems. Performance losses in the second stage

of hydrogenation of both pygas units were observed in Braskem plants. Similar problems in the naphtha hydrogenation unit throughout 2007–2008 were also noted.

The catalyst used in the second-stage reactor (pygas plant 1) was replaced in May 2007. During this inventory first cycle, this catalyst operated for about 4.5 months, using a starting temperature of 260°C and even operating a feedrate 10% higher than design capacity at points of the run. Data confirmed good performance by the catalyst during its first cycle. After 13 months onstream, this catalyst had to be regenerated. The next cycle did not perform well from the start-of-run (SOR), thus indicating deactivation behavior.

The naphtha hydrogenation reactor, which had demonstrated good performance in the previous single cycles, performed poorly on the last two cycles. The cycles corresponding to the 2007–2008 runs in all of the hydrotreating reactors showed performance problems. Table 1 lists the catalysts cycle times.

After regeneration procedures, both pygas reactors showed poorer performance in terms of bromine index (BI) and dienes. As a consequence, the inlet temperature had step-wise increases to the EOR temperature in the last months of the cycle. Fig. 2 illustrates the inlet temperature profile from the pygas second-stage reactor

PETROCHEMICAL DEVELOPMENTS (Plant 1) throughout the last two cycles, while the Fig. 3 shows the BI profile on the reactor effluent during the same time.

A similar behavior was observed on the Plant 2 pygas secondstage reactor, and the last cycle of naphtha HDS catalyst also demonstrated poor denitrogenation performance after only eight months onstream.

Process problem investigation and mitigation. The

tor the silicon occurrence in the naphtha feedstocks. A study was done to identify these analytical problems and re-establish adequate silicon monitoring. Severe analyte losses were observed in the original analytical methods, based on electrothermal atomization atomic absorption spectrometry (ETAAS).

TABLE 2. Silicon content on spent catalysts Samples

SiO2 , % w/w

process data evaluation showed that the recommended increase 2nd stage plant 1 reactor 12.3 of inlet temperature did not yield any improvement for product 2nd stage plant 2 reactor 9.5 properties (sulfur, diene or BI), suggesting that an abrupt drop in Naphtha HDS reactor 18.9 the catalyst activity had occurred. This behavior was unexpected and is not consistent to the process data status or the feedstock composition.

Data evaluation included checking feed composition for styrene and dienes content, due to the possibility of a first-stage reactor low efficiency. From this analysis, the first reaction system demonstrated good performance in this period. The feed distillation parameters were checked, and no significant shift was found to explain the catalytic deactivation behavior. The possibility of plant leakages was also investigated, and nothing of value was found.

Uncertainty in the feedstock or product analysis was suggested and investigated.

At this time, the silicon content was not monitored in pygas feedstock, due to the lack of analytical methodology. Since the MSA UltimaÂŽ X Series silicon concentration in SR naphtha and Gas Monitors medium-range naphtha cuts were always at More efficient asset management low levels, routine silicon analytical control of the pygas feeds had not been required.

More flexibility with digital or analog capability After the last short cycle, the Plant 1 catalysts were dumped, and samples col More compatibility with existing lected for analysis. The spent catalyst charinstalled operations acterization confirmed silicon poisoning, as Ask about our new 10-year warranty presented in Table 2. This contaminant was on DuraSourceâ&#x201E;˘ Technology for Ultima found in high levels in the catalysts samples, XIR and XI Gas Monitors. For your gas and these values were much higher than detection solutions, contact MSA what would be expected even for catalysts at 1.800.MSA.INST. that were at the end of their service life. The HDS catalyst sample showed even higher silicon content compared to the pygas catalysts, due to its longer cycle length.

To see videos about the New catalyst inventories were selected Ultima X Series of Gas Monitors, scan with from a technical proposal. High-surface your Web-enabled area catalysts were presented as a promismobile phone. ing technology for silicon uptake to main* www.2dscan.com * standard data rates may apply tain desired HDS performance. Previous hydrotreating catalyst was replaced with new technology, which showed higher superficial area and were designed to uptake higher silicon levels now present | G A S M O N I T O R S | S C B A | M U LT I G A S D E T E C T O R S | in the feedstocks. A catalyst-cycle manageH E A D / E Y E / FAC E P R OT E C T I O N | ment considering a more frequent catalyst replacement was also discussed.

1.800.MSA.INST | www.MSAnet.com

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Analytical methodology. Former

analytical methods were not able to moniHYDROCARBON PROCESSING OCTOBER 2010

I 67

PETROCHEMICAL DEVELOPMENTS A new method was developed using the same analytical technique (ETAAS).5 However, significant modifications in the methodology were done to avoid losses of the volatile silicon species throughout the procedure. For instance, the pyrolysis temperature, required to calcinate the sample and remove the complex matrix before silicon measurement, was significantly decreased from 1,200°C to 600°C. The silicon was stabilized by chemical modification with lanthanum, whose reaction product remains stable throughout the temperature program, which the sample is subjected to in a graphite furnace. Using a method without such modifications, as described in literature, analyte losses above 70% may be observed if volatile silicon species are present in the sample.6 Considering a previous dilution of the sample with a suitable micro-emulsion solvent, the method was able to reach detection 3,500

Silicon, ppb m

3,000 2,500 2,000 1,500 1,000 500 0

FIG. 4

Sample

Recent silicon content results in SR naphtha.

limits as low as 20 μg/kg-1 in the original sample. With the new methodology much higher silicon levels were detected in naphtha samples, as shown in Fig. 4. A similar methodology was also developed to monitor silicon content in pygas feeds.

Process follow-up improvements. New practices were

implemented to achieve suitable hydrotreating catalyst performance while monitoring silicon occurrence, as highlighted here: • Improving the silicon analytical method applied to the naphtha and pyrolysis gasoline samples, thus allowing suitable process management • Selecting new catalyst technology to improve the silicon uptake, based on technical proposal evaluation and industrial experience.

Additionally, some other strategies were established: • Catalyst cycle management; replacing the catalyst bed after the first cycle, even if this would in crease operating costs • Sampling, analysis and segregation of used catalyst for later usage. This practice could allow applying a spent-catalyst bed as a spare for emergencies • Install silicon guard as the top layer of the catalyst bed • Developing a better guard-bed reactor design for upstream installation of an HDS naphtha unit, since this system is exposed to even higher silicon feed contamination.

Lessons learned. From this experience, several learned lessons were identified. Silicon poisoning limits hydrotreating catalyst run length. The catalyst’s first cycle is affected by the silicon contamination, as indicated by decreasing reaction parameters

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I OCTOBER 2010 HYDROCARBON PROCESSING

Select 172 at www.HydrocarbonProcessing.com/RS

PETROCHEMICAL DEVELOPMENTS throughout the cycle. Therefore, after the first regeneration, the catalyst deactivates sharply, and its performance significantly affects unit reliability. This phenomenon is explained by the silicon’s irreversible incorporation onto catalyst alumina surface, affecting textural and chemical properties.

Catalysts that show a high superficial area and pore volume are suitable technology to increase catalyst silicon uptake when applied to the pygas hydrotreating units. Emphasis must be placed on feedstock-quality control, especially for the analytical methods used to determine silicon and other catalyst contaminants. Accurate silicon measurement is essential to provide the best process control and catalyst management. Great care and attention should be directed to analytical methodology development to avoid the loss of very volatile silicon species that would lead to inaccurate lower testing results. HP ACKNOWLEDGMENTS The authors thank Braskem S.A. for supplying technical resources required for this work and Ivan Bessa for final paper revision.

1

2

3

4

LITERATURE CITED Hancsok, J., S. Magyar, and A. Lengyel, “Upgrading of Delayed Coker Light Naphtha in a Crude Oil Refinery,” Petroleum & Coal, Vol. 51, No. 2, pp. 80–90, 2009.

Blok, K., M. Patel and T. Ren, “Olefins from Conventional and Heavy feedstocks: Energy Use in Steam Cracking and an Alternative Process,” Energy, Vol. 31, pp. 425–451, 2004.

Rangel, M. C., P. Reyes and M. O. G. Souza, “Silicon Poisoning of Pt/Al2O3 Catalysts in Naphtha Reforming,” Catalyst Deactivation, pp. 469–472, 1999.

Medeiros, J. L., O. Q. F. Araújo, A. B. Gaspar, M. A. P. Silva, and J. M.

5

6

Britto, “A kinetic Model for the First Stage of Pygas Upgrading,” Brazilian Journal of Chemical Engineering, Vol. 24 pp. 119–133, 2007.

Reboucas, M. V., D. Domingos, A. O. Santos and L. Sampaio, “Copper, Iron, Lead and Silicon Determination in Naphtha By Graphite Furnace Atomic Absorption Spectrometry—Comparison Between Direct Injection and Microemulsion Pretreatment Procedures,” Fuel Processing Technology, November 2010, pp. 1702–1709.

Amaro, J. A. A. and S. L. C. Ferreira, “Application of factorial design and Doehlert matrix in the optimization of instrumental parameters for direct determination of silicon in naphtha using graphite furnace atomic absorption spectrometry,” Journal of Analytic Atom Spectrometry, Vol. 19, pp. 1–5, 2004.

Jaildes Britto is a senior chemist working in the technology group of Braskem.

At present, she is involved with a catalysts and sustainable technologies. Dr. Britto has over 20 years of experience in catalytic processes, which includes development work in partnership with universities. She holds an MSc degree in inorganic chemistry and a PhD in physical chemistry from Federal University of Bahia, Brazil. Dr. Britto has authored two patents and several technical and scientific papers related to catalytic issues.

Marcio Reboucas is a senior chemist working in Braskem’s petrochemical plant.

Previously, he worked in the quality control laboratory as a researcher and lab manager. At present, he is involved in new business development for basic petrochemicals.

Dr. Reboucas has over 10 years of experience in analytical chemistry, with focus on spectroscopic and chemometric techniques. Dr. Reboucas holds a PhD in analytical chemistry from the Federal University of Bahia, Brazil, and an MSc degree in analytical chemistry and instrumentation from Loughborough University, England.

Ivan Bessa is a senior chemical engineer, now at the technology group of Braskem. He has 25 years of experience in process modeling and simulation, process development, project implementation and technical support. Previously, he was the leader of the process engineering group related to the aromatics processes for Braskem. He received his BS degree from IME (Military Institute of Engineering - Rio de Janeiro) and an MSc degree from UFRJ (Federal University of Rio de Janeiro), both in chemical engineering.

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Combining his knowledge of reliability engineering with real-world case studies, Heinz has the unique ability to provide insight and guidance that maintenance engineers can apply in their real-world jobs.

That’s why he is so well-respected. Never willing to take a short-cut, Heinz’s attention to detail and awareness of the big picture makes him a beacon of light for the HPI. Heinz, as an editor for Hydrocarbon Processing for 10 years, has built a dedicated following worldwide in his area of responsibility.

He holds six U.S. patents and has authored over 460 technical papers and 17 books on machinery. He was an Exxon Chemical Co. machinery specialist and held positions worldwide before retiring after 24 years with Exxon. His deep personal and technical understanding in the areas of maintenance and reliability and current trends will be presented in this Webcast.

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HYDROCARBON PROCESSING OCTOBER 2010

I 69

PUMPS/RELIABILITY

Cost optimization in mechanical seal applications Real-life case studies prove it is possible to make more informed choices that often lead to cost savings D. K. SHUKLA and D. K. CHAWARE, Essar Oil Limited, Mumbai, India; and R. B. SWAMY, Litwin PEL LLC, Abu Dhabi, U.A.E.

C

onsiderable cost reductions are possible in mechanical seals and associated systems once influencing factors are understood and taken into account. As with other machineryrelated topics and issues, it is important to: • Know the various design options and their respective advantages, disadvantage and limitations. These details are usually (but not always) available from seal vendors.

• Verify the above details. They should be furnished by seal vendors and must be based on end-user application experience from other industries or facilities.

• Have knowledge of complete pumpage property, utilities available, flare pressure and process variation. The possibility of operational upsets associated process requirements should be addressed as well.

• Closely interact with maintenance and plant operators from one’s own plant. Essentially, there needs to be an awareness of prevailing operating and maintenance philosophies.

• Accept the inherent limitations of industry standards. Standards will take a conservative approach and are generic.1 This means that following through with thoughtful and judicious selection processes may allow bypassing certain stipulations. Safely bypassing these stipulations is often possible in niche applications and will achieve cost savings.

Several implementations based on the above approach have

FIG. 1

70

API Plan 11 and injecting a controlled pumpage flow (a side stream taken from a higher pressure source) into the seal environment.

I OCTOBER 2010 HYDROCARBON PROCESSING

led to cost savings; they are described below and may help the cost-conscious end user to make a more suitable choice. The typical cost elements and calculations for life-cycle cost (LCC) for a five-year equipment life are given in Table 1.

It should be noted that cost calculations will differ for each particular case since contributing elements cover a wide range from plant to plant and also from country to country. Among the important variables we find are: initial equipment cost, labor and utilities. Of special concern here is cooling water— unfortunately considered negligible in India—and the maintenance and other cost contributions related to environmental safety standards.

Accordingly, and although LCC calculations are mentioned, cost reductions also relate to such seemingly intangible benefits as discontinuing water cooling, savings in extra instrumentation and auxiliaries, and the value of uptime extensions. It might even be reasoned that these intangibles are more important in LCC calculations than in initial equipment cost.

Virtually all mechanical seals require separating the rotating seal face from the stationary face. A liquid is generally best suited to provide both face separation and cooling. The American Petroleum Institute (API) has long recognized this fact and facilitated our understanding by issuing relevant standards for our general guidance. These standards represent users, and manufacturers, collective experience; the API seal plans or flush plans published in applicable documents such as API-6822 facilitate communicating seal-related knowledge.

API Plan 11 (Fig. 1) is one of the most common flush recommendations we find in these specifications. As is the case with all other plans, it is intended for use in a certain operating range and, as can be expected, has limitations when operated outside this range. Some case studies highlight the particulars.

Case 1: API Plan 11 or Plan 23? For hot water or condensate applications above 80°C, end users generally opt for single mechanical seals with Plans 21 (Fig. 2) or 23 (Fig. 3). These flush plans provide a cool flush to the seal; also, at least one tutorial on plan selection mentions Plan 23 as the standard selection for such applications.2 Hot water has very low lubricity above 80°C, resulting in high seal face wear that generally makes Plan 23 requirement a very prudent selection.

PUMPS/RELIABILITY TABLE 1. Life cycle cost in Indian Rs. (US $)

Input:5 costs in Indian Rs. Initial investment cost (a) Installation and commissioning cost Energy price (present) per kWh Weighted average power of equipment in kW (d)

1 Mech. seal + Plan 23

2 Mech. seal + Plan 11

3 Mech. seal + Plan 75

4 Mech. seal + Plan 52 (b)

5

285,000

250,000

495,000

690,000

200,000

6,600

0

6,600

6,600

6,600

4

4

4

4

4

Plan M (c)

1.83

1.6

0.48

1.1675

0.1875

8,000

8,000

8,000

8,000

8,000

Energy cost/year (calculated) = energy price x weighted average power x average operating hours/year 58,560

51,200

15,360

28,160

6,000

5,000

5,000

5,000

5,000

Average operating hours/year

Operating cost/year

5,000

Maintenance cost (routine maintenance/year) Repair cost every 2nd year (e) Other yearly costs (f) Downtime cost/year Environmental cost Decommissioning/disposal cost n—Life in years i—interest rate, % p—Inflation rate, % Output: net present LCC value (g)

4,500

900

6,300

6,300

4,500

60,000

75,000

75,000

60,000

0

1,300

0

10,500

34,300

1,300

0

0

0

0

0

0

0

2,000

2,000

0

500

0

500

500

500

5

5

5

5

5

10

10

10

10

10

6

6

6

6

6

710,000 (US $16,000) 640,000 (US $14,200) 800,000 (US $17,800)1,177,814 (US $26,174)

117,000 (US $2,600)

a) Mechanical seal cost (if applicable) + cooler (if applicable) + piping and auxiliaries. b) Plan 52 cost includes the seal heat-exchanger cooling Plan M cost as per Reference 9. c) Plan M seal cooling cost estimation is as per schematics given in Reference 9. d) Energy consumed by mechanical seal cost + recirculation liquid energy cost applicable for Plan 11 only + cooling-water cost. e) Repair cost of mechanical seal. f) Cooler repair and cleaning costs + instrument calibration and repair + buffer/barrier liquid replacement. g) 1 US$ = Indian Rs. 45.

Authors’ notes: *Investment costs appear to have been calculated based on hardware considerations. The user should be mindful of the piping connection and instrument hookup costs. *Plan 75 is normally the most expensive since it requires connection to the flare and close drain systems. Plans 76 and 52 require connection to flare.

However, a specially designed seal with face-enhancing features outlined in API-682 may allow the user to stay with Plan 11. Usually the pressure distribution across the conventional seal faces is linear and drops from sealing box pressure at the outer seal face diameter to atmospheric pressure at the inner diameter.

Depending on pressure and temperature, vaporization may take place part-way across the seal face. Designs with features that might include a water groove or an engineered laser etching are aimed at deferring or even avoiding this vaporization.

Although these specially designed seals have limitations and are influenced by stuffing-box pressure, pumpage temperature and peripheral speed, they cover many of the applications in hot-water services with Plan 11 instead of Plans 21 or 23. Use of Plan 11 over Plan 21 or 23 allows eliminating the cooling system.

(The advantages of cooling device elimination are described in references 3 and 4).

The initial bare seal cost of a specially designed water groove seal is usually 10% to 20% higher than a conventional API-682 seal requiring Plans 21 or 23. Eliminating the cooler and piping, however, reduces the overall initial investment (refer to columns 1 and 2, Table 1).

The typical cost elements for special seals with Plan 11 and conventional seals with Plan 23 for a boiler feedwater pump (300 m³/h at 243-m head and 120°C) are given in Table 1. In each instance, the seals are for a 3.625-in. shaft size and in general compliance with the guidelines found in reference 2.

FIG. 2

API Plan 21—Product recirculation from discharge through flow control orifice and heat exchanger to seal chamber.

The LCC for both options was calculated per reference 5 and is shown in columns 1 and 2 of Table 1. A five-year life span, a 10% interest rate and a 6% inflation rate were applied. The slight economic advantage of seals requiring Plan 11 is evident; however, eliminating cooling-water requirements should be factored in when the user decides on a preference.

HYDROCARBON PROCESSING OCTOBER 2010

I 71

PUMPS/RELIABILITY Case 2: Plan 21 vs. Plan 23. As a general rule, Plan 23 is

considered a better option than Plan 21; some inherent advantages are spelled out in reference 2. Among these, Plan 23 has a lower heat load that allows using a smaller cooler or an extended cooler life. Plan 21 consumes more energy than Plan 23 because the pumped fluid must first be cooled and then repumped from suction back to discharge. There is also a heat load addition due to the cooling requirements. To avoid undersizing, cooler load calculations must be done carefully for Plan 21.

FIG. 3

API Plan 23—Product recirculation from seal chamber to heat exchanger and back to seal chamber. A bidirectional pumping ring and advanced-style bearing protector seal are shown in this illustration.

While Plan 23 would thus seem to be favored, some site experiences may prove different. In this particular case history, seal units supplied with Plan 23 were later modified to Plan 21. The negative experience with Plan 23 was attributed to the following: • Hydraulic friction losses in the piping connected to the pumping element are available with respect to water and inadvertently used for pumpage other than water. The pipe friction losses, calculated based on water as the medium, will often prove incorrect for liquids such as LNG or lube oil. To not misjudge the effectiveness of a particular pumping element, the system resistance calculation must reflect pumpage actually handled.

• The capability needed by a pumping element to overcome system resistance was not checked by either the pump or seal supplier. The pumping element H-Q characteristics should comply with clause 8.6.2.2 of API 6822 and piping friction and heat loss calculations must be accurate.

• The pumping element proved ineffective due to vapor-lock, wrong location of inlet/outlet ports, and changes in fluid properties, poor design and reduced operating speed. Speed changes are possible in case of pumps fitted with a variable-speed drive or when an existing drive is replaced with a lower-speed version.

• Pumpage properties such as solids content, suction and stuffing-box pressure margin over vapor pressure and the pumpage tendency to solidify were not taken into account at the time of plan selection.

• The available pumping element—in this case, an elementary pumping ring—proved ineffective. A better option might have been a pumping screw 6 or an innovative bidirectional

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I OCTOBER 2010 HYDROCARBON PROCESSING

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PUMPS/RELIABILITY TABLE 2. Guidelines for pressure and level switches selections for Plans 52/53A/75 (Case 2) Pumpage vapor pressure

Plan

Pressure switch High Low

Level switch High Low

Technical justification for recommendation

52

> or < flare pressure

R

–

R

R

In this situation, since the flare pressure normally keeps on varying, all media that have a vapor pressure > or < flare pressure may leak to the outboard area in vapor or liquid forms depending upon the flare pressure at a given time. Hence, both the LSH and PSH per reference 2 are necessary.

52

> flare pressure

R

–

–

R

In this situation, since the pumpage vapor pressure will always be > maximum flare pres sure, the leaked media will always be vapor. As such, the LSH requirement per Reference 2 is not essential. An PSH is mandatory.

52

< atmospheric pressure

–

–

R

R

In this situation, since the pumpage vapor pressure will always be < atmospheric pressure, the leaked media would always be liquid. As such, the PSH requirement per Reference 2 is not essential. A LSH is mandatory.

53A

> atmospheric pressure

–

R

–

R

In Plan 53, flare pressure does not matter. In this situation, in case the plan 53 pressure source fails at the same time the PSL also fails and the inboard seal leaks, even then the LSH would never function since the leakage would never be in liquid form. As such LSH requirement per Reference 2 is not essential.

75

< atmospheric pressure

–

–

R

–

In this situation, since the media vapor pressure will always be < atmospheric pressure, the leaked media would always be liquid. As such, the PSH requirement per Reference 2 is not essential. An LSH is mandatory. A level transmitter would be recommended in place of a level switch to have a precise measurement/recording.

R: Required

Note: Plan numbering is as per (2). Flare pressure varying and assumed always to exceed atmospheric pressure.

pumping ring.7 The latter is certainly also the most reliable.

Pumping screws are efficient but require close gaps that cause their own set of concerns in case of shaft deflection and internal rubbing. Moreover, the unidirectional pumping screw geometry can create interchangeability problems.

Poor Plan 23 execution is often at fault and needs to be corrected before concluding that Plan 21 excels. Heat loads imposed on cooling towers in many plants can be a major issue along with cooler fouling. Heat removed at the seal is heat removed from the process. Heat allowed to return into the process represents an inefficiency that often reaches 10 kW or more—an amount that simply cannot be ignored.

In short, careful piping system analysis is needed if selecting Plan 23. The responsible engineer must ensure that the needed flush flowrate is, in fact, achieved at the anticipated operating speed. Seal accessories such as piping, instrumentation, reservoir and coolers should preferably be procured from the seal manufacturer. This will facilitate verifying actual recirculation flows and ascertain pumping device efficiency. If needed, the coordinating corrective measures will be greatly simplified. Suction pressure fluctuations are to be taken into account, since this can lead to inadequate margin over vapor pressure—a frequently overlooked issue resulting in vapor-lock even with venting holes.

The most practical option for an end user or equipment owner may well be Plan 23, if all parameters favor it. Select Plan 21 if the data for LCC calculations and technical support are lacking, in which case, you might not be able to verify the full adequacy of Plan 23. At all times, question the seal vendor and do not take anything for granted. Just because it might be tradition among seal vendors to do such-and-such doesn’t necessarily make it the most intelligent choice.

Case 3: Instrumentation for Plans 52/53A/75. Costly instruments can be avoided if pumpage vapor and flare pressure variations are given due consideration. In a particular case where

FIG. 4

API Plan 75—Process liquid leakage from the inboard section of a dual-containment seal is sent to a liquid collector.

Plan 75 (Fig. 4) had been supplied, an operations department felt compelled to check if the sealing system could be operated without a high-pressure switch (PSH). In general, Plan 75 is suitable for condensing leakage. Reference 2 and other industry guidelines clearly mention that the PSH is expected to operate if leakage is vapor and if the amount is judged excessive. In this instance, the operations department confirmed that the vapor pressure would always stay well below atmospheric pressure and this proved the PSH to be redundant.

Doing away with the PSH prompted the authors’ facility to determine all pump seal-related instrumentation requirements based on flare and vapor pressures. Moreover, the company decided to enlist the help of pump and seal manufacturers. The HYDROCARBON PROCESSING OCTOBER 2010

I 73

PUMPS/RELIABILITY information compiled in Table 2 can be useful, but it points to the need for all parties to interact and consult when selecting instruments for Plans 52 (Fig. 5), 53A2 and 75 (Fig. 4), all of which incorporate pressure switches.

There could also be applications where a high-level transmitter (LTH) might be preferred to an LSH. Again, cooperation between the interested or affected parties will help define what is best.

Case 4: Plan 75 for Plan 52. Applications involving mechanical seals in light hydrocarbon duties can be provided with Plan 52, as well as Plans 75 and 76, wherein vapor leakage from the inboard segment of a dual-containment seal is directed to a suitable vapor-recovery system.2 Containment seal effectiveness provided with Plans 75 and 76 from emission and reliability viewpoints is satisfactory.8 Reference 8 is among several that acknowledge the suitability of contacting (faces wetted by liquid) as well as non-contacting (faces separated by a gas) containment seals for many applications. Nevertheless, there is often a significant difference in liquid containment (that may occur in a primary seal failure) between noncontacting and contacting sealing devices.

The typical LCC comparison for contacting-type seals and Plan 75 vs. Plan 52 is given in columns 3 and 4 of Table 1. Plan 75 is provided with an LSH, but without a PSH—and Plan 52 with an LSL and LSH, but without a PSH. In the case discussed here, the cost comparison favors Plan 75 and the same trend is observed for Plan 76. Maintenance associated with seal repairs, filling, draining and flushing a contaminated buffer system can be considerable.2 Based on the above discussion, it is worth probing substituting Plans 75 or 76 in place of Plan 52. An end user, however, should take into account certain failure scenarios. In case of Plans 75 or

FIG. 5

74

API Plan 52—Depressurized buffer-fluid circulation in a dual-seal outboard section through a seal-support system.

A pumping ring maintains circulation while running; thermosiphon action is effective at standstill.

I OCTOBER 2010 HYDROCARBON PROCESSING

76, inboard seal failure would require shutdown and maintenance within a short period. In contrast, and with Plan 52, safe pump operation might be continued for longer.

Moreover, the containment-seal condition in Plans 76 or 75 is neither known nor monitored by these plans. If the containment seal is faulty and the inner seal fails, there is a potential for containment loss. With Plan 52, the outer seal condition is continuously monitored by the seal pot liquid level. This safety feature of Plan 52 is an important point.

Finally, Plan 52 only works well on vaporizing leaks; Plan 76 should only be used on vaporizing leakage, whereas Plan 75 is used for condensing leakage.

Case 5: Misunderstandings on Plan “M”. Reference 9

describes piping schematics for seal assemblies or configurations that collect both liquid and vapor leaks. The resulting Plan “M” layouts may or may not require a heat exchanger. In contrast, an exchanger is invariably provided for buffer/barrier liquid cooling with Plans 52 and 53A. Buffer/barrier reservoirs of 20 liters (5 gallons) for all pump shaft diameters were used due to inherent advantages10 including standardization of sizes.

It should be noted that piping connections are often provided with Plan M, although cooling may not be required in many applications. As a general rule, Plan “M” is not required for pumpage temperatures below 45°C, while from 45°C to 70°C, checking the feasibility of an air-fin cooler may be of merit. The cooling-water consumption for Plan “M” can be 10 liters/min. and the typical LCC for five years with Plan “M” is mentioned in column 5 of Table 1. Note that the resulting expenditure might not be incurred. The benefits of eliminating cooling requirements certainly deserve more of our attention.3,4 Again, a careful review of pumpage property (temperature, stuffing-box and vapor pressure range in the anticipated operating temperature range) and buffer/barrier liquid properties is advised. Knowing the coking tendencies of many fluid media at elevated temperature will enable seal manufacturers to determine if cooling is needed with Plan “M” configurations. The responsible entity (pump manufacturer or design contractor) must furnish these details to the seal manufacturers at the bidding stage so that a well-informed decision can be made about using Plan “M.” Case 6: Tapered stuffing boxes. Suppose the conventional seals fail prematurely because a slurry or random solid particles are present in the pumpage. The seal manufacturers recommend solutions such as double seals with Plan 53A/B/C2, single seals with Plan 322 a stuffing box with baffles and seals provided with solid separator bushings.

A tapered stuffing box offers several advantages and is usually recommended for slurry applications.6,11 Some limitations for tapered stuffing boxes include noncompliance with API-610.9 In a typical case, one pump manufacturer offered a pump with a 45-degree tapered stuffing box with an integral vortex-breaking rib with Plan 32, as against a conventional cylindrical stuffing box with Plan 32. A tapered seal chamber with vortex-breaking baffles is self-flushing, self-venting and self-draining. Moreover, the configuration modifies the flow at the seal chamber end and nearest to the seal faces for improved effectiveness. A careful review revealed that pumpage slurry content was low enough to do away with Plan 32 for a tapered stuffing box, leading to sub-

PUMPS/RELIABILITY stantial savings in utilities and initial investment. The substantial combined cost savings prompted users to select a pump with a tapered stuffing box instead of a pump with the more typical cylindrical seal environment.

In summary, real-life case studies prove that it is possible to make more-informed choices that very often lead to cost savings.

These choices can be made from available options and, as long as they deal with proven experience and are well thought-out, the choices may indeed deviate from the more general conventional guidelines. HP

Mechanical Seal Pumping Rings,” Pumps and Systems, October 2005.

Bowden, P. E. and C. J. Fone, “Containment seals for API 682, Second Edition,” Proceedings of the 19th International Pump Users Symposium.

9 ANSI/API Standard 610, Tenth Edition, October 2004, Centrifugal pumps for petroleum, petrochemical and natural gas industries.

10 Gabriel, R., API 610 and API 682, “A Powerful Combination for Maximum Pump/Mechanical Seal Reliability,” World Pumps, September 1996.

11 Riley, P. R., “Increasing the reliability of chemical process pumps by improvement to the environment for seals and bearing,” Ingersoll Dresser Pumps UK, Ltd. 8

D. K. Shukla is a senior vice president with Essar Oil Ltd. in Mumbai, India. He ACKNOWLEDGMENTS The authors thank the management of Essar Oil Ltd, in Mumbai, India, and Litwin PEL LLC, Abu Dhabi, United Arab Emirates, for granting permission to publish. Several major seal manufacturers cooperated by providing noncommercial versions of illustrations and technical data of value. Their assistance is gratefully acknowledged.

has more than 30 years of experience with process and systems engineering in the hydrocarbon processing industry, including oil/gas production facilities and refining/ petrochemical processes. Mr. Shukla’s previous experience includes working with Engineers India Ltd., New Delhi; M.W. Kellogg, Houston; Reliance Engineering Associates plc., Jamnagar, India; and BOC Gases in Murray Hill, New Jersey, and Guildford, UK.

LITERATURE CITED Byson, S., “Mechanical seals—Evaluating what’s right for you,” Chemical Engineering, December 2004.

ANSI/API Standard 682, 3rd Edition, September 2004, Shaft sealing systems for centrifugal and rotary pumps.

“How to save three billion gallons of water per year—the easy way,” AESSEAL plc, Rotherham, UK, Marketing Publication; www.aesseal.com.

Bloch, H. P., Improving Machinery Reliability, Volume 1, 3rd Edition, ISBN 0-88415-661-3; Gulf Publishing Company, Houston, Texas.

Pump life cycle costs, A guide to LCC analysis for pumping systems, 2001, Hydraulic Institute and Europump, ISBN 1-880952-58-0.

Bloch, H. P., “A hundred-plus points to improve pump reliability,” Hydrocarbon Processing, April 2004.

Smith, R. and H. P. Bloch, “Extending Seal Life with Bi-directional

Deepak K. Chaware is a rotating equipment engineer with Essar Oil Ltd. in Mumbai, India. He received an M.Tech. degree in mechanical engineering from the Indian Institute of Technology, in Chennai, India. Mr. Chaware has more than 25 years of experience in the field rotating equipment design, testing and selection.

He has worked with leading pump manufacturers like Jyoti Ltd. in India, Sulzer Pumps India Ltd.; KSB Pumps India Ltd. and Reliance Engineering Associates plc., Jamnagar, India.

2 3 4 5 6 7

Rajkumar B. Swamy is a senior process engineer with Litwin PEL LLC in Abu Dhabi, UAE. He has more than 10 years of experience in the fields of process and system engineering in petroleum refineries and petrochemical complexes. Mr. Swamy is a chemical engineering graduate from Gulbarga University, Karnataka, India and his previous experience includes working with Reliance Engineering Associates plc., Jamnagar, India, and Hindustan Petroleum Corp., Ltd. Mumbai Refinery, India.

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HYDROCARBON PROCESSING OCTOBER 2010

I 75

GAS PROCESSING DEVELOPMENTS

New correlation for calculating natural gas Z-factor Use these calculations for low absolute average error A. A. MOGHADAM and C. GHOTBI, Sharif University of Technology, Tehran, Iran

U

nderstanding the gas compressibility factor is necessary to solve petroleum engineering problems—such as predicting reserve, gas-pressure gradients, gas compression, gas metering, etc. Typically, the gas compressibility factor is obtained by laboratory experiments. Occasionally when laboratory reports are not available, equations of state (EOS) or empirical correlations are used to estimate this important factor. The first step is to determine the pseudo-critical gas properties. This is done by understanding the gas composition and correlations from LeeKesler. When the gas composition is unknown, gas properties are determined using correlations based on specific gravity. After obtaining the pseudo-critical data, the compressibility factor can be determined by using the Standing-Katz (SK) Z-factor chart or Dranchuk and Abou-Kassem (DAK) method.

It is important to calculate the Z-factor accurately. Empirical methods have been developed by gas companies to calculate the

TABLE 1. Coefficient values used in Eqs. 3–7 Coefficient

Tuned coefficients

Aa

76

0.997265

Ba

0.120108

Ca

–1.51296

Ab

–0.330498

Bb

0.213813

Cb

0.082281499

Db

–0.0317047

Ac

7.287

Bc

–13.06

Cc

8.83248

Dc

–2.581

Ec

0.274914

Ad

–0.899

Bd

1.527

Cd

–0.980396

Dd

0.278

Ed

–0.02922038

Ag

5.79784

Bg

–11.53563693

Cg

8.3475

Dg

–2.603

Eg

0.295672578

I OCTOBER 2010 HYDROCARBON PROCESSING

compressibility factor of commercial natural gas, particularly the AGA8 method developed by the Gas Research Institute1 (GRI) and the European Gas Research Group (European gas companies).2 However, these equations are mostly implicit in Z and require complicated and longer calculations.

In simulators, calculating the Z-factor is done by solving EOS or implicit correlations, i.e., DAK method that needs iterative methods, i.e. Newton Raphson method. These methods take considerable amounts of CPU time just for calculating gas properties.

CPU time should be used efficiently in the simulator.

The SK chart is widely used for calculating the Z-factor. Several correlations are proposed to fit the SK chart. Two of the most accurate correlations are: 1) Dranchuk and Abou-Kassem and 2) Hall Yarborough. These two correlations are rather accurate, but they are implicit in Z. The correlation presented is explicit and has two advantages: • Estimating an accurate Z-factor value • Saving CPU time.

An important parameter in the natural gas industry is isothermal compressibility of gases, and it is defined as: Cg =

1 V

V P

(1)

T

where: V is the volume and P is the pressure and Cg is the isothermal compressibility of the gas. It can be shown that isothermal compressibility can be related to the Z-factor. Several methods were presented for calculating the isothermal compressibility.3–5 New correlation. By using 438 data sets from the SK chart, a new correlation was developed. The new correlation for the Z-factor that fits the SK chart is proposed as follows:

Z=

a + b Pr + g Pr 0.428138

(2)

1+ c Pr + d Pr 2

where: C T a = Aa + Ba e a r

(3)

b = Ab + BbTr + CbTr + DbTr 2

3

(4)

c = Ac + BcTr + CcTr2 + DcTr3 + E cTr4

(5)

d = Ad + BdTr + C dTr + DdTr + E dTr 2

3

g = Ag + B gTr + C gTr + DgTr + E gTr 2

3

4

(6)

4

(7)

GAS PROCESSING DEVELOPMENTS The coefficients of Eqs. 3–7 are given in Table 1. Eqs. 2–7 have been proposed to estimate the compressibility factor of gases over the range 0 < Pr < 8 and 1.35 < Tr < 3. The advantage of the proposed equations is that it is explicit in Z; thus, it does not require an iterative solution as required by other methods. The proposed equation has an absolute average error of approximately 1% compared to the SK Z-factor chart. The proposed correlation performance in calculating the Z-factor is compared with those of Dranchuk and Abou-Kassem, Hall and Yarborough6 and Beggs and Brill equations. The results are shown in Table 2 and Fig. 1. It’s shown that Eq. 1 can be written as: 1 1 Z (8) Cg = p Z P T This equation can be expressed in a reduced form as:

1 pr

1 Z

Z Pr

good accuracy at high Tr , but at intermediate Tr , the proposed correlation and Hall Yarborough equation show better accuracy.

However, at low Tr , Hall Yarborough shows the greatest accuracy.

The average error of the proposed correlation in the range 1.35 < Tr < 3.0 and 0 < Pr < 8 is approximately 1%. The Hall Yarborough equation is more accurate at low Tr in comparison to the proposed correlation. Contrary to the proposed correlation, the Hall Yarborough equation is implicit in Z and needs an iterative solution. In Fig. 1, the variation of average errors vs. Tr for all the studied correlations is shown—supporting the comparison made in Table 2.

TABLE 2. Average errors of calculating Z-factor in % using different methods at 0 < Pr < 8 Tr

This work Abou-Kassem Hall Yarborough Beggs-Brill

3

0.4588

0.7346

0.4145

–

2.8

0.5054

0.5757

0.2123

–

2.6

0.4238

0.3676

0.2702

–

2.4

0.5147

0.6112

0.3818

0.9507

(10)

2.2

0.6162

1.02161

0.307

1.0177

By inserting Eq. 2 in Eq. 9, the following equation can be obtained for calculation of Cr .

2

0.5783

2.1665

0.2193

1.5289

1.9

0.607

3.9165

0.1711

1.9067

Cr =

(9)

Tr

where: Cr = C g Pc

b

2ad Pr bd Pr 2 + gc (0.428138 1)

ac

Pr 0.428138 + gd ( 0.428138 2 ) Pr1.428138 +

1 Cr = Pr

0.428138Pr

((1 + c P + d P ) (a + b P + g P 2

r

(11)

0.571862

r

r

0.428138

r

))

1

Eq. 11 can be used to calculate Cr over the range 2.0 < Tr < 3.0 and 0 < Pr < 8 with good accuracy.

Results and discussion. Table 2 compares the results

obtained from the proposed correlation with those obtained from Dranchuk and Abou-Kassem, Hall Yarborough, and Beggs and Brill correlations. The reported errors are with respect to the SK chart. As seen from Table 2, all the studied correlations show 16 This work Abou-Kassem Hall Yarborough Beggs-Brill

14 12

Error, %

10 8

1.8

0.713

6.012

0.2219

2.1907

1.7

0.9696

5.6284

0.3045

1.9737

1.6

1.2345

4.679

0.3101

1.8579

1.5

1.8056

6.7934

0.2241

1.6627

1.45

1.4697

6.133

0.2153

1.223

1.4

3.017

14.4382

0.2941

1.2509

1.35

2.3855

13.437

0.3424

0.954

Average

1.093

4.7511

0.2778

1.1797

TABLE 3. Comparison of correlated values of pseudo-reduced compressibility, using different methods Pr

This work

Dranchuk and Abou-Kassem

2

1

1.0314

1.0284

2

2

0.5124

0.5164

2

3

0.3323

0.337

2

4

0.2391

0.2437

2

5

0.1814

0.1883

Tr

2

6

0.1418

0.1543

2.5

1

1.0069

1.0073

2.5

2

0.4973

0.4995

2.5

3

0.3243

0.3255

6

2.5

4

0.2364

0.2362

4

2.5

5

0.183

0.1819

2

2.5

6

0.147

0.1459

3

1

0.9882

0.9989

3

2

0.4866

0.4935

3

3

0.3194

0.322

3

4

0.2359

0.2347

3

5

0.1857

0.1817

3

6

0.1523

0.1463

0 1.2

FIG. 1

1.4

1.6

1.8

2.0

2.2 Tr

2.4

2.6

2.8

3.0

3.2

Comparison of average errors of different equations vs. reduced temperature.

HYDROCARBON PROCESSING OCTOBER 2010

I 77

GAS PROCESSING DEVELOPMENTS Table 3 compares the performance of the proposed correlation with the correlation for predicting Cr at different Tr and Pr .

The results show good accuracy over the range 2.0 < Tr < 3.0 and 0 < Pr < 8 for both studied correlations.7 The same comparison was made in Fig. 2 at Tr = 2. As illustrated in Fig. 2, both studied correlations show the same accuracy.

pressibility factor of natural gas as a function of reduced pressure and temperature. The correlation has an absolute average error of approximately 1% in the range 0 < Pr < 8 and 1.35 < Tr < 3.

The advantage of the proposed correlation is that it is accurate and explicit in Z; therefore, it does not require an iterative solution contrary to the existing correlations for Z-factor. HP

Conclusion. A simple correlation based on the standard gas compressibility factor chart was introduced to calculate the com-

NOMENCLATURE

Pc : Critical pressure, m/Lt2, Pa Pr : Reduced pressure, dimensionless Tc : Critical temperature, T, Kelvin Tr : Reduced temperature, dimensionless Cg : Isothermal compressibility, Lt2/m, Pa–1 Cr : Reduced isothermal compressibility, dimensionless

1.2 This work Dranchuk and Abou-Kassem

1.0

a: Coefficient, dimensionless A: Coefficient, dimensionless b: Coefficient, dimensionless B: Coefficient, dimensionless c: Coefficient, dimensionless C: Coefficient, dimensionless d: Coefficient, dimensionless D: Coefficient, dimensionless E: Coefficient, dimensionless g: Coefficient, dimensionless n: Number of moles of gas, n, mol P : Pressure, m/Lt2, Pa R: Gas constant, mL2/nTt2, Pa.m3/mol Kelvin T: Absolute temperature, T, Kelvin V: Volume, L3, m3 Z: Compressibility factor, dimensionless

Cr

0.8 0.6 0.4 0.2 0.0 0

FIG. 2

1

2

3

Pr

4

5

6

7

Reduced Isothermal compressibility vs. reduced pressure at Tr = 2.0.

LITERATURE CITED Starling, K. E, J. W. Martin, J. L. Savidge, S. W. Beyerlin and E. Lemmon, “Proceedings of 72nd GPA Annual Convention,” San Antonio, Texas, March 1993.

2 Technical Association of Gas Industry Publication, Technical Association of France Gas Industry, Paris, Fourth Edition, 1990.

3 Trube, A. S., “Compressibility of natural gases,” American Institute of Mining and Engineering, Vol. 210, pp. 355–357, 1957.

4 Drankchuk, P. M. and J. H. Abou-Kassem, “Calculation of Z-factor for natural gases using equations of state,” Journal of China University of Petroleum, Vol. 14 (3), pp. 34–36, 1957.

5 Chen, Z. and X. Zhou, “The calculation of total volumetric change rate of natural gas,” Journal of China University of Petroleum, Vol. 13 (5), pp. 132–137, 1989.

6 Hall, K. R. and L. Yarborough, “A new equation of state of Z-factor calculations,” Oil and gas Journal, Vol. 14 (25), pp. 82–92, 1973.

7 Abou-Kassem, J. H., L. Mattar and P. M. Dranchuk, “Computer calculations of compressibility of natural gas,” Journal of Canadian Petroleum Technology, Vol. 29 (5), pp. 5–108, 1990.

1

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LAB ANALYZERS

Consider using alternative carrier gases for petrochemical analysis Advantages include higher efficiency and shorter analysis times J. DUAN and T. JACKSIER, Air Liquide, Delaware Research and Technology Center, Newark, Delaware

H

elium (He), widely used as carrier gas for gas chromatography (GC), is a nonrenewable resource extracted from natural gas. There has been sound evidence over the past few years of rising costs and shortages, both domestically and internationally, owing to issues with the availability of He. It is likely that the He supply chain issues will continue in the near term. It is, therefore, an incentive for chromatographers to consider alternative carrier gases.

Introduction. Quantitative and qualitative data for petro-

chemical processes are routinely obtained by gas chromatographic analysis. Chromatography effectiveness depends partially on the ability of the carrier gas to transport various components present in the sample from the inlet through the column to the detector (Fig. 1). Therefore, selecting the proper carrier gas for gas chromatography (GC) analysis is very important, especially for complex mixtures.

The chromatographic efficiency of separation is determined by the height equivalent theoretical plate (HETP). HETP is the segment length of the column in which the analyte’s distribution between mobile and stationary phase reaches equilibrium. The smaller HETP value, the better chromatographic resolution.

The relationship between HETP and carrier-gas velocity, μ, is described by the van Deemter equation:

where: A B μ Cμ

Carrier gas flow C B A CA B A C A B C A B C B

Start-no separation C C

C

B B B

A

A

B

A

B A

A

Middle-partial separation C

B

C C

C

B B

C

B B

A

A A

A

A

Finish-complete separation FIG. 1

B + Cμ μ Eddy diffusion

=

C C

A +

The carrier gas role.

HETP, (cm)

HETP

Different components have different dependencies of HETP on the flowrate on the same column depending on the components’ nature and types of the surface interactions. It is impor-

Longitudinal diffusion Mass transfer between the mobile and stationary phases

The carrier-gas flow velocity (μ) influences the mass transport speed through the column. At high velocities, the opportunity for band broadening through longitudinal diffusion of the solute molecules (along the column length) is diminished. This may cause an insufficient amount of time for the molecules to pass into liquid phase. However, when the mobile phase flowrate is too low, there is an increased opportunity for band broadening through longitudinal diffusion. Efficiency tends to fall when the flowrate is too high or too low. This is illustrated in the van Deemter plot (Fig. 2).

Minimum H

B/μ Cμ A Mobile phase velocity μ, (cm/s) Ideal velocity

FIG. 2

HETP vs. mobile phase velocity.

HYDROCARBON PROCESSING OCTOBER 2010

I 79

LAB ANALYZERS tant to find an optimum carrier-gas flowrate where the column efficiency will be the best.

ing to the carrier gases used. Compressed air was fed at a rate of 300 mL/min to the FID. A gaseous hydrocarbon mixture (Table 2A) and a liquid hydrocarbon mixture (Table 2B) were used as samples to evaluate the effect of different carrier gases on the resolution of similar compounds.

Experimental data. Experiments were conducted using a GC

coupled with a flame ionization detector (FID) on an alumina 30 m x 0.538-mm inner diameter capillary column. The FID was operated at 240°C. The hydrogen fuel gas flowrate was varied accordTABLE 2A. Gaseous hydrocarbon mixture Ethane

100 ppm

Ethylene

100 ppm

Propane

100 ppm

Propylene

100 ppm

Isobutane

100 ppm

n-Butane

100 ppm

Nitrogen

Balance

1.00 0.90 0.80

H2

HETP, mm

0.70 0.60

Ar

0.50

N2

He

0.40 0.30 0.20 0.10 0.00

40

60 80 100 Linear velocity, cm/sec

2.636

4.910

4.693

4.080

2

2.109

1.302 1.353 1.473 1.763

40 30 20 10 0

N2 3.80 min

WI:

II-

II+

2.412

2.321

25 20 15 10 5 0

3.319

2.895 3.027

2

WI:

II-

2.023

mVolts

160

2 WI:

II-

20 15 10 5 0 II+

mVolts

140

van Deemter plot for n-butane in N2 using N2, He, Ar and H2 as carrier gases.

II+

mVolts

120

3.640 3.801

FIG. 3

20

3.154

0

Effect of carrier gas. The effect of four carrier gases—nitrogen, argon, helium and hydrogen—on the optimum carrier gas velocity were evaluated by generating a van Deemter plot using 10 ppm n-butane in balance nitrogen (Fig. 3).

The van Deemter plot shows: • Nitrogen and argon generate the highest column efficiencies (smallest HETP), but with optimum velocities of only 28–32 cm/sec. This sacrifice in analysis speed generally makes nitrogen a poor choice unless the analysis speed is not a consideration.

• Helium’s efficiency is slightly reduced (HETP = 0.29mm); however, the optimum linear velocity increases to 58–62 cm/sec, reducing analysis time.

• Hydrogen, with an optimum linear velocity of 110–120 cm/sec, combines high column efficiency with analysis times almost four times faster than nitrogen and two times faster than helium. Linear velocities of hydrogen can reach 160 cm/sec with only a small decrease in column efficiency.

Fig. 4 illustrates chromatograms at optimal conditions for various carrier gases.

The optimum HETP and linear velocity for each carrier gas is summarized in Table 3. N2 generated the highest column efficiency, while He had the lowest. H2 had the highest linear velocity, which is approximately twice that of He. Considering that H2 can improve the linear velocity by a factor of two compared to He, it is also important to validate that separating similar components can be maintained. The calculated resolution between the C2 and C4 isomers (Table 4) illustrates that there is a slight sacrifice in resolution as the carriergas flowrate increased; however, the ability to quantitate similar components is not compromised.

This benefit was also validated using liquid hydrocarbons (Figs. 5 and 6). The liquid hydrocarbon mixture was analyzed using H2, He and N2 as carrier gases. H2 Ar 4.91 min shows a clear advantage by reducing analysis X: 1.0917 minutes time without performance loss. AdditionY: -0.180 mVolts ally, Peaks 3 and 4 were better resolved using H2 as the carrier gas. Peak 3, which is a ppm cyclopropane, elutes between percent levels of propane (60%) and propylene (40%), X: 6.2068 minutes making good separation very difficult.

Y: 0.000 mVolts Conclusion. When choosing a carrier gas,

He 2.11 min

X: 6.4487 minutes Y: 0.000 mVolts

1

FIG. 4

80

1.143

15 10 5 0

0.745 0.770 0.829 0.973 1.100

mVolts

2 1 WI: WI:

H2 1.16 min 2

X: 6.3643 minutes Y: 0.000 mVolts 3

4

5

6

Chromatograms at optimal conditions—Ar, N2, He and H2 as carrier gases. Elution order: Ethane, ethylene, propane, propylene, isobutene and n-butane.

I OCTOBER 2010 HYDROCARBON PROCESSING

there are advantages and disadvantages. It is important for the analyst to be aware of the available options. Cost, time savings, safety, performance and GC method development are key components in the decision-making process, some having a higher priority than others. N 2 provides a higher chromatographic efficiency than either He or H2 with significantly longer analysis times. He provides shorter analysis times compared to N2, along with the benefit that most GC methods were developed to use He as the

LAB ANALYZERS carrier gas. Using He is a good compromise between N2 or H2.

Significantly shorter analysis times are indeed possible using H2.

These shorter analysis times translate into significantly higher throughput for the lab. HP TABLE 2B. Liquid hydrocarbon mixture Ethane

200 ppm

Cyclopropane

200 ppm

Propane

60%

Isobutene

300 ppm

n-Butane

15 ppm

1-Butene

7 ppm

Cis-2-butene

7 ppm

Isobutylene

Balance

TABLE 3. HETP and linear velocity under optimized conditions HETP (mm)

Linear velocity cm/sec

0.22

28–31

N2

28–31 110–120

He

0.29

58–62

II-

II+ II2.989

0.24 0.28

2.238

Ar H2

4

2.911

2

II+

3.735

3

1

2

7 8 9

6

2 II- WI:

4 WI: FP+

4.711

5

6

2 WI: FP- WI:4I+ I

7

File: h: \2008\lab work\phase ii\helium\he-f25-10-2.run Channel: Front = FID results Last recalc: 9/10/2008 3:46 pm

4

1

3.1

3.1

H2

2.3

2.6

He

2.5

3

Tracey Jacksier is an international expert, and the research and development analysis and specialty gas program director, at Air Liquide based at the Research and Technology Center in Newark, Delaware. She is responsible for defining the worldwide development of key technologies in specialty gases, as well as recommending new analytical technologies within the Air Liquide Group. Ms. Jacksier has been with Air Liquide for more than 15 years. She received a BS degree from Purdue University and a PhD in physical chemistry from the University of Massachusetts. Ms. Jacksier has authored and co-authored more than 100 articles and technical presentations, and holds patents in the gas purification and standard manufacturing areas.

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5

5.660

3

4.600

2

X: 1.6203 minutes Y: -0.0530 mVolts 6

7 8 9

-1

FIG. 6

Ar

Advanced Piping Design

By Rutger Botermans and Peter Smith 250 pages • Hardcover • Pub date: May 2008 ISBN: 978-1-933762-18-0 • Price: $175

II-

5.951

0

1. Propane 2. Cyclopropane 3. Propylene 4. Isobutane 5. N-butane 6. 1-butene 7. Cis-2-butene 8. Isobutylene

2.924

mVolts

1

3

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8.418 8.784 8.979

5

2

4 Minutes

3.398

II+

3

2.8

Gas chromatogram obtained using H2 as the carrier gas— run time is 6.12 min.

FIG. 5

4

3

N2

X: 0.8677 minutes Y:-0.0480 mVolts

5

-1 1

RC4 Isomers

File: h: \2008\lab work\phase ii\h2\h2-f35-ramp-1.run Channel: Front = FID results Last recalc: 12/1/2008 11:32 am

3.997

1

0

RC2 Isomers

II-

4

2

3 mVolts

II+ II-

5.650 5.937 6.121

II+

Carrier gas

Yanyu (Jade) Duan is a research associate in the analysis group at Air Liquide’s research and development facility in the US. She is involved in various research and development activities across different entities, such as specialty gas, health care and air separation units. Ms. Duan received a BS degree in analytical chemistry from Shen Yang Institute of Technology, China and an MS degree in chemical engineering from Laval University, Canada. She is currently working on her MBA at the University of Delaware.

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Propylene

TABLE 4. Resolution of C2 and C4 isomers using various carrier gases

5.0 Minutes

7.5

10.0

Gas chromatogram obtained using He as the carrier gas— run time is 8.98 min.

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Brown brings to the company over 30 years of experience working in advertising sales in the UK and Europe. For the past several years, his advertising sales have been primarily in the oil and gas and chemical engineering sector for the UK and Europe.

Iris Yuen has been appointed as the new sales representative

Select 212 at www.HydrocarbonProcessing.com/RS

Bill Wageneck, Publisher 2 Greenway Plaza, Suite 1020 Houston, Texas, 77046 USA P.O. Box 2608 Houston, Texas 77252-2608 USA Phone: +1 (713) 529-4301, Fax: +1 (713) 520-4433 E-mail: Bill.Wageneck@GulfPub.com www.HydrocarbonProcessing.com

SALES OFFICES—NORTH AMERICA IL, LA, MO, OK, TX Josh Mayer 5930 Royal Lane, Suite 201, Dallas, TX 75230 Phone: +1 (972) 816-6745, Fax: +1 (972) 767-4442 E-mail: Josh.Mayer@GulfPub.com

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 2 Greenway Plaza, Suite 1020, Houston, Texas, 77046 Phone: +1 (713) 520-4449, Fax: +1 (713) 520-4459 E-mail: Laura.Kane@GulfPub.com

CT, DC, DE, MA, MD, ME, NC, NH, NJ, NY, OH, PA, RI, SC, VA, VT, WV, EASTERN CANADA Merrie Lynch 20 Park Plaza, Suite 517, Boston, MA 02116 Phone: +1 (617) 357-8190, Fax: +1 (617) 357-8194 Mobile: +1 (617) 594-4943 E-mail: Merrie.Lynch@GulfPub.com

DATA PRODUCTS AND CLASSIFIED SALES Lee Nichols Phone: +1 (713) 525-4626, Fax: +1 (713) 525-4631 E-mail: Lee.Nichols@GulfPub.com

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I OCTOBER 2010 HYDROCARBON PROCESSING

for World Oil and Hydrocarbon Processing magazines for China and Hong Kong. She worked for seven years as an advertising representative with ACT before starting her own agency, with offices in Shenzhen and Hong Kong. Previously, she was a Sales Representative with CSL Electronic Ltd. Yuen is fluent in Mandarin, Cantonese and English.

SALES OFFICES—EUROPE

SALES OFFICES—OTHER AREAS

FRANCE, GREECE, NORTH AFRICA, MIDDLE EAST, SPAIN, PORTUGAL, SOUTHERN BELGIUM, LUXEMBOURG, SWITZERLAND, GERMANY, AUSTRIA, TURKEY Catherine Watkins 30 rue Paul Vaillant Couturier 78114 Magny-les-Hameaux, France Tél.: +33 (0)1 30 47 92 51, Fax: +33 (0)1 30 47 92 40 E-mail: Watkins@GulfPub.com

AUSTRALIA—Perth Brian Arnold Phone: +61 (8) 9332-9839, Fax: +61 (8) 9313-6442 E-mail: Australia@GulfPub.com

ITALY, EASTERN EUROPE Fabio Potestá Mediapoint & Communications SRL Corte Lambruschini - Corso Buenos Aires, 8 5° Piano - Interno 7 16129 Genova - Italy Phone: +39 (010) 570-4948, Fax: +39 (010) 553-0088 E-mail: Fabio.Potesta@GulfPub.com

BRAZIL—São Paulo Alfred Bilyk Brazmedia Rua General Jardim, 633 Cj 61 01223 011 São Paulo SP, Brazil Phone: +55 (11) 3237-3269 Fax: +55 (11) 3237-3269 E-mail: Brazil@GulfPub.com

RUSSIA/FSU Lilia Fedotova Anik International & Co. Ltd. 10/2 Build. 1,B. Kharitonyevskii Lane 103062 Moscow, Russia Phone: +7 (495) 628-10-333 E-mail: Lilia.Fedotova@GulfPub.com UNITED KINGDOM/SCANDINAVIA, NORTHERN BELGIUM, THE NETHERLANDS Michael Brown 1 Ladythorn Crescent Bramhall Stockport Cheshire SK7 2HB, UK Phone: +44 161 440 0854, Mobile: +44 79866 34646 E-mail: Michael.Brown@GulfPub.com

CHINA—Hong Kong Iris Yuen Phone: +86 13802701367, (China) Phone: +852 69185500, (Hong Kong) E-mail: Iris.Yuen@GulfPub.com

JAPAN—Tokyo Yoshinori Ikeda Pacific Business Inc. Phone: +81 (3) 3661-6138, Fax: +81 (3) 3661-6139 E-mail: Japan@GulfPub.com INDONESIA, MALAYSIA, SINGAPORE, THAILAND Peggy Thay Publicitas Major Media (S) Pte Ltd Phone: +65 6836-2272, Fax: +65 6297-7302 E-mail: Singapore@GulfPub.com PAKISTAN—Karachi S. E. Ahmed Intermedia Communications Karachi-74700, Pakistan Phone: +92 (21) 663-4795, Fax: +92 (21) 663-4795

REPRINTS Phone: +1 (866) 879-9144 ext. 194 E-mail: rhondab@FosterPrinting.com

FREE Product and Service Information—OCTOBER 2010 HOW TO USE THE INDEX: 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 several ways readers can obtain information: 1. The quickest way to request information from an advertiser or about an editorial item is to go to www.

HydrocarbonProcessing.com/RS. If you follow the instructions on the screen your request will be forwarded for immediate action.

2. Go online to the advertiser's Website listed below.

3. Circle the Reader Service Number below and fax this page to +1 (416) 620-9790. Include your name, company, complete address, phone number, fax number and e-mail address, and check the box on the right for your division of industry and job title.

Name ________________________________________________________

Company ________________________________________________________

Address ______________________________________________________

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Phone No. _______________________________________________________

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This Advertisers’ Index and procedure for securing additional information is provided as a service to Hydrocarbon Processing advertisers and a convenience to our readers. Gulf Publishing Co. is not responsible for omissions or errors.

This information must be provided to process your request: PRIMARY DIVISION OF INDUSTRY (check one only): A B C F G H J P

䊐-Refining Company 䊐-Petrochemical Co. 䊐-Gas Processing Co. 䊐-Equipment Manufacturer 䊐-Supply Company 䊐-Service Company 䊐-Chemical Co. 䊐-Engrg./Construction Co.

JOB FUNCTION (check one only): B E F G I J

䊐-Company Official, Manager 䊐-Engineer or Consultant 䊐-Supt. or Asst. 䊐-Foreman or Asst. 䊐-Chemist 䊐-Purchasing Agt.

ADVERTISERS in this issue of HYDROCARBON PROCESSING Company Website

Page

RS#

ABV Energy SpA . . . . . . . . . . . . . . . . 23 (154) Ametek Process Instruments . . . . . . . 40 (162) (53)

Bryan Research & Engineering . . . . . . 20 (113) Cudd Energy Services . . . . . . . . . . . . 38 (161) (76) (65)

Webcast—ITT . . . . . . . . . . . . . . . . 56 (167)

Paharpur Cooling Towers, Ltd. . . . . . . 57

(77)

Paratherm Corporation . . . . . . . . . . . 26 (155)

Parker Hannifin Corporation . . . . . . . 47 (166) www.info.hotims.com/29424-166

Samson GmbH . . . . . . . . . . . . . . . . . . 4 (151)

Haver & Boecker . . . . . . . . . . . . . . . . 33 (158)

www.info.hotims.com/29424-151

Spraying Systems Co.. . . . . . . . . . . . . 87 (79)

(62)

www.info.hotims.com/29424-62

Swagelok Co. . . . . . . . . . . . . . . . . . . 14

HPI Marketplace . . . . . . . . . . . . . 82–84 Hunter Buildings . . . . . . . . . . . . . . . . 18 (152)

www.info.hotims.com/29424-65

Flexim Americas Corp. . . . . . . . . . . . . 32 (157) (93)

www.info.hotims.com/29424-170

KBC Advanced Technologies Inc . . . . . 58

www.info.hotims.com/29424-93

(84)

www.info.hotims.com/29424-84

Grabner Instruments . . . . . . . . . . . . . 52 (164) www.info.hotims.com/29424-164

Gulf Publishing Company Construction Boxscore . . . . . . . . . . 27 (156) www.info.hotims.com/29424-156

European Turnaround Showcase . . . 78 (177) www.info.hotims.com/29424-177

Event—IRPC . . . . . . . . . . . . . . . . . 72 (174)

(82)

KBR . . . . . . . . . . . . . . . . . . . . . . . . . 10 www.info.hotims.com/29424-83

Linde Process Plants . . . . . . . . . . . . . 12

(81)

www.info.hotims.com/29424-81

M3 Technology . . . . . . . . . . . . . . . . . 36 (160) www.info.hotims.com/29424-160

Mangiarotti SpA . . . . . . . . . . . . . . . . 55 (165) www.info.hotims.com/29424-165

Merichem Company . . . . . . . . . . . . . 34 (159) www.info.hotims.com/29424-159

www.info.hotims.com/29424-174

MSA Instrument Division . . . . . . . . . . 67

Event—WGLC . . . . . . . . . . . . . . . . 75 (175)

Ohmart/Vega . . . . . . . . . . . . . . . . . . 63 (169) www.info.hotims.com/29424-169

(89)

www.info.hotims.com/29424-89

Unifrax . . . . . . . . . . . . . . . . . . . . . . . 24 (83)

(97)

www.info.hotims.com/29424-97

Tyco Thermal Controls . . . . . . . . . . . . 16

www.info.hotims.com/29424-82

(63)

www.info.hotims.com/29424-63

Thermo Fisher Scientific . . . . . . . . . . . . 6

www.info.hotims.com/29424-152

Idrojet . . . . . . . . . . . . . . . . . . . . . . . . 64 (170)

www.info.hotims.com/29424-157

www.info.hotims.com/29424-175 . . . . . .

RS#

www.info.hotims.com/29424-155

Webcast—Heinz . . . . . . . . . . . . . . 69 (173)

Honeywell Analytics. . . . . . . . . . . . . . . 8

Page

www.info.hotims.com/29424-79

www.info.hotims.com/29424-76

Garlock Sealing Technologies . . . . . . . 22

HPI Market Data Book . . . . . . . . . . 68 (172)

www.info.hotims.com/29424-158

www.info.hotims.com/29424-161

Company Website

www.info.hotims.com/29424-77

www.info.hotims.com/29424-167

www.info.hotims.com/29424-113

Flexitallic LP . . . . . . . . . . . . . . . . . . . . 5

GPC Books . . . . . . . . . . . . . . . . . . . 81 (176)

www.info.hotims.com/29424-173

www.info.hotims.com/29424-53

Emerson Process Management . . 44–45

RS#

www.info.hotims.com/29424-172

www.info.hotims.com/29424-162

Curtiss-Wright Flow Control Corp . . . . 2

Page

www.info.hotims.com/29424-176

www.info.hotims.com/29424-154

Axens . . . . . . . . . . . . . . . . . . . . . . . . 88

Company Website

(68)

www.info.hotims.com/29424-68

United Laboratories International, Llc/Zyme-Flow . . . . . . . . . . . . . . . . 19 (153) www.info.hotims.com/29424-153

Veolia Environment . . . . . . . . . . . . . . 48 Vize, An Ohmart/Vega Company . . . . 60 (168) www.info.hotims.com/29424-168

Weka Ag . . . . . . . . . . . . . . . . . . . . . . 51 (163) www.info.hotims.com/29424-163

Yokogawa Corporation Of America . . 28

(74)

www.info.hotims.com/29424-74

For information about subscribing to HYDROCARBON PROCESSING, please visit www.HydrocarbonProcessing.com HYDROCARBON PROCESSING OCTOBER 2010

I 85

HPIN WATER MANAGEMENT LORAINE A. HUCHLER, CONTRIBUTING EDITOR Huchler@martechsystems.com

Utility water boot camp for process engineers—Part 2 In Part 2, we will address the slowly developing problems in utility water systems. Too often, water-plant problems evolve slowly.

Plant personnel fail to detect the non-conformances and failures occur with no clear causal events. Table 2 lists some examples of slowly developing problems.

The obvious method to detect these slowly developing problems is to conduct frequent reviews of historical data for water chemistry and performance test results, identify non-conformances and implement the proper corrective actions. Examples of data reviews includes trend data for conformance to specification limits of the boiler and cooling water systems and weekly inspections of the appearance of the cooling tower basin, pump inlet screens and hot deck.

Normalization of deviance. However, engineers, operators and even managers often accept non-conforming data and performance that does not conform to the established standards—they create a culture of “Normalization of Deviance.” Sociologist Diane Vaughan wrote a book about the Challenger launch decision process1 and coined the term “Normalization of Deviance” to explain the root causes of the Challenger failure. Colonel Mike Mullane, a shuttle astronaut, defines Normalization of Deviance as “. . . . the working or mission environment created when established standards are subverted incrementally over time without consequence, by routinely rewarding shortcuts from the established norm. As team members continue this practice (normalization),

it leads to ‘predictable surprise’, incursion of risk, technical failure, and in the worst cases, complete and catastrophic failure and loss of property and life.”

Engineers and their managers should consider the consequences of accepting non-conformance and creating an environment of “normalization of deviance” in their plants. HP Next month: Typical utility process engineer responsibilities.

Plants make the utility process engineer responsible for the central water plant and utility boilers, but the process engineers assigned to each unit are responsible for their utility water systems such as cooling towers and condensate return systems. Next month, we will discuss the typical responsibilities of a utility process engineer to managing their systems and interfacing with process engineers at all other units within the plant.

NOTES D., The Challenger Launch Decision: Risky Technology, Culture, and Deviance at NASA, University of Chicago Press, April 1997.

1Vaughan,

The author is president of MarTech Systems, Inc., an engineering consulting firm that provides technical services to optimize water-related systems (steam, cooling and wastewater) in refineries and petrochemical plants. She holds a BS degree in chemical engineering and is a licensed professional engineer in New Jersey and Maryland. She can be reached at: huchler@martechsystems.com.

TABLE 2. Slowly developing problems in utilities systems Symptom

Possible root causes

Recommended actions

Pitting corrosion on heat exchanger

• Inadequate anodic inhibitor concentration

• Supplement corrosion monitoring program with instantaneous

(HX) as shown by carbon steel

• Galvanic corrosion (copper alloy corrosion from high

corrosion coupons

free chlorine or loss of azole corrosion inhibitor) • Intermittent low pH (below 6.8)

corrosion meter • Review historical trend data to detect nonconformances to specification limits (poor control), especially during the first five days of the coupon test period

High planktonic microbiological

• Process leak

• Review historical biocide concentrations and feedrates

populations

• Biocide feed interruption

• Conduct volatile hydrocarbon tests (TLV)

• High turbidity (suspended solids) in cooling water

• Test sludge for anaerobic bacteria

• Condensate corrosion due to:

• Measure condensate quality at boundary limits of each

High boiler feedwater iron concentrations

• Low pH

unit to determine location of problem

• Dissolved oxygen • Process intrusion High boiler feedwater

• Poor softener or demineralizer operation

(condensate + makeup)

• Condensate contamination (surface condenser)

total hardness

• Undetected feedwater heater or pump seal leak

86

I OCTOBER 2010 HYDROCARBON PROCESSING

• Hardness deposits will cause long-term overheat failures in boiler tubes

Spray Nozzles

Spray Analysis

Spray Control

Spray Fabrication

Why Leading Refineries and Engineering Firms Rely on Us for Injectors and Quills

Retractable Injector, Slurry Backflush Quill, Water Wash Quill (bottom to top)

Water-Jacketed Injector for High-Temperature Applications Computational Fluid Dynamics (CFD)

Manufacturing quality and flexibility.

Need a simple quill or multi-nozzle injector? Insertion length of a few inches or several feet? 25# or 2500# class flange? High-pressure, high-temperature and/or corrosion-resistant construction? Special design features like a water-jacket, air purge or easy retraction for maintenance? Tell us what you need and we’ll design and manufacture to your specifications and meet B31.1, B33.3 and CRN (Canadian Registration Number) requirements.

CFD shows the change in drop size based on nozzle placement in the duct.

D32 (μm) 220

165

Z = 0.6 m

Nozzle spraying in-line with duct

Proven track record.

We’ve manufactured hundreds of injectors for water wash, slurry backflush, feed and additive injection, SNCR and SCR NOx control, desuperheating and more. Customers include Jacobs Engineering, Foster Wheeler Corp, Shaw Group, Conoco Phillips Co, Shell, Valero and dozens more.

Learn More at spray.com/injectors Visit our web site for helpful literature on key considerations in injector and quill design and guidelines for optimizing performance.

110

55 0

Design validation with process modeling.

Let us simulate the injection environment to identify potential problems. We can model gas flow, droplet trajectory and velocity, atomization, heat transfer, thermal stresses, vibration and more to ensure optimal performance.

Nozzle spraying at 45° in duct

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Select 62 at www.HydrocarbonProcessing.com/RS

Specify and order standard nozzles spray.com/ispray

Your objectives in focus Make the most of today’s and tomorrow’s challenges with leading-edge solutions from Axens - Clean and alternative fuel technologies - Petrochemicals - Energy efficiency - High performance catalysts & adsorbents - Revamps

Single source technology and service provider ISO 9001 – ISO 14001 – OHSAS 18001 www.axens.net Select 53 at www.HydrocarbonProcessing.com/RS

2010

EUROPEAN DIRECTORY

Supplement to:

Compressors and Service from the OEM

Customer Support Service â&#x20AC;&#x201C; The Full Range for All Your Reciprocating Compressors Valve Service U Engineering Services U Field Service Spare Parts Logistics U Technical Support U Component Repair Revamps U Training U Condition Monitoring & Diagnostics Sustainable Reduction of Your Operating Cost with Our Leading OEM Specialists and Compressor Technology

Contact us: www.burckhardtcompression.com /contacts info@burckhardtcompression.com

Select 301 at www.HydrocarbonProcessing.com/RS

2010

EUROPEAN DIRECTORY Table of Contents

5

Provider Directory

12

Provider Product Directory

17

Product /Service Directory

Listing of service providers, contractors and equipment vendors for turnaround and maintenance needs.

Listing of products and services for turnaround and maintenance needs by service providers, contractors and equipment vendors

Listing of products and services for turnaround and maintenance needs.

Published by Hydrocarbon Processing® Front cover: Industrial Insulation Group: your insulation partner for a safer workplace and world. Products for industrial high temperature applications include Thermo-12 Gold™ Calcium Silicate, Sproule WSR-1200™ Perlite, and Minwool-1200 pipe, board and blanket insulations. Commercial MinWool products address thermal, acoustical and fire protection applications. Photo courtesy of Industrial Insulation Group.

Copyright © 2010 Gulf Publishing Company, Houston, Texas. All rights reserved. Printed in USA.

For information on additional copies and advertising in the 2011 edition, please contact: Bill Wageneck (713) 520-4421 Bill.Wageneck @gulfpub.com

Select 302 at www.HydrocarbonProcessing.com/RS

Provider Directory chemical industry, refineries, power stations as well as for the oil and gas industry.

A

AMETEK, CALIBRATION INSTRUMENTS

ALSTOM POWER, AIR PREHEATER COMPANY

8600 Somerset Drive Largo, FL 33773 United States Scott Crone Phone: 1-727-536-7831 Phone: 1-800-527-9999 Fax: 1-727-539-6882 cal.info@ametek.com www.jofra.com

Raymond Operations 4525 Weaver Parkway, Suite 250 Warrenville, IL 60555 United States Dave Dahlstrom Phone: 1-630-393-1000 AMETEK Calibration Instruments. We Fax: 1-630-393-1001 info@airpreheatercompany.com are one of the leading manufactures and developers of calibration instruments for www.airpreheatercompany.com temperature, pressure and process sigAlstom Power, Inc., Air Preheater Company, Raymond Operations is a leading supplier of engineered products, services and technologies for size reduction, classification and thermal processing.

Bartlett-Snow and Raymond equipment is known for its quality and performance, and is supported by our technical staff, pilot plant testing facility, OEM replacement parts and service departments.

Bartlett-Snow rotary calciners, kilns, dryers and coolers, and Raymond flash drying equipment/systems provide solutions for thermal processing applications worldwide. The Raymond size reduction product line includes equipment and systems for pendulum roller mills, impact mills, vertical hammer mills, table roller mills, jet-stream and hybrid turbine classifiers. Raymond Operations has been in operations since 1885 and was consolidated into the Air Preheater Company in 1995. The Air Preheater Company began its core operation in the production of regenerative air preheaters in Wellsville, New York in 1925 and today is a leader in the development of energy recovery and auxiliary products for power generation and industrial processing equipment.

The operation has approximately 700 employees, and is owned by ALSTOM, a full service provider of power generation and transportation services and equipment, with headquarters in Paris, France and employing over 69,000 people in 70 countries. The Air Preheater Company has manufacturing plants in Wellsville, New York, Concordia, Kansas, and Vinhedo, Brazil, as well as a research and development facilities in Wellsville and a 25,000 square foot pilot plant testing facility in Naperville, Illinois.

nals as well as for temperature sensors both from a commercial and a technological point of view.

B BORSIG GMBH BORSIG GmbH 13507 Berlin Germany Phone: 49-30-4301-01 info@borsig.de www.borsig.de BORSIG Group, member of KNM Group Berhad, offers customized solutions for pressure vessels, heat exchangers, membrane technology, compressors, boiler and power plant technology as well as comprehensive power plant and industrial services.

The companies • BORSIG GmbH • BORSIG Process Heat Exchanger GmbH • BORSIG Membrane Technology GmbH • BORSIG ZM Compression GmbH • BORSIG Boiler Systems GmbH • BORSIG Service GmbH and their products are synonymous for top quality, reliability and optimum technical implementation.

The BORSIG Group - innovative solutions, state-of-the-art technology, perfectly trained specialists and comprehensive know-how are the basis for our position as a “”single source”” supplier of leading technology.

The BORSIG Group offers customised solutions for the chemical and petroEUROPEAN TURNAROUND

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BUCHEN-ICS INDUSTRIALCATALYST-SERVICE GMBH Emdener Str. 278 50735 Cologne Germany Frauke Ellinghaus Phone: 49-221-7177-202 Fax: 49-221-7177-374 RED@buchen-ics.com www.buchen-ics.com BUCHEN-ICS Industrial-CatalystService has been developing during the last 30 years to become the largest European service provider in the field of catalyst handling and mechanical work for the international (petro) chemical industry as well as for the oil and natural gas processing industry.

We accomplish all the tasks expected of a modern service provider to major industries: total shutdown management; plant preparation; catalyst replacement with high performance vacuum and screening units and individual loading procedures; mechanical works (e.g. welding works, removal and installation of complete reactor internals, neutralisation of internals, camera inspection of internals); regeneration (turnaround regeneration, double change catalyst charge); recycling (of high-quality spent catalyst and disposal of unusable spent catalyst); transport and logistics.

All reactor works are carried out under nitrogen atmosphere and our complete equipment, including our own certified (CE 0158) LSS Life Support System (breathing protection system) based on a NASA development, is designed for nitrogen operations and handling with auto-combustible material.

Quality, safety, health and environment protection are firmly fixed components of our corporate philosophy.

This means it is a matter of course that our group of companies is certified in all prevalent QSHE standards and—far more important—that all work for our clients is carried out in line with these requirements. In order to provide these requirements we create risk assessments, carry out project-related toolbox meetings, make site tours and project documentation. Our more than 300 own local catalyst handling specialists

M A I N T E N A N C E S E R V I C E S D I R E C TO RY 2010

5

Provider Directory are medically assessed in regular intervals and educated and trained to the same firmly fixed principles.

pressor systems, also for other brand compressors: • Valve service • Spare parts logistic • Field service • Technical support • Component repair • Engineering services • Revamps • Training • Condition monitoring & diagnostics

Since 1979 BUCHEN-ICS has been grown up to a group of 13 companies so that we are available to our clients with local staff and equipment on-site at extremely short notice throughout Europe 365 days a year.

BURCKHARDT COMPRESSION AG

BW TECHNOLOGIES BY HONEYWELL

Im Link 5 CH-8404 Winterthur Zurich Switzerland Manfred Straessler Phone: 41-52-262-73-66 Fax: 41-52-262-00-53 info@burckhardt compression.com www.burckhardt compression.com

3279 West Pioneer Parkway Arlington, TX 76013 United States Phone: 1-888-749-8878 Phone: 1-817-274-2487 Fax: 1-817-274-8321 info@gasmonitors.com www.gasmonitors.com

Burckhardt Compression is one of the market leaders in the field of reciprocating compressor technology and the only manufacturer that offers a complete range of Laby® (labyrinth piston), Process Gas, and Hyper Compressors.

These compressors are used in a wide range of applications in the chemical and petrochemical industry, in refineries, in air separation systems, and for gas transport and storage.

For us as a leading compressor manufacturer, it is of big importance that your reciprocating compressors operate efficiently and reliably for a very long time. Therefore, we offer the full range of customer support services for all reciprocating compressor systems.

BW Technologies by Honeywell is committed to becoming the industry leader in the design, manufacturing, and marketing of gas detection equipment for the protection of working personnel and facilities. Since its inception in 1987, BW has created technically advanced products to meet safety needs for the industrial and Municipal markets.

C CB&I

One CB&I Plaza 2103 Research Forest Drive The Woodlands, TX 77380 United States Our specialists have an extensive OEM Kathleen Wehr know-how and experience in all specific Phone: 1-832-513-1209 fields of compression technology. This Fax: 1-832-513-1505 enables us to support you for demanding turnarounds@CBI.com applications handling cryogenic, abrasive, corrosive, toxic or explosive gases and for www.cbi.com applications with very high pressures up to 3500 bar. With our in-house engineering and manufacturing expertise and the state-of-the-art analysis tools we guarantee maximum efficiency and durability for our solutions.

Backed by our worldwide service network we strive to serve you as quick as possible during 24 hours a day, 7 days a week.

We support you with the full range of services for all reciprocating com6

EUROPEAN TURNAROUND

AND

CB&I has provided safe and dependable turnkey revamp, debottlenecking and upgrade services to the petroleum industry for more than a half a century.

We specialize in capital improvement projects executed on an accelerated schedule basis. Because we have successfully completed hundreds of revamps and upgrades worldwide, we understand the critical impact these projects have on our customers business.

M A I N T E N A N C E S E R V I C E S D I R E C TO RY 2010

D DAMPNEY COMPANY INC. 85 Paris St Everett, MA 02149 United States Dennis Aikman Phone: 1-617-389-2805 sales@dampney.com www.dampney.com Since 1917, Dampney Company, Inc has designed, developed, manufactured, and distributed engineered coating systems for specialized applications.

Dampney serves the petroleum refining, chemical processing, oil & gas, pipeline, power, OEM, pulp & paper, and materials processing markets. Today Dampney is a world class leader supplying high-performance, high temperature solutions throughout the world.

Dampney continues to develop and improve industry’s choice of innovative, right-the-first-time coating systems for protection against hostile environments in atmospheric, immersion, and underground applications.

DELTA VALVE 857 West, South Jordan Parkway, Suite 100 South Jordan, UT 84095 United States Steven Wilkie Phone: 1-801-984-1000 Fax: 1-801-984-1001 swilkie@deltavalve.com www.deltavalve.com DeltaValve is a world leader in delayed coking solutions for the Petroleum Refining Industry. The company designs, engineers, and manufactures industrial products for that market segment.

It’s flagship product-—the DeltaGuard Unheading Device—has quickly become the new worldwide standard in coke drum unheading, offering an inherently safe, reliable, and easy-to-operate unheading solution. The DeltaGuard unheading device is a fully enclosed unheading system which completely isolates personnel and equipment from coke-drum fallout and other hazards associated with the unheading process.

DeltaValve is a business unit of CurtissWright Flow Control Company and is located in South Jordan, Utah.

Provider Directory

E EDGEN MURRAY 18444 Highland Road Baton Rouge, LA 70809 United States Jennifer dAquin Phone: 1-225-756-9868 Fax: 1-225-756-7953 info@edgenmurray.com www.edgenmurray.com

Elliott Services: • Emergency call-out service • On-site repair: machining, weld repair, sandblasting, balancing • Installation and commissioning • Machine Overhauls • Laser/optical alignment • On-site troubleshooting, analysis and technical advice • Project management • Resource planning and subcontractor control • Resident engineers • Operator and maintenance training • Call-off contracts • Long-term maintenance agreements • Relocation of used equipment • Repair and remanufacture of blades, impellers, diaphragms, seals, bearings, etc.

• CNC machining • Vacuum heat treating • Parts fabrication • Dynamic balancing • Protective coating • Equipment upgrades, regardless of original manufacture

Edgen Murray, headquartered in Baton Rouge, La., is an international distributor of high performance steel and alloy products manufactured for use in specialized applications throughout the hydrocarbon chain, energy infrastructure, and individual industrial segments. Offering technical expertise and customized solutions for unique project requirements, the company has a source-to-delivery global logistics platform. With a broad base of customers across every sector in the energy value chain, Edgen Murray’s Changes in operating requirements do worldwide operations span four geographical regions including the Americas, not necessarily require new equipment.

Upgrades and modifications to bearing Europe, Middle East, and Asia-Pacific. designs, seals and controls, or a complete rerating of a machine to meet new proELLIOTT TURBOMACHINERY SA cess requirements enhances performance Feldstrasse 2 and extends equipment life.

CH 8853 Lachen Switzerland Marco Van Schaik Phone: 41-55-451-8000 Fax: 41-55-451-8099 mvanschaik@elliott-turbo.com www.elliott-turbo.com

For over 40 years customers have relied upon Elliott for maintenance, repairs and parts for Elliott and nonElliott turbomachinery. We are truly a “one-stop” organization for high quality service, 24 hours per day, seven days per week. The aim of every plant manager and maintenance engineer is to ensure maximum reliability and life span for their rotating machinery. Elliott’s goal is to ensure the efficient, trouble free operation of all critical turbomachinery, regardless of the original manufacturer.

The resources of the Elliott Group – in Europe, the Middle East, Africa, and throughout the world – provide timehonored service excellence.

variety of metal and fabric joints. It serves companies in the refining, petrochemical, power/utility, OEM, water/wastewater, boiler petrochemicals and other industries. For nearly three decades, EJS has been dedicated to providing high quality products at competitive prices. EJS offers its customers highly engineered metal bellows and fabric expansion joints, standard expansion joints, field services and piping analysis by PAI. Our specialty expansion joints include: FCCU, Gas Turbine Exhaust Units, Penetration/ Boiler Seals, ASME Code joints, toroid expansion joints, high temperature fabric assemblies, silencer bellows seals, bellows for aerospace, cryogenic and LNG applications. All EJS manufacturing facilities are ASME/PED certified. We are an active member of the Expansion Joint Manufacturers Association as well as a UOP approved manufacturer. Using state of the art technology and equipment, our engineering team incorporates Finite Element Analysis and 3D design software as a standard part of our design process.

EJS is available 24 hours a day, 7 days a week. Emergency and on-site services are available.

F FABENCO, INC.

2002 Karbach Houston, TX 77092 United States David LaCook Scott Friedman Sandi Coles Phone: 1-713-686-6620 We supply parts for virtually all rotating equipment manufactured by other suppli- Phone: 1-800-962-6111 1-713-688-8031 ers. If necessary we can reverse engineer Fax: parts for non-Elliott machinery, and as is cec@safetygate.com often the case, apply engineering compe- www.safetygate.com/gw Typical modifications include: • Bearing redesign and retrofits • Dry gas seals retrofits • Electronic governor systems • Digital control systems • Vibration and temperature monitors • Anti-surge controls

tencies to make improvements.

EXPANSION JOINT SYSTEMS, INC. 10035 Prospect Ave, Suite 202 Santee, CA 92071 United States Kathy Tyson Phone: 1-619-562-6083 Fax: 1-619-562-0636 sales@ejsus.com www.ejsus.com As one of the world’s leading expansion joint manufacturers, Expansion Joint Systems, Inc. (EJS) supplies a wide EUROPEAN TURNAROUND

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The FabEnCo Self-Closing Safety Gate is an adjustable swinging gate for fall protection at your ladder, platform and stair openings, or catwalks, mezzanines and machine guarding. It can be clamped on either side of the handrail, at different levels, and mounts on channel, angle, flatbar or pipe. Our adjustment bolts provide positive stop without handrail contact. Shipped complete with hardware, the Safety Gate can be installed quickly on most handrails or to existing walls. Available in galvanized steel (Safety Yellow optional), aluminum and stainless steel.

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Provider Directory components and systems, including quick-disconnect couplers, fluid power 6915 Hwy 225 accessories, leak testing equipment, shock absorbers, tubing, industrial and Deer Park, TX 77536 instrumentation valves and many more.

United States We represent the finest manufacturBarry Dubbin ing companies in the industry: Parker Phone: 1-281-604-2400 Hannifin, Schrader Bellows, Valvair II Air Fax: 1-281-604-2415 Valves, Camozzi, Flairline, Bray Controls, Baldor Motors, Arrow Pneumatics, Hex JLenahan@flexitallic.com Valve, Sharpe Valves, Whitman Controls, www.flexitallic.com Dwyer Flowmeters, Weiss Instruments, The Flexitallic Group is the internaAMSOIL Lubricants, AIRTROL, Coilhose tional market leader in the manufacture Pneumatics and many others. and supply of high quality, high value industrial static sealing products. Based on sales and geographic reach, The Flexitallic Group has become a global supplier of industrial gaskets. Developer HOERBIGER of the spiral wound gasket in 1912 KOMPRESSORTECHNIK HOLDING in the US, Flexitallic today continues its legacy of innovation with product G MBH materials like Thermiculite® and Tech Gate Tower, Floor 14-16 Sigma®. Flexitallic’s sheet materials product lines began in the mid 1800’s Donau-City-Straße 1 in England. Flexitallic is a privately held A-1220 Vienna company headquartered in Houston, Austria Texas USA. Flexitallic’s global customer 43-1-22-440-0 service network of owned manufactur- Phone: info-hkth-marketing@ ing facilities, manufacturing licensees and distribution network (over 750 dishoerbiger.com tributors in 30 countries) ensure local www.hoerbiger.com demand is met quickly, with a combinaHOERBIGER Compression Technology tion of the highest product quality and is a business unit of HOERBIGER customer service.

Holding AG, Zug / Switzerland. The HOERBIGER Group is active throughout the world as a leading player in the fields of compression technology, automation technology, and drive techGRACE TECHNOLOGIES , INC. nology. Its 6,400 employees achieved 16613 W Hardy sales of around 1 billion Euros. The focal points of its business activities Houston, TX 77060 include key components and services United States for compressors, gas-powered engines, Mark Grace and turbomachinery, hydraulic systems Phone: 1-281-873-8633 and piezo technology for vehicles and Phone: 1-800-873-4247 machine tools, as well as components and systems for shift and clutch operaFax: 1-281-873-9329 tions in vehicle drive trains of all kinds. mgrace3101@aol.com Through innovations in attractive techwww.gracetechnologies.com nological niche markets, the HOERBIGER Grace Technologies is your comGroup sets standards and creates highplete pneumatics distributor. Grace quality unique selling propositions with Technologies offers a unique comlong-term benefit for the customer. bination of industrial, hydraulic and pneumatic products and services for the fluid power industries. We are a full line stocking distributor specializing in air cylinders, air dryers, actuators, air and hydraulic compressors, air and hydraulic cylinders, fittings, hydraulic and pneumatic process equipment, industrial controls and automation

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HRI, INC. 1726 N. Ash PO Box 500 Buffalo, MO 65622 United States Curt Rankin Phone: 1-417-345-8019 Fax: 1-417-345-8398 hightemp@hightempinc.com www.hightempinc.com HRI, Inc. is a small international consulting firm that specializes in helping our clients complete maintenance, repairs and inspections of equipment in high heat environments.

I INDUSTRIAL SCIENTIFIC CORPORATION 1001 Oakdale Road Oakdale, PA United States Chris Lange Phone: 1-412-788-4353 Phone: 1-800-338-3287 Fax: 1-412-788-8353 info@indsci.com http://www.indsci.com Industrial Scientific designs, manufactures and markets portable and fixed instruments and services for detecting, measuring and monitoring hazardous gases to protect and preserve life and property. Headquartered in an advanced ISO 9001:2000-certified facility near the Pittsburgh International Airport, Industrial Scientific provides equipment that is used for safety and industrial hygiene in potentially dangerous locations. The Company’s products range from hand-held / portable instruments capable of monitoring from one to six gases, to permanently installed systems capable of monitoring many different gases in hundreds of locations from a central monitoring station. The products carry third-party intrinsic safety and performance approvals and are used in industrial, municipal and commercial applications. Through technical breakthroughs, perseverance in product development and rigorous in-house product testing, Industrial Scientific has become the name for the most rugged and dependable gas instrumentation on the market. Employing over 850 people,

Provider Directory Industrial Scientific has manufacturing operations based in Pittsburgh (USA), Arras (France), Dortmund (Germany) and Shanghai (China), provides technical services to customers from local service centers around the world, and has additional subsidiaries in Australia, Canada, Czech Republic, Dubai, Germany, The Netherlands, Singapore, Switzerland and the United Kingdom. Industrial Scientific is dedicated to preserving life and property by providing highest quality products around the world.

INNOVATIVE TURNAROUND CONTROLS 3512 Fairmont Parkway Pasadena, TX 77504 United States Jim Hilliard Phone: 1-713-213-2324 Fax: 1-281-998-9437 jim.hillard@turnaround controls.com http://www.turnaround controls.com ITC a world leader in Project Services and Project Controls, supplying Cost Engineers, Schedulers, Planners, Coordinators, Project Manager’s, and Turnaround Managers.

K KBC ADVANCED TECHNOLOGIES, INC. 14701 St. Marys Lane Suite 300 Houston, TX 77079 United States Joe Davis Phone: 1-281-293-8200 Fax: 1-281-293-8290 salesinfo@kbcat.com http://www.kbcat.com/ KBC is a leading independent global consulting organization serving owners and operators in the oil refining, petrochemical and other process industries. KBC’s Reliability, Availability and Maintenance (RAM) division is built on real-world operations and maintenance expertise, allowing our group to review, recommend, and implement superior operational solutions. We focus on providing sustainable competitive advan-

tage while safely and cost-effectively delivering increased value to your shareholders.

NDTRAK

KTI CORP 1990 Post Oak Blvd, Ste 200 Houston, TX 77056 United States Chris Eley Phone: 1-281-249-2443 Fax: 1-281-249-2328 sales@kticorp.com http://www.kticorp.com KTI provides engineering, design, procurement and construction services for all types of fired heaters including specialized applications such as Steam Reformers and EDC Pyrolysis Furnaces.

We offer Nox reduction through a variety of technologies including LoNOx burner retrofits and Selective Catalytic Reduction (SCR) Units. KTI specializes in fast-track emergency rebuilds of fire damaged heaters and revamp of existing units for capacity or efficiency improvement.

930 Gemini Street Houston, TX 77058 United States Rob Albright Phone: 1-281-990-0284 Fax: 1-281-990-0264 ralbright@ndtrak.com www.paragonintegrity.com Paragon Integrity Solutions, LLC is in the business of assessing the mechanical integrity of oil and natural gas production, processing and transportation facilities. We use state of the art testing tools such as ultrasonic phased array units and infrared fugitive gas cameras to inspect equipment while in service with very minimum interference with ongoing operations.

P PETROBLAST LEASING

M MAN TURBO AG Steinbrinkstrasse 1 46145 Oberhausen Germany Phone: 49-208-692-2347 stephanie.schneider@man.eu www.manturbo.com MAN Turbo offers the world’s most comprehensive product line of compressors and turbines. MAN Turbo embodies the experience of five major OEM companies. 250 years of made-tomeasure solutions from one manufacturer – from single machines to turnkey machine sets. Innovation, ongoing development and modern technology guarantee the competitiveness of our products (single source solutions) for the lifetime of a machine.

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1148 East Texas Avenue P.O. Box 809 Rayne, LA 70578 United States Phone: 1-337-735-9245 Phone: 1-866-334-1904 Fax: 1-337-735-9243 info@petroblastleasing.com www.blastresistantbuildings.com PetroBlast Leasing (PBL) is the largest leasor of fully compliant blastresistant buildings in the world. PBL provides a Manufacturer’s Data Report on all buildings. This Mechanical Integrity documentation includes supporting information on engineering certification documentation, material certification documentation, and fabrication process documentation. PBL’s has developed standard building sizes of 12’ x 40’ and 14’ x 40’ and standard blast ratings of 5psi, 200 ms, medium damage and 8psi, 200 ms, medium damage. PBL has built its reputation on mechanical integrity, experience, knowledge and customer service. With an increasing number of buildings being placed into the fleet on a daily basis, PBL is steadily expanding to better meet the industry’s growing needs. Contact us about guaranteed availability.

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RAE SYSTEMS, INC.

SMITHCO ENGINEERING

TAPCOENPRO INTERNATIONAL

3775 N 1st San Jose, CA 95134 United States Ray Dauterive Phone: 1-281-222-3621 Phone: 1-877-723-2878 Fax: 1-408-952-8480 rdauterive@raesystems.com www.raesystems.com

6312 S. 39th West Ave. Tulsa, OK 74132 United States Jim Matthews Phone: 1-918-446-4406 Fax: 1-918-445-2857 info@smithco-eng.com www.smithco-eng.com

16315 Market Street Channelview, TX 77530 United States Lee Treichel Phone: 1-281-452-5865 Fax: 1-281-452-5251 ltreichel@curtisswright.com www.tapcoenpro.com/index.htm

Smithco Engineering, together with its Amercool Division, designs, manufactures and delivers a comprehensive range of custom-built air-cooled heat exchangers, including forced and induced draft, vertical and horizontal, motor or engine driven, and high pressure applications.

We’ve installed air coolers from the North Pole to South America, and all around the world.

With more than 50 years of process control experience, TapcoEnpro International today is know as the industry’s most sophisticated and successful supplier of engineered solutions yet TapcoEnpro never allows itself to become totally satisfied with yesterday’s accepted standards for conducting business. Your single source for products and services you need, when you need them With sales and service representation worldwide, TapcoEnpro offers customdesigned valves and complimentary components that operate in industrial process applications including Fluid Catalytic Cracking Units, Residual Catalytic Cracking Units, Millisecond Catalytic Cracking Units, Power Generation, Steel Manufacture and Iron Ore Reduction.

Valve Types • Slide Valves • Bolt-Less Slide Valves™ • Plug valves • Diverter valves • Butterfly valves • Angle plug valves Valve Sizes • Diameters from 4 inches to 140 inches • Weighs up to 100 tons Control Systems • Electro-hydraulic (analog and digital) • Pneumatic • Electric Services • Installation • Maintenance and repair • Troubleshooting • Turnaround planning & supervision • System Inspection • 3D finite element analysis • Engineering services • Customengineered design • Preventive maintenance programs • On-site training systems 24-hour emergency response TapcoEnpro: Dedicated to being customer-driven Thanks to long-standing customer relationships, TapcoEnpro has been able to listen to customer needs, and develop solutions that continue to revolutionize the process industry. With that legacy in mind, we invite you to bring any challenge you face to your TapcoEnpro CARE Team today.

RAE Systems business is to provide high value, reliable, easy to use field monitors and gas detectors. Contributing solutions for environmental, industrial hygiene and occupational health and safety users. From personal single gas to hand held wireless continuous gas monitors for detection of benzene, methylene Tu rna round and Ma int enanc 34 e Service s June 2009 Provider Directory chloride, combustibles, oxygen, hydrogen sulfide, carbon monoxide, sulfur dioxide, nitric oxide, nitrogen dioxide, chlorine, hydrogen cyanide, ammonia, phosphene and more.

REOTEMP INSTRUMENT CORPORATION 10656 Roselle Street San Diego, CA 92121 United States Mark Leonelli Phone: 1-858-784-0710 Fax: 1-858-784-0720 MLeonelli@reotemp.com www.reotemp.com

SPECTRASENSORS 4333 W Sam Houston Pkwy N. Houston, TX 77043 United States Phone: 1-800-619-2861 Fax: 1-713-856-6623 sales@spectrasensors.com www.spectrasensors.com

SpectraSensors, Inc. is a leading manufacturer of optically based gas analyzers and moisture analyzers for analytical process markets. Typical applications include gas quality and energy measurements (H2O, CO2, H2S, BTU) in natural gas, trace moisture and hydrogen sulfide in refineries and petrochemical plants, and atmospheric REOTEMP is recognized as a leading measurements from commercial airmanufacturer of temperature and prescraft for the U.S. and International sure instrumentation. We provide bimetal Weather Services. SpectraSensors uses thermometers, pressure gauges, RTD’s Tunable Diode Lasers (TDL) in conjuncand thermocouples, diaphragm seals, tion with Absorption Spectroscopy in temperature and pressure transmitters, an array of products such as Ambient temperature and pressure switches, Air Monitoring Analyzers, Moisture thermowells, remote filled thermometers, Analyzers (Hygrometers), Dew Point digital thermometers, and related acces- Analyzers, and Hydrogen Sulfide sories to a variety of process markets Analyzers, Gas Analyzers for Natural worldwide. REOTEMP Instrument Gas Pipelines, Petrochemical Refineries, Corporation was established in 1965 and Environmental Technology, and Gas is located in San Diego, California.

Quality applications. SpectraSensors Gas Analyzers measure Moisture REOTEMP is an ISO 9001 certified (H2O), Carbon Dioxide (CO2), Hydrogen manufacturer. We are dedicated to conSulfide (H2S), Hydrogen Chloride tinual improvement, on-time deliveries, (HCl), Methane (CH4), Ammonia (NH3) high quality products, and exceptional Ethylene Oxide (ETO) and more. customer satisfaction.

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Provider Directory TEAM INDUSTRIAL SERVICES, INC. 200 Hermann Drive Alvin, TX 77511 United States Kurt Hand Phone: 1-281-331-6154 Phone: 1-800-662-8326 Fax: 1-281-331-4107 contact@teamindustrial services.com www.teamindustrial services.com Team Industrial Services, Inc., provides U.S. and International manufacturing facilities with (1) on-site, onstream, Tu rna round and Ma int enanc 40 e Service s June 2009 Provider Directory nondestructive leak sealing services (to 6,000 psig/1700F), (2) high temperature/ high pressure hot taps and line stops (to 2500 psig/1350F, 1650 gpm/22ftsec), (3) an ISO-9001 engineering, design, and manufacturing facility that produces related hardware and sealants for any chemical process leak, (4) Freeze Stop Services, (5) concrete leak repair and restoration services, (6) Fugitive Emissions Control Services, LDAR (7) Specialty Maintenance Services such as online repairs of leaking fin fans, (8) Field Machining Services, (9) Mechanical Integrity Inspection Services (10) NDE/ NDT Inspection Services and (11) Field Heat Treating Services.

TITAN TECHNOLOGIES INTERNATIONAL, INC. 9001 Jameel Road, Suite 180 Houston, TX 77040 United States Tom Kubala Phone: 1-281-796-1516 Phone: 1-281-358-6023 Fax: 1-281-358-6011 tkubala@titanti.com www.titanti.com Our mission is to be the leading manufacturer of Hydraulic Torque Wrenches, Pneumatic Torque Wrenches, Hydraulic Tensioning and other high-end bolting solutions for the benefit of our customers, our shareholders, our employees and our partners by providing: • Direct customer relations and local presence in the markets served • Superior products and services • Total customer solutions Our unwavering mission guides our everyday actions.

Customer driven product development fuels our growth. Listening to customer

needs builds our market Tu rna round and Ma int enanc 42 e Service s June 2009 Provider Directory leadership. Continuous improvement is fundamental to our continued success. TITAN is a leading bolting solutions provider committed to offering the most reliable and comprehensive bolting solutions world wide. Different from other companies that sell bolting products and services, Titan is a solutions-based company which features a vast array of solutions to any bolting application.

TOTAL SAFETY 11111 Highway 225 La Porte, TX 77571 United States Paul Tyree Phone: 1-281-867-2300 Phone: 1-800-231-6578 Fax: 1-281-867-2400 mail@totalsafety.com www.totalsafety.com

operations in 56 countries and experience in managing projects around the globe, Tyco Thermal Controls is the ideal partner for companies worldwide.

V VOITH TURBO BHS GETRIEBE GMBH Hans-Boeckler-Strasse 7 87527 Sonthofen Germany Jean-Claude Debout Phone: 49-8321-802-501 Fax: 49-8321-802-685 jean-claude.debout@voith.com www.bhs-getriebe.de

Voith Turbo BHS Getriebe is a world leading gearbox manufacturer whose design capabilities have consistently produced the most reliable and maintenance free gearboxes since 1932. Since joining Total Safety is the World’s Leading together with Voith Turbo in 2007, the Provider of Safety Service Solutions to the organization offers unparalleled service Upstream, Refinery, and General Industrial via a global service network to match markets. Our goal is to provide high-qualtheir world leading industrial gear drives. ity safety solutions in a measurable, costThrough an unmatched combination of effective manner - without compromise. advanced technologies, design experiTotal Safety provides rental, inspection, ence, and manufacturing capabilities, service, and repair of safety equipment, BHS continues to meet the increasing which includes gas detection, respiratory customer demands for the higher power, protection, fire protection, and confined speeds, efficiency, and reliability. space entry equipment, safety training Voith Turbo BHS is available anytime, and consulting and safety services for turnarounds and In-Plant Service Centers, in emergencies 24 hours, 7 days a week and provides comprehensive one-stop which provides on-site technicians who perform technical safety services. At Total service for turbo gearboxes from a variety of manufacturers. This naturally includes Safety, we’ve assembled the best minds in the business. We’re ready to put them their own units, supplied under trademarks BHS, BHS Sonthofen, BHS-Voith, to work for you and your specific needs, big or small. We share a single mission... BHS-Cincinnati, BHS Getriebe, Voith, Krupp, and Voith Turbo BHS Getriebe. to ensure the safe Wellbeing of Workers The service concentrates on high-perforWorldwide (W3). mance gearboxes and other load gear units, but they also deal with heavy-duty TYCO THERMAL CONTROLS couplings, double and single diaphragm Romeinse straat 14 couplings, toothed couplings and rotor 3001 Leuven turning gears / barring gears.

Belgium Marcus Kleinehanding Phone: 32-16213510 mkleineh@tycothermal.com www.tycothermal.com

Voith Turbo BHS’ service portfolio is not limited to routine maintenance. They also install, align and commission turbo gearboxes, and revamp units to increase their performance or adapt them to new duties. They measure and analyze vibraTyco Thermal Controls, a part of Tyco tion, noise, and lubricating oil. Visual Flow Control, is a global company providing optimal solutions for various appli- checks, surface crack detection, dye cations involving heat tracing, floor heat- penetrant tests, magnetic powder tests, ing, snow melting and de-icing, tempera- and checks of tooth contact pattern and ture measurement, fire and performance tooth geometry are also carried out. wiring, and leak detection systems. With EUROPEAN TURNAROUND

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Provider Product Directory Mesh—Wire Operations and Maintenance Procedures Planning and Scheduling Project—Project Engineering Trays—Fractionation Turnarounds—Turnarounds/ Shutdowns Services Welding—Welding Repairs

A Alstom Power, Air Preheater Company Calciners Coolers—Rotary Dryers—Flash Dryers—Rotary Kilns—Rotary Mills Mills—Hammer Mills—Roller

Burckhardt Compression AG

AMETEK, Calibration Instruments Calibration—Laboratory Grade Equipment—Hand Held Calibration Gauges—Deadweight Instrument Calibration and Repair—Pressure Instruments Instrument Calibration and Repair—Temperature Instruments Instruments—Calibration Specialty—Specialty Gases Calibration Temperature—Temperature Indicators Temperature—Temperature Probes Testers—Deadweight Thermometers

B BORSIG GmbH Boilers—Steam Boilers—Waste Heat Recovery Compressors—Booster Compressors—Centrifugal Compressors—Reciprocating Compressors—Turbocharged Exchangers—Scraped Surface Maintenance—Heat Exchanger Maintenance—Refinery Pressure—Pressure Vessels

BUCHEN-ICS GmbH

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BW Technologies by Honeywell Gas Detection Gas Detection—Infrared Combustible Gas Detection—Portable Monitors—Carbon Monoxide Monitors—Ozone

C C B and I Columns Pressure—Pressure Vessels Pressure—Pressure Vessels, Carbon Steel

Catalysts—Custom Engineering—Inspection Grids—Support Maintenance—Refinery 12

Compressors—Ammonia Compressors—Balance-Opposed Compressors—CO2 Compressors—Ethylene Compressors—Gas Compressors—High Pressure Compressors—Lube and Non-Lube Compressors—Oxygen Compressors—Reciprocating Compressors—Vertical, In-Line Cryogenics Engineering—Stress Analysis Maintenance—Refinery Online Monitoring—Online Monitoring Preventive/Predictive Maintenance Pulsation Studies Rotating—Rotating and Reciprocating Equipment Maintenance Skid Units Valves—Compressor

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Pressure—Pressure Vessels, Heavy Wall Stainless Steel Pressure—Pressure Vessels, Stainless Steel Project—Management and Controls Reactors—Fabrication Towers Turnaround Services— Management and Construction

D Dampney Company Inc. Coatings—Corrosion Resistent Coatings—Insulation Lining—Corrosion-Resistant

Delta Valve Valves, Gate—Critical Service Valves, Gate—Delayed Coking Series Valves, Gate—Double Block and Purge Valves, Gate—Large Diameter Isolation Valves, Gate—Metal Seated Knife Valves, Gate—Slide

E Edgen Murray Flanges—Forged Steel Flanges—High Alloy Pipe—Corrosion Resistant Pipe—High Alloy Stainless Steel—Stainless Steel Plate Valves—Angle Valves—Ball Valves—Check Valves—Gate Valves—Globe

Elliott Turbomachinery SA Compressors—Centrifugal Compressors—Ethylene Compressors—Gas Compressors—Refrigeration Couplings—Flexible Reverse—Reverse Engineered Turbine Parts Rotor Maintenance

Provider Product Directory Steam—Steam Turbine Turbine—Analysis Turbine—Balancing Turbine—Bearings Turbine—Blades Turbine—Blades Repair Turbine—Coatings Turbine—Components Turbine—Control Systems Turbine—Extraction Control Control Systems Turbine—Hardfacing Turbine—Impellers Turbine—Inspection Turbine—Multi-Stage Steam Turbine—Nozzle Repair Turbine—Overhauls Turbine—Performance Turbine—Repair Turbine—Rotor Repair Turbine—Seal Strip Replace Turbine—Shell/Casing Crack Repair Turbine—Single Stage Steam Turbine—Speed Control Systems Turbine—Strut Crack Repair Turbine—Surplus Turbine—Systems Automation and Controls Turbine—Valve Position Control Systems Turbomachinery— Turbomachinery Systems Automation and Controls Turnarounds—Turnarounds/ Shutdowns Services Turnarounds—Turnarounds Sub-Contractor

Expansion Joint Systems, Inc. Joints—Expansion, Bellows-type Joints—Expansion, Inspections and Repairs Joints—Fabric Expansion Joints—Metal Expansion

F FabEnCo, Inc. Gates—Safety Safety—Safety Gates

Flexitallic

HRI, Inc.

Gaskets—Ceramic Fiber High Temperature Gaskets—Custom Made Gaskets—Elastomeric Gaskets—Heat Exchanger Gaskets—Manhole

Boiler—Inspections and Repairs Fluid Catalytic Cracker—Repairs Inspection Services—High Temperature Pipe—Tapping Tube—Inspections and Repairs

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Grace Technologies , Inc.

Industrial Scientific Corporation

Compressors—Air Dryers—Air Pumps—Vacuum Valves—Air-Operated Valves—Check Valves—Pressure Control Valves—Solenoid

Analysers—Carbon Dioxide Analysers—Hydrocarbon Equipment—Leak Detection and Monitoring Gas Detection—Continuous Monitoring Systems Gas Detection—Equipment and Services Gas Detection—Portable Monitors—Carbon Monoxide Safety—Safety Equipment

H HOERBIGER Kompressortechnik Holding GmbH Compressors—Gas Engine Compressors—High Pressure Compressors—Liquid Ring Compressors—Reciprocating Engineering—Systems, Instrumentation Maintenance—Refinery Online Monitoring—Online Monitoring Operations and Maintenance Procedures— Packing—High Performance Positioners, Actuators Preventive / Predictive Maintenance Relief Valves Rotating—Rotating and Reciprocating Equipment Maintenance Safety—Safety Equipment Turbomachinery— Turbomachinery Engineering and Design Valves—Compressor Valves—High Pressure Valves—L P G Valves—Safety

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Innovative Turnaround Controls Procurement and Expediting— Carbon Dioxide Software—Cost Estimating Software—Project Management Turnaround Services— Management and Construction Turnaround Services—Planning and Scheduling

K KBC Advanced Technologies, Inc. Operations and Maintenance Procedures Process—Process Consultants Productivity Optimization Consultants Reliability—Reliability Consultants Revamps and Modifications

KTI Corp Fired Heaters Heat Recovery Revamps and Modifications

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Provider Product Directory

M MAN Turbo AG Compressors—Axial Flow Compressors—Centrifugal Compressors—Reciprocating Exchangers—Heat Turbine—Components Turbine—Performance Turbomachinery— Turbomachinery Engineering and Design

N Equipment—Leak Detection and Monitoring Gas Detection Heat Exchanger—Inspections Inspection Services Inspection Services—Fugitive Emissions Inspection Services—Infrared Pipe—Leak Detection

P

Smithco Engineering Heat Exchanger—Air Cooled Heat Exchanger—Finned Tube Heat Exchanger—Gas Coolers Heat Exchanger—Motor-driven forced and induced air Analysers—Carbon Dioxide Analysers—Fuel Gas Analysers—Gas Moisture Analysers—Humidity Analysers—Hydrogen Sulfide

T TapcoEnpro International

Total Safety Fire Protection Fire Suppression Gas Detection—Continuous Monitoring Systems Gas Detection—Portable and Fixed Safety—Rescue Safety—Safety Supervision Safety—Safety Training

Tyco Thermal Controls Controllers—Automatic Controllers—Electrically Operated Controllers—Temperature Engineering—Designing Engineering—Evaluation Engineering—Inspection Engineering—Insulation Engineering—Piping Heaters—Pipe Tracing, Electric Pre-Insulated Pipe Process—Process Engineering and Design Procurement and Expediting Risk Management

Valves—Angle Valves—Butterfly Valves—Diaphragm Valves—Double Disc Valves—Inspection and Testing Valves—Process Control Systems Voith Turbo BHS Getriebe

V

Petroblast Leasing Blast Resistant Buildings— Modular Blast Resistant Buildings— Offices, Labs, Control Rooms Blast Resistant Buildings— Pre-engineered

R RAE Systems, Inc. Analysers—Carbon Dioxide Analysers—Hydrogen Sulfide Gas Detection— Gas Detection—Infrared Combustible Monitors—Wireless

Team Industrial Services, Inc. Gas Detection—Equipment and Services Heat Exchanger—Inspections Inspection Services Leak Detection—Equipment and Services Rotating—Rotating and Reciprocating Equipment Maintenance Vessel—Vessel and Tank Leak Repair Welding Services

Titan Technologies International, Inc.

REOTEMP Instrument Corporation Instrumentation—Calibration and Repair Pressure—Pressure Switches Pressure—Pressure Transmitters

EUROPEAN TURNAROUND

S

SpectraSensors

NDTrak

14

Temperature—Temperature Switches Thermometer—Thermometer, Bimetal Thermowells

AND

Bolt—Removal Bolt—Tensioning and Torquing Tools and Indicators

M A I N T E N A N C E S E R V I C E S D I R E C TO RY 2010

GmbH

Couplings—Rigid, Diaphragm, Torison Gear Box—Field Repair and Overhaul Gear Box—Online Monitoring Gear Box—Speed Increasing/ Reducing Gear Box Repair—All Brands Gear Drives—Design and Manufacturing Gears—Barring Online Monitoring—Online Monitoring

Emission impossible.

Q Q Q Q

Are you satisfied with the effectiveness of your compressor packings?

Are you happy with leaking gas?

Are you satisfied with the durability of your packing rings?

Are you comfortable with the impact your compressor is having on the environment?

If not: Try HOERBIGERâ&#x20AC;&#x2122;s new BCD packing ring combining high sealing efficiency with extended lifetime.

For more information please contact ringsandpacking@hoerbiger.com Select 303 at www.HydrocarbonProcessing.com/RS

www.hoerbiger.com

HOERBIGER launches a new sealing solution for reciprocating compressors

Select 306304 at at www.HydrocarbonProcessing.com/RS Select www.HydrocarbonProcessing.com/RS

Product/Service Directory

A

C

HOERBIGER Kompressortechnik Holding GmbH

Analysers—Carbon Dioxide Industrial Scientific Corporation RAE Systems, Inc. SpectraSensors

Calciners Alstom Power, Air Preheater Company

Compressors—Liquid Ring HOERBIGER Kompressortechnik Holding GmbH

Analysers—Fuel Gas SpectraSensors Analysers—Gas Moisture SpectraSensors Analysers—Humidity SpectraSensors

Calibration—Laboratory Grade Compressors—Lube and AMETEK, Calibration Instruments Non-Lube Burckhardt Compression AG Catalysts—Custom BUCHEN-ICS GmbH Coatings—Corrosion Resistent Dampney Company Inc.

Compressors—Oxygen Burckhardt Compression AG

Columns CB&I

Compressors—Reciprocating BORSIG GmbH Burckhardt Compression AG HOERBIGER Kompressortechnik Holding GmbH MAN Turbo AG

Compressors—Air Grace Technologies , Inc.

B

Compressors—Refrigeration Elliott Turbomachinery SA

Compressors—Ammonia Burckhardt Compression AG

Blast Resistant Buildings— Modular Petroblast Leasing

Compressors—Turbocharged BORSIG GmbH

Compressors—Axial Flow MAN Turbo AG

Compressors—Vertical, In-Line Burckhardt Compression AG

Compressors—BalanceOpposed Burckhardt Compression AG

Controllers—Automatic Tyco Thermal Controls

Analysers—Hydrocarbon Industrial Scientific Corporation Analysers—Hydrogen Sulfide RAE Systems, Inc. SpectraSensors

Blast Resistant Buildings— Offices, Labs, Control Rooms Petroblast Leasing Blast Resistant Buildings— Pre-engineered Petroblast Leasing

Coatings—Insulation Dampney Company Inc.

Compressors—Booster BORSIG GmbH

Compressors—Centrifugal BORSIG GmbH Boiler—Inspections and Repairs Elliott Turbomachinery SA HRI, Inc. MAN Turbo AG Boilers—Steam Compressors—CO2 BORSIG GmbH Burckhardt Compression AG Boilers—Waste Heat Recovery Compressors—Ethylene BORSIG GmbH Burckhardt Compression AG Bolt—Removal Elliott Turbomachinery SA Titan Technologies Compressors—Gas International, Inc. Burckhardt Compression AG Bolt—Tensioning and Torquing Elliott Turbomachinery SA Tools and Indicators Compressors—Gas Engine Titan Technologies HOERBIGER Kompressortechnik International, Inc. Holding GmbH Compressors—High Pressure Burckhardt Compression AG

EUROPEAN TURNAROUND

AND

Controllers—Electrically Operated Tyco Thermal Controls Controllers—Temperature Tyco Thermal Controls Coolers—Rotary Alstom Power, Air Preheater Company Couplings—Flexible Elliott Turbomachinery SA Couplings—Rigid, Diaphragm, Torison Voith Turbo BHS Getriebe GmbH Cryogenics Burckhardt Compression AG

D Dryers—Air Grace Technologies , Inc.

M A I N T E N A N C E S E R V I C E S D I R E C TO RY 2010

17

Product/Service Directory Dryers—Flash Alstom Power, Air Preheater Company Dryers—Rotary Alstom Power, Air Preheater Company

Flanges—High Alloy Edgen Murray

Gear Box—Field Repair and Overhaul Voith Turbo BHS Getriebe GmbH

G

Engineering—Designing Tyco Thermal Controls

Gas Detection BW Technologies by Honeywell NDTrak RAE Systems, Inc.

Engineering—Evaluation Tyco Thermal Controls Engineering—Inspection BUCHEN-ICS GmbH Tyco Thermal Controls

Gas Detection—Continuous Monitoring Systems Industrial Scientific Corporation Total Safety

Engineering—Insulation Tyco Thermal Controls Engineering—Piping Tyco Thermal Controls Engineering—Stress Analysis Burckhardt Compression AG Engineering—Systems, Instrumentation HOERBIGER Kompressortechnik Holding GmbH Equipment—Hand Held Calibration AMETEK, Calibration Instruments Equipment—Leak Detection and Monitoring Industrial Scientific Corporation NDTrak Exchangers—Heat MAN Turbo AG Exchangers—Scraped Surface BORSIG GmbH

F Fire Protection Total Safety Fire Suppression Total Safety

Gas Detection—Equipment and Services Industrial Scientific Corporation Team Industrial Services, Inc. Gas Detection—Infrared Combustible BW Technologies by Honeywell RAE Systems, Inc. Gas Detection—Portable BW Technologies by Honeywell Industrial Scientific Corporation

AND

Gear Box—Online Monitoring Voith Turbo BHS Getriebe GmbH Gear Box—Speed Increasing/ Reducing Voith Turbo BHS Getriebe GmbH Gear Box Repair—All Brands Voith Turbo BHS Getriebe GmbH Gear Drives—Design and Manufacturing Voith Turbo BHS Getriebe GmbH Gears—Barring Voith Turbo BHS Getriebe GmbH Grids—Support BUCHEN-ICS GmbH

H Heat Exchanger—Air Cooled Smithco Engineering Heat Exchanger—Finned Tube Smithco Engineering Heat Exchanger—Gas Coolers Smithco Engineering

Gas Detection—Portable and Fixed Total Safety

Heat Exchanger—Inspections NDTrak Team Industrial Services, Inc.

Gaskets—Ceramic Fiber, High Temperature Flexitallic

Heat Exchanger—Motor-driven forced and induced air Smithco Engineering

Gaskets—Custom Made Flexitallic

Heat Recovery KTI Corp

Gaskets—Elastomeric Flexitallic

Heaters—Pipe Tracing, Electric Tyco Thermal Controls

Gaskets—Heat Exchanger Flexitallic

I

Gaskets—Manhole Flexitallic

Inspection Services NDTrak Team Industrial Services, Inc.

Gates—Safety FabEnCo, Inc.

Fired Heaters KTI Corp EUROPEAN TURNAROUND

Gauges—Deadweight AMETEK, Calibration Instruments

Fluid Catalytic Cracker— Repairs HRI, Inc.

E

18

Flanges—Forged Steel Edgen Murray

M A I N T E N A N C E S E R V I C E S D I R E C TO RY 2010

ai_BHS_60.0_en aio

Service for Unparalleled Gearbox Performance Voith Turbo BHS Getriebe provides comprehensive service for turbo gearboxes from a variety of manufacturers. This naturally includes our own units, supplied under trademarks including BHS, BHS Sonthofen, BHS-Voith, BHS-Cincinnati, BHS Getriebe, Krupp, Voith and Voith Turbo BHS Getriebe.

Professional services offered from a single source are: Field Service | Customer Training | Condition Monitoring | Original Spares Maintenance | Repairs | Service Agreements | Consultation | Commissioning

We are available anytime, in emergencies 24 hours, 7 days a week. Via our worldwide service network we are always only a few steps away.

Call us at +49 (0)8321 802-555 on our service portfolio or check at www.bhs-gearbox-service.com

Voith Turbo BHS Getriebe GmbH Sonthofen / Germany www.bhs-getriebe.com

Select 305 at www.HydrocarbonProcessing.com/RS

Product/Service Directory Inspection Services—Fugitive Emissions NDTrak

M

Maintenance—Heat Exchanger Packing—High Performance BORSIG GmbH HOERBIGER Kompressortechnik Holding GmbH Maintenance—Refinery BORSIG GmbH Pipe—Corrosion Resistant BUCHEN-ICS GmbH Edgen Murray Burckhardt Compression AG Pipe—High Alloy HOERBIGER Kompressortechnik Edgen Murray Holding GmbH Pipe—Leak Detection Mesh—Wire NDTrak BUCHEN-ICS GmbH Pipe—Tapping Mills HRI, Inc. Alstom Power, Air Planning and Scheduling Preheater Company BUCHEN-ICS GmbH Mills—Hammer Positioners, Actuators Alstom Power, Air HOERBIGER Kompressortechnik Preheater Company Holding GmbH Mills—Roller Pre-Insulated Pipe Alstom Power, Air Tyco Thermal Controls Preheater Company

Inspection Services—High Temperature HRI, Inc. Inspection Services—Infrared NDTrak Instrument Calibration and Repair—Pressure Instruments AMETEK, Calibration Instruments Instrument Calibration and Repair—Temperature Instruments AMETEK, Calibration Instruments Instrumentation—Calibration and Repair REOTEMP Instrument Corporation Instruments—Calibration AMETEK, Calibration Instruments

Monitors—Carbon Monoxide BW Technologies by Honeywell Industrial Scientific Corporation

J Joints—Expansion, Bellowstype Expansion Joint Systems, Inc.

Monitors—Ozone BW Technologies by Honeywell

Joints—Expansion, Inspections and Repairs Expansion Joint Systems, Inc. Joints—Fabric Expansion Expansion Joint Systems, Inc.

Monitors—Wireless RAE Systems, Inc.

O Online Monitoring—Online Monitoring Burckhardt Compression AG HOERBIGER Kompressortechnik Holding GmbH Voith Turbo BHS Getriebe GmbH

Joints—Metal Expansion Expansion Joint Systems, Inc.

K Kilns—Rotary Alstom Power, Air Preheater Company

L Leak Detection—Equipment and Services Team Industrial Services, Inc.

Operations and Maintenance Procedures BUCHEN-ICS GmbH HOERBIGER Kompressortechnik Holding GmbH KBC Advanced Technologies, Inc.

EUROPEAN TURNAROUND

AND

Pressure—Pressure Switches REOTEMP Instrument Corporation Pressure—Pressure Transmitters REOTEMP Instrument Corporation Pressure—Pressure Vessels BORSIG GmbH CB&I Pressure—Pressure Vessels, Carbon Steel CB&I Pressure—Pressure Vessels, Heavy Wall Stainless Steel CB&I Pressure—Pressure Vessels, Stainless Steel CB&I Preventive / Predictive Maintenance HOERBIGER Kompressortechnik Holding GmbH Burckhardt Compression AG Process—Process Consultants KBC Advanced Technologies, Inc.

Lining—Corrosion-Resistant Dampney Company Inc. 20

P

M A I N T E N A N C E S E R V I C E S D I R E C TO RY 2010

Product/Service Directory Process—Process Engineering and Design Tyco Thermal Controls Procurement and Expediting Tyco Thermal Controls Procurement and Expediting— Carbon Dioxide Innovative Turnaround Controls Productivity Optimization Consultants KBC Advanced Technologies, Inc. Project—Management and Controls CB&I

Rotor Maintenance Elliott Turbomachinery SA

Thermometer—Thermometer, Bimetal REOTEMP Instrument Corporation

S

Thermometers AMETEK, Calibration Instruments

Safety—Rescue Total Safety Safety—Safety Equipment HOERBIGER Kompressortechnik Holding GmbH Industrial Scientific Corporation Safety—Safety Gates FabEnCo, Inc. Safety—Safety Supervision Total Safety

Project—Project Engineering BUCHEN-ICS GmbH

Safety—Safety Training Total Safety

Pulsation Studies Burckhardt Compression AG

Skid Units Burckhardt Compression AG

Pumps—Vacuum Grace Technologies , Inc.

Software—Cost Estimating Innovative Turnaround Controls

R

Software—Project Management Innovative Turnaround Controls

Reactors—Fabrication CB&I Reliability—Reliability Consultants KBC Advanced Technologies, Inc. Relief Valves HOERBIGER Kompressortechnik Holding GmbH Revamps and Modifications KBC Advanced Technologies, Inc. KTI Corp Reverse—Reverse Engineered Turbine Parts Elliott Turbomachinery SA Risk Management Tyco Thermal Controls Rotating—Rotating and Reciprocating Equipment Maintenance Burckhardt Compression AG HOERBIGER Kompressortechnik Holding GmbH Team Industrial Services, Inc.

Specialty—Specialty Gases Calibration AMETEK, Calibration Instruments Stainless Steel—Stainless Steel Plate Edgen Murray

T Temperature—Temperature Indicators AMETEK, Calibration Instruments Temperature—Temperature Probes AMETEK, Calibration Instruments Temperature—Temperature Switches REOTEMP Instrument Corporation Testers—Deadweight AMETEK, Calibration Instruments AND

Towers CB&I Trays—Fractionation BUCHEN-ICS GmbH Tube—Inspections and Repairs HRI, Inc. Turbine—Analysis Elliott Turbomachinery SA Turbine—Balancing Elliott Turbomachinery SA Turbine—Bearings Elliott Turbomachinery SA Turbine—Blades Elliott Turbomachinery SA Turbine—Blades Repair Elliott Turbomachinery SA Turbine—Coatings Elliott Turbomachinery SA Turbine—Components Elliott Turbomachinery SA MAN Turbo AG Turbine—Control Systems Elliott Turbomachinery SA

Steam—Steam Turbine Elliott Turbomachinery SA

EUROPEAN TURNAROUND

Thermowells REOTEMP Instrument Corporation

Turbine—Extraction Control Control Systems Elliott Turbomachinery SA Turbine—Hardfacing Elliott Turbomachinery SA Turbine—Impellers Elliott Turbomachinery SA Turbine—Inspection Elliott Turbomachinery SA Turbine—Multi-Stage Steam Elliott Turbomachinery SA Turbine—Nozzle Repair Elliott Turbomachinery SA

M A I N T E N A N C E S E R V I C E S D I R E C TO RY 2010

21

Product/Service Directory Turnaround Services—Planning Valves—Pressure Control Grace Technologies , Inc. and Scheduling Innovative Turnaround Controls Valves—Process Control Systems Turnarounds—Turnarounds / TapcoEnpro International Shutdowns Services BUCHEN-ICS GmbH Valves—Safety Elliott Turbomachinery SA HOERBIGER Kompressortechnik Holding GmbH Turnarounds—Turnarounds Sub-Contractor Valves—Solenoid Elliott Turbomachinery SA Grace Technologies , Inc.

Turbine—Overhauls Elliott Turbomachinery SA Turbine—Performance Elliott Turbomachinery SA MAN Turbo AG Turbine—Repair Elliott Turbomachinery SA Turbine—Rotor Repair Elliott Turbomachinery SA Turbine—Seal Strip Replace Elliott Turbomachinery SA

V

Turbine—Shell/Casing Crack Repair Elliott Turbomachinery SA

Valves—Air-Operated Grace Technologies , Inc.

Turbine—Single Stage Steam Elliott Turbomachinery SA

Valves—Angle Edgen Murray TapcoEnpro International

Turbine—Speed Control Systems Elliott Turbomachinery SA

Valves—Ball Edgen Murray

Turbine—Strut Crack Repair Elliott Turbomachinery SA Turbine—Surplus Elliott Turbomachinery SA Turbine—Systems Automation and Controls Elliott Turbomachinery SA Turbine—Valve Position Control Systems Elliott Turbomachinery SA

Turbomachinery— Turbomachinery Systems Automation and Controls Elliott Turbomachinery SA Turnaround Services— Management and Construction CB&I Innovative Turnaround Controls

22

EUROPEAN TURNAROUND

AND

Valves, Gate—Delayed Coking Series Delta Valve Valves, Gate—Double Block and Purge Delta Valve

Valves—Butterfly TapcoEnpro International

Valves, Gate—Large Diameter Isolation Delta Valve

Valves—Check Edgen Murray Grace Technologies , Inc.

Valves, Gate—Metal Seated Knife Delta Valve

Valves—Compressor Burckhardt Compression AG HOERBIGER Kompressortechnik Holding GmbH

Valves, Gate—Slide Delta Valve

Valves—Diaphragm TapcoEnpro International

Turbomachinery— Turbomachinery Engineering and Design HOERBIGER Kompressortechnik Holding GmbH MAN Turbo AG

Valves, Gate—Critical Service Delta Valve

Valves—Double Disc TapcoEnpro International Valves—Gate Edgen Murray Valves—Globe Edgen Murray Valves—High Pressure HOERBIGER Kompressortechnik Holding GmbH Valves—Inspection and Testing TapcoEnpro International Valves—L P G HOERBIGER Kompressortechnik Holding GmbH

M A I N T E N A N C E S E R V I C E S D I R E C TO RY 2010

Vessel—Vessel and Tank Leak Repair Team Industrial Services, Inc.

W Welding—Welding Repairs BUCHEN-ICS GmbH Welding Services Team Industrial Services, Inc.

The companies below are advertisers in the 2010 European Turnaround & Maintenance Services Directory. You can find more information about them in the Provider Directory (pages 5–11), Provider Product Directory (pages 12–14) and the Product /Service Directory (pages 17–22). When contacting, please mention that you saw their ad within the 2010 European Turnaround & Maintenance Services Directory.

HOW TO USE THE INDEX: 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 several ways readers can obtain information: 1. The quickest way to request information from an advertiser or about an editorial item is to go to www.HydrocarbonProcessing.com/RS. If you follow the instructions on the screen your request will be forwarded for immediate action.

2. Go online to the advertiser's Website listed below.

This Advertisers’ Index and procedure for securing additional information is provided as a service to European Turnaround and Maintenance Services Directory advertisers and a convenience to our readers. Gulf Publishing Co. is not responsible for omissions or errors.

Page

RS #

Page

RS #

Borsig GmbH.......................................................... 24 www.info.hotims.com/33748-306 Buchen.................................................................... 16 www.info.hotims.com/33748-304 Burckhardt Compression ........................................ 2 www.info.hotims.com/33748-301

(306)

DeltaValve ................................................................ 4 www.info.hotims.com/33748-302 Hoerbiger ............................................................... 15 www.info.hotims.com/33748-303 Voith Turbo ............................................................ 19 www.info.hotims.com/33748-305

(302)

(304) (301)

(303) (305)

Would you like to be represented in the 2011 European Turnaround & Maintenance Services Directory? Contact your sales representative for more information:

Bill Wageneck, Publisher 2 Greenway Plaza, Suite 1020 Houston, Texas, 77046 USA P.O. Box 2608 Houston, Texas 77252-2608 USA Phone: +1 (713) 529-4301, Fax: +1 (713) 520-4433 E-mail: Bill.Wageneck@GulfPub.com www.HydrocarbonProcessing.com

RUSSIA/FSU Lilia Fedotova Anik International & Co. Ltd. Phone: +7 (495) 628-10-333 E-mail: Lilia.Fedotova@GulfPub.com UNITED KINGDOM/SCANDINAVIA, NORTHERN BELGIUM, THE NETHERLANDS Michael Brown Phone: +44 161 440 0854, Mobile: +44 79866 34646 E-mail: Michael.Brown@GulfPub.com

SALES OFFICES—NORTH AMERICA

SALES OFFICES—OTHER AREAS

IL, LA, MO, OK, TX Josh Mayer

AUSTRALIA—Perth Brian Arnold Phone: +61 (8) 9332-9839, Fax: +61 (8) 9313-6442 E-mail: Australia@GulfPub.com

Phone: +1 (972) 816-6745, Fax: +1 (972) 767-4442 E-mail: Josh.Mayer@GulfPub.com

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) 520-4459 E-mail: Laura.Kane@GulfPub.com

CT, DC, DE, MA, MD, ME, NC, NH, NJ, NY, OH, PA, RI, SC, VA, VT, WV, EASTERN CANADA Merrie Lynch Phone: +1 (617) 357-8190, Fax: +1 (617) 357-8194 Mobile: +1 (617) 594-4943 E-mail: Merrie.Lynch@GulfPub.com

SALES OFFICES—EUROPE FRANCE, GREECE, NORTH AFRICA, MIDDLE EAST, SPAIN, PORTUGAL, SOUTHERN BELGIUM, LUXEMBOURG, SWITZERLAND, GERMANY, AUSTRIA, TURKEY Catherine Watkins Tél.: +33 (0)1 30 47 92 51, Fax: +33 (0)1 30 47 92 40 E-mail: Watkins@GulfPub.com ITALY, EASTERN EUROPE Fabio Potestá Mediapoint & Communications SRL Phone: +39 (010) 570-4948, Fax: +39 (010) 553-0088 E-mail: Fabio.Potesta@GulfPub.com

BRAZIL—São Paulo Alfred Bilyk Phone: +55 (11) 3237-3269, Fax: +55 (11) 3237-3269 E-mail: Brazil@GulfPub.com CHINA, HONG KONG Iris Yuen Phone: +86 13802701367 (China) Phone: +852 69185500 (Hong Kong) E-mail: China@GulfPub.com INDONESIA, MALAYSIA, SINGAPORE, THAILAND Peggy Thay Publicitas Major Media (S) Pte Ltd Phone: +65 6836-2272, Fax: +65 6297-7302 E-mail: Singapore@GulfPub.com JAPAN—Tokyo Yoshinori Ikeda Pacific Business Inc. Phone: +81 (3) 3661-6138, Fax: +81 (3) 3661-6139 E-mail: Japan@GulfPub.com PAKISTAN—Karachi S. E. Ahmed Intermedia Communications Karachi-74700, Pakistan Phone: +92 (21) 663-4795, Fax: +92 (21) 663-4795

BORSIG

LEADING TECHNOLOGY FOR INNOVATIVE SOLUTIONS The BORSIG Group, a member of the global process technology player KNM Group Berhad, Kuala Lumpur/Malaysia, offers customised solutions for the chemical and petrochemical industry, refineries, power stations as well as for the oil and gas industry.

Our actual product and service programme: Pressures Vessels and Heat Exchangers: Process gas waste heat recovery systems, quench coolers, scraped surface exchangers Compressors: Reciprocating compressors for process gases and for CNG filling stations, centrifugal compressors for process gases Membrane Technology: Membranes, membrane modules and membrane systems for emission control, product recovery, gas conditioning, liquid separation

BORSIG GmbH Egellsstr. 21 D-13507 Berlin / Germany

Industrial Boilers: Fired boilers, heat recovery boilers, power plant engineering Power Plant Services and Industrial Services for: Pressure vessels, heat exchangers, power stations, steam generators, ball valves, fittings, machines such as steam turbines, compressors, pumps and blowers as well as pipelines.

The BORSIG Group - innovative solutions, state-ofthe-art technology, perfectly trained specialists and comprehensive know-how are the basis for our position as a “single source” supplier of leading technology. All BORSIG products are synonymous for top quality, reliability and optimum technical implementation.

The BORSIG Group – your competent partner for the future.

Phone: +49 (0) 30 4301-01 Fax: +49 (0) 30 4301-2236 Email: info@borsig.de http://www.borsig.de

Select 306 at www.HydrocarbonProcessing.com/RS