Gulfpub Hp 201103

Heat Recovery Steam Generators | Waste Heat Boilers | Fired Packaged Watertube Boilers | Specialty Boilers

We’ve been around awhile.

The RENTECH team has

a heap of experience – a total of more than 3,000 years – making boilers that operate efficiently and safely on six continents. Our formula has been tested and perfected so you can be assured that a boiler from RENTECH will perform reliably and earn your trust. So don’t be tempted to saddle up with a greenhorn; insist that your boiler be built Texas-tough by the skilled people at RENTECH.

WWW.RENTECHBOILERS.COM

BOILERS FOR PEOPLE WHO KNOW AND CARE

Select 58 at www.HydrocarbonProcessing.com/RS

MARCH 2011

HPIMPACT

SPECIALREPORT

BONUSREPORT

US pipeline safety bill

CORROSION CONTROL

PLANT SAFETY

Global midstream M&A update

Methods show how to detect and control corrosion

New technologies, standards and systems reduce plant risks

www.HydrocarbonProcessing.com

Select 55 at www.HydrocarbonProcessing.com/RS

MARCH 2011 • VOL. 90 NO. 3 www.HydrocarbonProcessing.com

SPECIAL REPORT: CORROSION CONTROL

29

Updates on improving refractory lining service life

39

Flare stack structure revamp: A case history

43

Avoid brittle fracture in pressure vessels

Tips help maintenance and operations care and maintain refractory products in high-temperature operations M. Maity

An innovative approach was used to repair an older flare structure online without an extensive shutdown S. Singh

Key points identify effects from auto-refrigeration on steel vessels F. Khazrai, H. B. Haghighi and H. Kordabadi

49

Improving pH control mitigates corrosion in crude units Equipment and pipe failures can be avoided through better desalting practices and inhibitor injections D. L. N. Cypriano, J. A. C. Ponciano, A. T. Vilas Boas, P. D. Murray and M. R. Nasser

TURNAROUND AND MAINTENANCE 2011—SUPPLEMENT Turnaround and Maintenance 2010

55

Cover This is an Elliott 60M centrifugal compressor rotor in Elliott’s high-speed balance facility, Jeannette, Pennsylvania. The rotor is coated with Elliott Pos-e-Coat® Plus, a premium protective and functional coating that provides superior anti-fouling and corrosion resistance for components in hydrocarbon gas-processing applications.

HPIMPACT 17

Pipeline safety bill introduced in US Senate

17

2010 midstream M&A activity hits $49 billion

19

Association says CFATS should be made permanent

20

US demand for activated carbon growing

Guide on how to successfully execute turnarounds and proper facility maintenance

BONUS REPORT: WATER MANAGEMENT Process safety: Blind spots and red flags

75 78 83

Improving safety for organizations involve more than technological solutions; understanding processes and plant interactions are a must T. Shephard

Consider new design criteria equipment modules

COLUMNS

Construction offers cost-effective protection of critical systems D. Cole and D. Austin

9

Chemical Facility Anti-Terrorism Standard turns four: What’s next?

HPIN RELIABILITY Oil mist and electric motor windings

11

HPIN EUROPE China enters and Russia deepens its influence in European refining

13

HPINTEGRATION STRATEGIES Terminal automation: More challenging than it looks

15

HPIN ASSOCIATIONS Maintenance, securing the cloud and a pep talk

94

HPIN WATER MANAGEMENT Passivation in cooling water circuits

An in-depth look at the standard R. Loughin

INSTRUMENTATION Avoid these top-10 instrumentation headaches

85

Visual engineering program solves designer and engineer issues across the industry D. Gibson

ENGINEERING CASE HISTORIES Case 61: Pressure loss in a reactor

89

Much information is available from a simple analysis T. Sofronas

DEPARTMENTS 7 HPIN BRIEF • 21 HPIN CONSTRUCTION 26 HPI CONSTRUCTION BOXSCORE UPDATE 90 HPI MARKETPLACE • 93 ADVERTISER INDEX

years $539, digital format one year $199. Airmail rate outside North America $175 additional a year. Single copies $25, prepaid.

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: [email protected] www.HydrocarbonProcessing.com

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.

Publisher Bill Wageneck [email protected] ARTICLE REPRINTS EDITORIAL Editor Stephany Romanow Process Editor Tricia Crossey Reliability/Equipment Editor Heinz P. Bloch News Editor Billy Thinnes Associate Editor Helen Meche 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)

If you would like to have a recent article reprinted for an upcoming conference or for use as a marketing tool, contact Foster Printing Company for a price quote. Articles are reprinted on quality stock with advertisements removed; options are available for covers and turnaround times. Our minimum order is a quantity of 100.

MAGAZINE PRODUCTION Director—Editorial Production Sheryl Stone Manager—Editorial Production Angela Bathe Artist/Illustrator David Weeks Manager—Advertising Production Cheryl Willis

Copyright © 2011 by Gulf Publishing Co. All rights reserved.

For more information about article reprints, call Rhonda Brown with Foster Printing Company at +1 (866) 879-9144 ext 194 or e-mail [email protected]. 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.

Permission is granted by the copyright owner to libraries and others registered with the Copyright Clearance Center (CCC) to photocopy any articles herein for the base fee of $3 per copy per page. Payment should be sent directly to the CCC, 21 Congress St., Salem, Mass. 01970. Copying for other than personal or internal reference use without express permission is prohibited. Requests for special permission or bulk orders should be addressed to the Editor. ISSN 0018-8190/01. www.HydrocarbonProcessing.com

ADVERTISING SALES See Sales Offices page 92.

GULF PUBLISHING COMPANY John Royall, President/CEO Ron Higgins, Vice President Pamela Harvey, Business Finance Manager Part of Euromoney Institutional Investor PLC.

CIRCULATION +1 (713) 520-4440 Director—Circulation Suzanne McGehee E-mail: [email protected] SUBSCRIPTIONS

Subscription price (includes both print and digital versions): United States and Canada, one year $199, two years $359, three years $469. Outside USA and Canada, one year $239, two years $419, three

Other energy group titles include: World Oil® Petroleum Economist Publication Agreement Number 40034765



4

I MARCH 2011 HydrocarbonProcessing.com

Select 151 at www.HydrocarbonProcessing.com/RS

Printed in U.S.A.

YOUR GLOBAL GASKET PROVIDER

AFTER

450°C

IT’S ADVANTAGE THERMICULITE . ®

Graphite oxidizes at high temps. So gaskets made with graphite ®

deteriorate as well. Thermiculite , the revolutionary sealing material from Flexitallic maintains its integrity up to 982°C. Preventing leakage and the loss of bolt load that can be so costly—and ultimately dangerous. Replace your graphite gaskets. Because when the heats on, graphite can’t serve. Visit: www.flexitallic.com, or call us at USA: 1.281.604.2400; UK: +44(0) 1274 851273.

Select 93 at www.HydrocarbonProcessing.com/RS

I have someone retiring after 33 years on the job. I have someone taking 33 years of experience with him. And now someone with just 3 years has to do that job.

With new Human Centered Design technologies from Emerson, it’s like the experience never left. Using our deep insights into how your people perform their roles and tasks, Emerson is designing all of our new products based on the science of Human Centered Design. This lets us embed the same experience and understanding that’s walking through your plant into our control and monitoring technologies — making them the easiest and most intuitive to use. Tasks are accomplished in fewer steps, and with greater confidence, even when relying on less expertise and specialization. It’s the certainty that jobs are done right, no matter who’s doing them. Find the experience you’ve been missing at EmersonProcess.com/Experience

The Emerson logo is a trademark and a service mark of Emerson Electric Co. © 2011 Emerson Electric Co.

HPIN BRIEF BILLY THINNES, NEWS EDITOR

[email protected]

Honeywell has formed a new business focused on providing advanced open software services to the process industries. Honeywell is seeking to achieve this goal by integrating the open connectivity and broad platform capability of its Matrikon acquisition with its applications and solutions business. Honeywell plans to use an outcome-based consulting approach to offer solutions for supply chain, production execution and operational excellence in areas such as energy efficiency, compliance, performance improvement and asset effectiveness. The new business will also address industrial and cyber security, advanced process control and optimization, process design simulation and operator training simulation.

GE has completed a new expanded licensing agreement that will allow the company to continue offering high-efficiency reverse osmosis (HERO) systems to help more of its industrial customers increase water-usage efficiency and reuse capacity. The new pact is with Debasish Mukhopadhyay, HERO’s process developer and patent holder. According to GE, the HERO offers higher recovery of feed water, higher production rates, higher product water quality levels and reduced scaling and fouling when compared to conventional RO systems. Under the agreement, GE will hold specific rights to market and manufacture solutions that utilize the HERO technology in key industry segments and applications including hydrocarbon processing and chemical processing.

The Dow Chemical Co. will close two vinyl chloride monomer (VCM) production units in 2011. Dow will shut down a production unit in Oyster Creek, Texas, in the first quarter of 2011. The closure of a second VCM unit, located in Plaquemine, Louisiana, was announced in 2009. The Louisiana plant will cease operations in the third quarter of 2011. “This is a continuation of the decisive actions taken by Dow to right-size our core chemicals manufacturing footprint and shift our basic feedstocks toward performance derivative businesses,” said Carlo Guarino, global business director for Dow Chlor-Vinyl.

SPECTRO Analytical Instruments GmbH has formed a strategic marketing alliance with SII NanoTechnology, Inc., to market SPECTRO’s inductivelycoupled plasma optical emission (ICP-OES) and mass spectrometers (ICP-MS) in Japan. The alliance covers all SPECTRO ICP-OES and ICP-MS instruments. SPECTRO will continue to support its existing Japanese customers through a subsidiary formed in 2008.

Sunoco said that it will move forward with the planned separation of SunCoke Energy after reaching an agreement with ArcelorMittal that resolves the lawsuit concerning coke pricing for Sunoco’s Jewell facility in Vansant, Virginia. The settlement agreement includes a renegotiation of the Jewell coke contract, including the elimination of the Jewell coal cost multiplier and an increase in fees. The pricing of Jewell coal will be based upon the third-party coal price at SunCoke’s Haverhill facility. Also of note: Sunoco will pay no compensatory damages. Based upon the guidance assumptions that the company previously provided, the impact of this settlement for 2012 is estimated to reduce earnings before interest, taxes, depreciation and amortization by approximately $60 million.

The American Petroleum Institute (API) called on the US Department of State to approve the Keystone pipeline project as soon as possible “as a matter of critical national interest.” The pipeline, which would be built by TransCanada Corp., would be part of a pipeline system bringing oil from Alberta’s oil sands region in Canada to US refineries. Canada’s oil reserves are second only to Saudi Arabia, and the US imports more oil from Canada than from all Persian Gulf countries. More than 342,000 new US jobs are likely to be created between 2011 and 2015 because of Canadian oil sands development, according to a study by the Canadian Energy Research Institute. HP

■ Refineries for sale BP is looking to sell two of its US refineries. The company has officially put a “for sale” sign in front of its refineries in Texas City, Texas, and Carson, California. BP is also seeking a buyer (perhaps the same one) for its associated integrated marketing businesses in southern California, Arizona, and Nevada. BP plans to complete the sales by the end of 2012, and this liquidation of assets would cut in half BP’s US refining capacity. BP plans to focus future downstream investment in the US on further improving and upgrading its other refining and marketing networks in the country, based around the Whiting, Indiana, and Cherry Point, Washington, refineries and its 50% interest in the Toledo, Ohio, refinery. So in essence, the company is less interested in the sun-baked climates of the American Southwest and more compatible with a Midwestern vibe. According to BP, these refineries have greater flexibility to refine a range of crude oils including heavy grades, and, on average, are more diesel-capable than BP’s current portfolio. The Carson refinery, south of Los Angeles, is at the heart of an integrated fuels value chain stretching across southern California, Arizona and Nevada. The refinery, which has 265,000 bpd capacity and supplies around 25% of Los Angeles’ gasoline demand, became part of BP through the 2000 acquisition of ARCO. The Texas City refinery became part of BP with the 1998 merger with Amoco. It is a large, highly complex refinery with 475,000 bpd refining capacity—the third biggest refinery in the US, with gasoline manufacturing capability equivalent to approximately 3% of US production. During the last few years, over $1 billion has been invested in modernizing and improving the Texas City plant. Much of that investment was driven by the requirements of federal regulators after the March 2005 fire and explosion at the refinery killed 15 workers and injured more than 170 others. Investigation of the accident revealed BP was to blame for subpar maintenance and safety procedures. HP

HYDROCARBON PROCESSING MARCH 2011

I7

GE Power & Water Water & Process Technologies

Meeting your challenges head on As the global economy slowly recovers, refiners can expect to see a positive shift in the demand for finished petroleum products in mature markets and growing, developing regions. Now more than ever, GE’s advanced treatment technologies, monitoring tools, and unmatched domain expertise for the hydrocarbon process industries provide a variety of solutions to help our customers find new ways to solve their toughest challenges. For more information, contact your local GE representative or visit www.gewater.com

Phase Separation

Corrosion Inhibitors

Embreak* demulsifier technology improves desalter performance and efficiency, maximize crude throughput and reduce fuel gas consumption.

LoSALT* and pHilmPLUS* minimize corrosion in critical production units and extend equipment life, maintaining throughput and increase operational flexibility.

Antifoulants

Finished Fuels

Our Thermoflo* chemistry, engineering expertise, and Heat-Rate Pro software provide a state-of the-art antifoulant treatment program.

ProSweet*, SpecAid* and ActNow* products help ensure refined fuels and other hydrocarbons meet required specifications and improve final product quality.

* Denotes a trademark of General Electric Company.

Select 72 at www.HydrocarbonProcessing.com/RS

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

Oil mist and electric motor windings We often get questions relating to oil mist and how it affects electric motor windings. For a quick answer, contact us at Gulf Publishing via e-mail. We’ll steer you in the right direction by explaining that oil mist will not harm modern motors. But if you must minimize oil mist intrusion into electric motors, we recommend you insist on having the vendor prove IP66 compliance. IP is the universally recognized Ingress Protection Code; it’s discussed in Reference 1. At least one fully compliant sealing product is available; it was introduced in 2003 and has since been an unqualified success.

ard was again investigated on this occasion and confirmation obtained that the oil/ air mixture of a plant-wide oil mist system remains substantially below the sustainable burning point. Experiments had shown the concentration of oil mist in the main supply manifolds ranging from .005 to as little as .001 of the concentrations generally considered flammable. The fire or explosion hazard of oil-mist-lubricated motors is thus no different from that of NEMA-II motors. No signs of overheating were found, and winding-resistance readings conformed fully to the initial, as-installed values.

History. There are other historical facts

New windings. With the introduction

relating to oil-mist lubricated motors. In the mid-1970s, oil mist had demonstrated its outstanding suitability for lubricating and preserving electric motor bearings. By that time, petrochemical plants on the US Gulf Coast, Caribbean and South America had converted in excess of one thousand electric motors to dry-sump oil-mist lubrication. In 1986, there were more than 4,000 electric motors on oil mist lube in the US Gulf Coast area alone. As of this writing (in 2011), there are an estimated 26,000 electric motors that run on pure oil mist with outstanding success. Many of these are in the Middle East. However, universal acceptance did not come overnight. Conversely, it seemed logical to extend oil-mist feeder lines from centrifugal pump bearing housings to the adjacent electric motor bearings. On the other hand, concern was voiced that lube oil would enter the motor and cause damage to winding insulation, or cause overheating until winding failure occurred. Initial efforts were, therefore, directed toward developing lip seals or other barriers confining the oil mist to only the bearing areas. Those efforts date back to about 1975.

of epoxy motor-winding materials several decades ago, it was shown that these winding coatings will not deteriorate in an oilmist atmosphere. This has been conclusively proven in tests by users and motor manufacturers. Among them were Reliance Electric (Cleveland), Continental Electric (Newark), and an oil refinery in the Caribbean where windings coated with epoxy varnish were placed in beakers filled with various types of mineral oils and synthetic lubricants. Next, these windings were oven-aged at 170°C (338°F) for several weeks, and then cooled and inspected— no problems. Decades ago, experimentation with motor winding and cable terminations in conduit boxes showed that a Teflon-based wrap should be used in the conduit box for best results. Other materials, including silicone tape, seemed to exhibit a tendency to swell or become gummy when exposed to oil mist. It was then decided to provide sealant between the motor frame and conduit box to reduce (an open system) mist emissions at the conduit enclosure. Mist supply and condensed oil-drain ports were made accessible without the need for covers and guards. A simple pipe nipple or similar extension was considered just fine in the 1980s. Today, environmentally friendly “closed circuit” oil-mist systems would be used in industry, but oil mist is still the best way to lubricate. HP

Issues. When, in the late 1970s, failures

of old-style Vee-ring seals (Fig. 1) were experienced in operating motors, oil mist did enter, and it coated the windings with coalesced oil. The potential explosion haz-

1

LITERATURE CITED Bloch, H. P. and A. Budris, Pump User’s Handbook: Life Extension, 3rd Edition, The Fairmont Press, Inc., Lilburn, Georgia, 2010, pp. 477-478

FIG. 1

A worn Vee-ring removed from an electric motor.

Oil mist in

Oil mist vent Overflow drain

FIG. 2

A successful oil-mist-lubricated motor bearing dating to the mid 1970s.

The author is Hydrocarbon Processing’s Reliability/ Equipment Editor. The author of 18 textbooks and over 490 papers or articles, he advises process plants worldwide on reliability improvement and maintenance cost-reduction opportunities. For more details, see his Practical Lubrication for Industrial Facilities, ISBN 0-88173-579-5.

HYDROCARBON PROCESSING MARCH 2011

I9

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

Select 76 at www.HydrocarbonProcessing.com/RS

HPIN EUROPE TIM LLOYD WRIGHT, EUROPEAN EDITOR [email protected]

China enters and Russia deepens its influence in European refining Like for the local couple that went long-distance ice skating here on the Swedish west coast recently, there are disconcerting rumblings of change underfoot in the European refining industry. This couple saw a wave rolling toward them one morning as they skated half a mile from the mainland. It was from a large tugboat, whose portly progress created a slow wash that slipped under the soft salt ice and continued toward them. In its wake, they were stranded on a small iceberg. Much to their chagrin, they began a slow drift out to sea.

49% stake in the 320,000 bpd (320 Mbpd) ISAB refinery in the Mediterranean on the strategically located island of Sicily. Mr. Sechin is at pains to distinguish the Russian oil industry, privatized and listed, from the majority of the OPEC–based NOCs (Rosneft is publicly listed but state-controlled). Stateowned China National Petroleum Company would say the same of PetroChina, its listed affiliate and the world’s most valuable company. It tops the Financial Times’ Global 500 list.

In reality. The wave that is breaking up and reforming Europe’s

China’s deal. After much speculation in the Scottish press,

refining operations is also the result of a passing behemoth. I described in my December 2010 column that the international oil companies (IOCs) are, in many cases, raking in their “chips” and leaving the table. And there is a sense of unease among the large customers of this industry as they wake up to a new creed of trader—or banker-supplier. But since I wrote, the tectonic of these changes are becoming clearer, and they are on a grander scale. The oil rich are joining skills-rich. The cash rich are merging their interests with wealthy western inland markets. And the IOCs and the national oil companies (NOCs) are getting together.

PetroChina has now joined a partnership with the operator of the 400 Mbpd Ineos (formerly BP) refinery at Grangemouth in Scotland. The deal also involves the 220 Mbpd Lavéra refinery at Marseille on the Mediterranean coast, from where it supplies French, Swiss and Southern German markets. At a signing ceremony in London presided over by Nick Clegg, the British deputy prime minister, and Li Ke Qiang, the Chinese vice premier, PetroChina’s UK general manager echoed to an extent the sentiment of Igor Sechin. “The framework agreement to work toward forming trading and refining related joint ventures with INEOS is consistent with PetroChina’s strategy of building a broader business platform in Europe and of becoming a leading international energy company,” he said.

Russian deal. Through a landmark $16 billion share swap at the start of the year, Kremlin-controlled Rosneft is now the single largest shareholder in BP. Thwarted, it may feel, in the Gulf of Mexico, the deal gives BP a route to explore for oil on the massive Russian Arctic continental shelf in an area comparable in size and potential, say the companies, to the North Sea. It’s said to be the first major equity-linked partnership between an international and a national oil company, giving the Russian company a 5% stake in BP in return for 9.5% of its shares. Since BP remains a substantial force in refining, and is said to be the largest supplier of the US military, the tie-up has had US Congress members questioning its security implications. But here’s what Rosneft Chairman Igor Sechin, who is also deputy prime minister, had to say about the purpose of the deal. “Rosneft is working on a new strategy aimed at transforming the company into an international energy holding. . . BP has gained a great amount of experience, including the Gulf of Mexico incident,” he told Russian television station, RT. Mr. Sechin is on record as saying that his dream is to sell finished products, not crude oil: “In 10, 15, 20 years, I would really like for Russian crude to be refined on Russian refining assets or those with Russian ownership,” he told the Wall Street Journal in 2009. It’s not just crude that the Russians export to the West. Fuel oils from straight-run Russian sites are also an upgrading staple of Northwest European refiners. Russia’s Lukoil is expanding internationally through acquisitions, as well. It is now firmly in the key ARA oil hub at Vlissingen, in The Netherlands, where in 2009, it bought 45% of the Total TNR refinery. The company also took a

Changing field. A research desk friend and I were discussing the current changes: “The buyers are long crude,” he pointed out. He sees coincidence on an epic scale, rather than some grand design—the NOCs picking up opportunities as the IOCs seek to get more value out of what they particularly can do well. Focusing upstream, he said, at least gave the IOCs a chance to differentiate themselves. “With the possible exception of Exxon, refineries are built by a handful of companies—UOP, KBR, the Japanese … and they buy catalysts from BASF, UOP, Albemarle, Axens and Haldor Topsøe. It’s hard to differentiate yourself by processing another barrel of oil.” Better, he suggested, for the IOCs to be operating in an environment where good seismic or better drilling can make a substantial difference. In the context of these deals, the rise of the Vitols and Morgan Stanleys as products suppliers is put into perspective. The arrival of PetroChina may even cause a small skirmish. Morgan has, in recent years, marketed products from INEOS’ refineries. As for the ice skaters, they may have been half a mile from land; but fortunately, they were just a mobile-phone call from rescue by helicopter. HP The author is HP’s European Editor and also a specialist in European distillate markets. 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 MARCH 2011

I 11

© 2010 Swagelok Company

We don’t have a department dedicated to quality. We have a company dedicated to it.

Simulated computer modeling, dimensional testing, and electron scanning of raw materials – you name it, we’ll go to any lengths to ensure that if it’s from Swagelok, it’s top quality. Because Quality isn’t just one of our values. It’s our attitude. It’s the focus of every associate, affecting everything from our services to our products. And by using the same disciplines, practices, and technologies through every office in every country, that focus is constant. We know that quality isn’t just a well-made product, it’s customers served beyond what they were expecting. To see what that attitude can do for you, visit swagelok.com/quality.

Select 63 at www.HydrocarbonProcessing.com/RS

HPINTEGRATION STRATEGIES PAUL MILLER, CONTRIBUTING EDITOR [email protected]

Terminal automation: More challenging than it looks Due to increasing market, competitive, regulatory and social pressures, terminal automation is more important today than ever before. Nevertheless, many smaller petroleum-product terminals continue to operate with a relatively low level of automation, and many larger terminals operate with outdated, poorly supported automation technology and/or a hodgepodge of disconnected systems. Due to the recent flood of mergers and acquisitions, many multi-terminal owner-operators also find themselves with different systems (or, at best, different versions of the same systems) installed in their various terminals. This can make it difficult to coordinate activities, obtain the required information, avoid incidents, train operators and support the systems. All in all, it’s not a pretty picture. Some good news. The good news is that existing specialist

suppliers in the terminal automation system (TAS) space have been continually enhancing their hardware and/or software offerings to make them even more functional, flexible, interoperable and easy to use. Terminal management systems (TMS) are also available to extend the capabilities of terminal automation systems to help optimize the supply chain and provide more effective tools for real-time decision support (relative to allocations management, credit management, product pricing, etc.). Several prominent, full-line automation suppliers have also effectively leveraged their general automation expertise and wide-ranging portfolios (including some well-targeted acquisitions) to develop comprehensive terminal-automation solutions with compelling value propositions. Most suppliers to this market can point to a successful track record of projects and a fairly long list of customer reference sites. Almost all claim to be able to work well with SAP, Oracle/JD Edwards, and other back office ERP systems used within the oil and gas and petrochemicals industries. Several even have certified interfaces. So, as an owner/operator, how do you go about selecting the right automation solution for your terminal or terminals? Should you stick with your current supplier(s) (if any) or look elsewhere? Should you partner with the same full-line automation supplier that might be providing measurement and control systems elsewhere within your parent organization, or work with a specialist in this area? What are the characteristics and functionalities of the many different suppliers’ offerings within this space, and how do you map these against your specific terminal requirements? These are some of the questions that ARC attempted to answer in a recent series of reports on terminal automation systems. Terminal automation becoming more sophisticated.

While, in the past, a surprisingly large number of petroleum-product terminals operated with minimal automation (limited largely to either the load racks or some limited transactional functions), terminal automation is no longer optional. Today’s terminals, large or small, need to accommodate and accurately account for an

TABLE 1. Some terminal-automation solution providers TMS software specialists (software only)

TAS suppliers (software-based, with some specialized hardware)

Full-line automation suppliers (hardware/software solution)

AC2

Dearman Systems

ABB

CSE Global

General Atomics

Emerson

CSI

M+F

Endress+Hauser

Telvent DTN

Prosoft

Honeywell

Implico

TopTech

Invensys

Varec

Siemens Yokogawa

ever-increasing number of different petroleum- and biofuel-related products and additives, deal with extreme price volatility, and comply with stringent and ever-changing governmental regulations. Several highly publicized terminal explosions, fires and spills underscore the need for increased safety to protect people, equipment, property and the environment. The threat of terrorists or disgruntled employees targeting these relatively vulnerable facilities and ongoing problems with product theft highlight the need for increased security. All this has become extremely difficult, if not impossible, to handle manually or with stand-alone paperbased systems. Challenges in TAS supplier selection. The wide variety of major and minor sub-systems and applications that must be integrated makes terminal automation particularly challenging. In the past, there were only a limited number of TAS suppliers and few, if any, that offered comprehensive terminal-automation solutions. However, there are a growing number of suppliers, several of which offer (at a price) relatively comprehensive, largely pre-integrated terminal automation solutions encompassing hardware, application-specific software and appropriate services. Other suppliers offer more specialized terminal-automation hardware and software, or specialized TMS software solutions. Increasingly, these are designed with a high degree of openness and interoperability, making them relative easy to integrate within a larger TAS solution. In our comprehensive market outlook study, ARC divided the suppliers into two logical categories: full-line automation suppliers with dedicated solutions for terminal automation, and more specialized TAS/TMS suppliers that largely focus on the terminalautomation market. HP Paul Miller is a senior editor/analyst at ARC Advisory Group and has 25 years of experience in industrial automation industry. He has published numerous articles in industry trade publications. Mr. Miller follows both the terminal automation and water/wastewater sectors for ARC. HYDROCARBON PROCESSING MARCH 2011

I 13

Sulfur Experience For the past four decades, Linde Process Plants, Inc. (LPP) has designed and/or constructed sulfur recovery systems. These systems process off gases from gas treating units and sour water strippers. LPP is a world leader in plant modularization and on-site constructed plants. Advantages LPP has the experience, specialized skills, impressive track record, and extensive fabrication facilities to successfully deliver major turnkey process units to global markets. - Extensive technology portfolio - Full turnkey capabilities, including process design, detail engineering, fabrication, construction, and start-up - Competitive pricing - ISO 9001 certified - Single source provider

A member of The Linde Group Linde Process Plants, Inc. 6100 South Yale Avenue, Suite 1200, Tulsa, Oklahoma 74136, USA Phone: +1.918.477.1200, Fax: +1.918.477.1100, www.LPPUSA.com, e-mail: [email protected] Select 81 at www.HydrocarbonProcessing.com/RS

HPIN ASSOCIATIONS BILLY THINNES, NEWS EDITOR

[email protected]

Maintenance, securing the cloud and a pep talk Microsoft’s Global Energy Forum was held in January at the Westin Galleria in Houston. The gathering offered a little bit of everything for interested parties: some upstream, some downstream, lots of intensive technology sessions and a keynote lunch address from former New Orleans Saints quarterback Archie Manning. I was at the event to explore several action items. I was interested in a session on proactive plant maintenance that focused on the expertise of GenOn and Accenture. I wanted to learn more about Microsoft’s efforts to ensure security with its cloud-computing concepts that are being implemented at sensitive refining and petrochemical facilities across the globe. And, finally, I wanted to know what Archie Manning thought about former Saints and Houston Oilers’ coach Bum Phillips. Thankfully, I was able to satiate all levels of my curiosity. Proactive maintenance session.

The proactive maintenance data gateway (PMDG) is based upon the Accenture plant performance solution (APPS). PMDG correlates transactional and realtime plant information relative to critical equipment and systems. The overall goal is to provide management, engineers and station personnel access to accurate plant and financial performance information that is needed to support operations and maintenance decisions in the most efficient manner. This software suite helps a company like GenOn look at its equipment via a life cycle, especially in procurement procedures and keeping track of repairs. It also helps with re-commissioning. GenOn’s goal was to be less than 10% reactive in its maintenance approach. The average industrial plant performs more than 55% reactive maintenance work. Fully implemented proactive maintenance allows for: station personnel to be knowledgeable of roles; the personnel are fully trained in utilizing maintenance technologies; staff members incorporate this

work into their daily activities; key leaders can articulate maintenance spending and failure-mode levels for station equipment; and activities are integrated with maintenance efficiently and utilize root-cause analysis programs to complete the maintenance within a work-flow process. Trustworthy computing. After the

proactive maintenance session, I went to a suite at the top of the hotel and met with Craig Hodges from Microsoft. Mr. Hodges and I spoke about security issues and how they can impact plant safety and real-time collaboration. We also touched upon using technology as a solution to the industry’s aging workforce problem. Mr. Hodges was keen to discuss Microsoft’s initiative known as trustworthy computing. The company seeks to make all the platforms it provides inherently safer. Microsoft works to develop more secure code and it holds its engineering teams accountable for the security of the code they deliver. The other main key to the trustworthy computing concept is the goal to reduce an organization’s exposure to attacks, through threat protection, detection and removal. Microsoft says it collects data using various feedback mechanisms combined with a global multi-vendor research effort to enable fast discovery of protection against new threats. Once oil and gas plants have a bona fide security system in place to prevent mischief and worse, it opens the door for real-time collaboration to be used as a work-around to the aging workforce dilemma facing the industry. “The number one thing companies need to do is capture and classify knowhow. Many customers are using SharePoint [Microsoft’s business intelligence and content management collaboration software] as a way to capture knowledge and then classify and retain knowledge,” Mr. Hodges said. “To mitigate the culture change, business logic can go up in the cloud through a hosted service and retirees can have access to the data and con-

tribute feedback to their replacements.” Mr. Hodges also wanted to note the inroads Microsoft has made into downstream support. Companies like AspenTech, OSIsoft, Honeywell and Invensys all have offerings available that are built on Microsoft technology. “We have a strong ecosystem of partners that is helping manage the refining and petrochemical process,” he said. Looking to the future, Mr. Hodges said that business intelligence and better collaboration will continue to be a big push. All facets of intelligence and collaboration are constantly being examined and reexamined. The essence of all this is Microsoft’s quest to help its customers find, use and share data in the most efficient manner, he said. Archie Manning. Archie Manning’s

lunchtime address was well-received. He touched on his time with the Saints, living in New Orleans, having two NFL quarterback sons and some motivational themes. For those of you reading not familiar with American football, consider Mr. Manning like the star striker on a bad EPL soccer team that is constantly getting relegated. Mr. Manning’s best anecdote concerned his former coach Bum Phillips, who was one of his favorites. HP

Craig Hodges is a Microsoft executive who believes in trustworthy computing.

HYDROCARBON PROCESSING MARCH 2011

I 15

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

1-800-95-SPRAY | spray.com |

Select 62 at www.HydrocarbonProcessing.com/RS

Specify and order standard nozzles spray.com/ispray

HPIMPACT BILLY THINNES, NEWS EDITOR

[email protected]

Pipeline safety bill introduced in US Senate Two US senators have introduced legislation to enhance pipeline safety in the country. The bill strengthens pipeline safety oversight by the US federal government and addresses long-standing safety issues, including the use of automatic shutoff valves and excess flow valves. “Pipelines transport valuable energy resources to communities across our nation. While our pipeline system is largely safe, when accidents occur the consequences can be catastrophic,” said Senator Frank Lautenberg (D-NJ), one of the bill’s two original co-sponsors. “Our legislation will help to ensure the safety and efficiency of this vital transportation network. We can prevent deadly accidents by requiring more advanced technology, increased inspections, and steeper penalties for safety violations.” “Safety should be the bedrock of any responsible business,” said Senator Jay Rockefeller IV (D-WV), the other original co-sponsor of the legislation. “We want to make sure worker and consumer safety remain a top priority. This bill will give the US Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) the tools it needs to provide stronger oversight of our nation’s pipeline system. Safety should never take a backseat to profit.” The US has approximately 2.5 million miles of pipelines that transport oil, natural gas and hazardous liquids. These pipelines are an integral component of the US economy and energy supply, and are

generally considered a safer mode of transportation than other options for moving gas and liquids. Since 2006, there have been approximately 40 pipeline incidents each year that resulted in a fatality or injury. Last September, a natural-gas pipeline exploded in San Bruno, California, killing eight people. In January of this year, a 12-in. gas main exploded in a residential neighborhood of Philadelphia, Pennsylvania, killing a gas company employee and injuring five others. The cause of that blast remains under investigation. The pipeline safety legislation seeks to mitigate pipeline risks through a number of measures. It would reauthorize and strengthen the authority of the PHMSA through fiscal year 2014. Other highlights of the bill include: increased civil penalties for violators of pipeline regulations; expanded excess flow valve requirements to include multi-family buildings and small commercial facilities; required installation of automatic or remote-controlled shutoff valves on new transmission pipelines; instructs the US Secretary of Transportation to establish time limits on accident and leak notification by pipeline operators to local and state government officials and emergency responders; requires the US Secretary of Transportation to evaluate whether integrity management system requirements should be expanded beyond currently defined high-consequence areas and establish regulations as appropriate; makes pipeline information, inspections, and standards available to the public on the PHMSA’s website; and authorizes

TABLE 1. Highlights of Pipeline Transportation Safety Improvement Act of 2010 • Reauthorizes the authority of the US Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) through fiscal year 2014 • Increases civil penalties for violators of pipeline regulations • Expands excess flow valve requirements to include multi-family buildings and small commercial facilities • Requires installation of automatic or remote-controlled shut-off valves on new transmission pipelines • Instructs the US Secretary of Transportation to establish time limits on accident and leak notification by pipeline operators to local and state government officials and emergency responders • Requires the US Secretary of Transportation to evaluate whether integrity management system requirements should be expanded beyond currently defined high-consequence areas and establish regulations as appropriate • Makes pipeline information, inspections and standards available to the public on the PHMSA’s website • Authorizes additional pipeline inspectors and pipeline safety support employees through a phased-in increase over the next four years.

additional pipeline inspectors and pipeline safety support employees through a phased-in increase over the next four years.

2010 midstream M&A activity hits $49 billion Worldwide mergers and acquisitions (M&A) transactions involving midstream energy assets, which include natural gas pipelines, gas-gathering and processing facilities, as well as tankers and diversified holdings, returned to the 2006 all-time high of $49 billion in 2010, according to results in a recent IHS Herold study. This figure represents a 400% increase (above 2009 transaction values of $12.6 billion) in total asset deal value. According to the report, nearly all (94%) of midstream M&A activity in 2010 was driven by spending on gas pipelines and gas-gathering and processing facilities in the US. Several large transactions involving restructurings of master limited partnerships (MLPs) operating primarily in conventional US gas plays contributed more than two-thirds of 2010 total transaction value, but total transaction value for shale gas play assets was up 255% year-over-year, reaching an all-time high of more than $5 billion. Transactions involving gas-gathering and processing facilities led the deal count with 24 deals in 2010, followed by 10 deals involving liquids pipelines and eight deals involving gas pipelines. “The midstream M&A activity in 2010 was clearly a reflection of the rapidly increasing volumes of natural gas that are being produced and brought online in the US combined with the current unfavorable economic climate for gas,” said Cynthia Pross, senior analyst for M&A research at IHS. “I think many of these deals indicate a desire by companies to cut costs by streamlining operations through restructuring, to improve balance sheets, and to gain increased access to capital through larger, consolidated operations. Ultimately, they want to optimize their profitability, since natural gas margins are so thin.” MLPs. Ms. Pross said there were several US midstream restructurings in 2010 involving master limited partnerships. “We HYDROCARBON PROCESSING MARCH 2011

I 17

Continuous Level Coke Drum Measurement System

VEGA Americas Inc., formerly Ohmart/VEGA, is the leader in the level measurement of coke drums, resulting in the development of a new model for coke drum control. Using a series of patented FiberFlex continuous detectors, DSG point level detectors, and gamma radiation sources the Continuous Level Coke Drum Measurement System makes an accurate, continuous level measurement. The system is fully customizable to meet customer needs and provide the following benefits: ϶ Continuous monitoring of the drum level throughout the entire coking cycle ϶ Reduces antifoam usage and saves costs associated with the change out frequency of catalyst beds ϶ Uses the internal RS-485 gauge-to-gauge communication network for extensive diagnostics, increasing uptime, and saving time spent troubleshooting

www.vega-americas.com [email protected] 1-800-FOR-LEVEL Select 92 at www.HydrocarbonProcessing.com/RS

HPIMPACT have seen MLPs streamlining operations through acquisition of their general partners, eliminating general partner distribution requirements and using those funds for capital expenditures or to maintain distributions to MLP unit-holders.” One such example of this streamlining strategy, the IHS report noted, was evident in the largest midstream transaction in 2010, when Enterprise Products Partners, the gas-gathering and processing MLP, acquired its general partner, Enterprise GP Holdings, giving the MLP control of the $22 billion enterprise value MLP. Enterprise Products Partners has geographically diverse gas-gathering and storage assets in Texas, Louisiana, Colorado and Ohio, primarily serving conventional gas plays.

infrastructure continues to develop in the shale plays, we would expect to see more consolidation among players, resulting in fewer companies, but those that remain will be larger, stronger companies with bigger footprints in the shale plays.”

Association says CFATS should be made permanent In written testimony before a US con-

gressional panel, the National Petrochemical and Refiners Association (NPRA) said existing Chemical Facility Anti-Terrorism Standards (CFATS) are effective and should be made permanent. The association’s statement was given to the US House Committee on Homeland Security’s Subcommittee on Cybersecurity, Infrastructure Protection and Security Technologies. “Maintaining a high level of security has always been, and remains, a top priority

Major transaction. Another major

restructuring and the largest gas pipeline transaction value for 2010 was Williams Companies’ sale of its US interstate gas pipeline and midstream business and limited partner interests in Williams Pipeline Partners, to Williams Pipeline Partners for a $11.8 billion total transaction value. This new structure frees up additional funds to direct to Williams Companies’ upstream exploration and production operations, and it consolidates and streamlines midstream operations, cutting operating costs. Williams Pipeline Partners has diversified US midstream operations, with major pipelines, primarily in the Rocky Mountains, that serve conventional gas plays, as well as some assets that serve unconventional gas plays in the Marcellus shale. “Aside from cost control through consolidation and a need to enhance balance sheets,” Ms. Pross said, “many of these companies find the M&A market a way to quickly and economically expand geographically, versus taking on extensive new construction. In particular, we have seen this in US shale plays, where we witnessed a higher deal count than those for conventional gas plays in 2010. Most of these transactions were asset-level deals that ranged from approximately $100 million to $1 billion in total transaction values.” In addition to consolidation among pipeline companies, 2010 saw integrated oil and gas companies selling midstream assets to midstream companies, allowing the seller to focus financial resources on upstream operations while simultaneously locking in long-term midstream capacity agreements with the buyer as part of the deal. “Going forward,” Ms. Pross said, “as Select 152 at www.HydrocarbonProcessing.com/RS 19

HPIMPACT at America’s refineries and petrochemical manufacturing plants,” the NPRA stated in its testimony. “Operators of these facilities are fully engaged in the maintenance and enhancement of facility security.” Established in 2007, the CFATS program was created under the US Department of Homeland Security (DHS) to regulate security at chemical facilities determined by the department to be “high-risk.” “We firmly believe that the current

CFATS program has been successful, but it needs to be made permanent without the addition of any extraneous provisions,” the NPRA said. “CFATS must be allowed to be fully implemented by the DHS before any amendments to the program are considered.” The program is currently operating under a temporary extension granted by Congress. Legislative proposals both to modify the existing program and to make

Wouldn’t it be great if everything was FRACTURE RESISTANT?

the program permanent were introduced in the previous Congress and are expected to be considered again this year. Some previous proposals have included measures to require the use of “inherently safer technology” (IST). The NPRA’s testimony reiterated the association’s longstanding opposition to this change. “IST is a conceptual and often complex framework that covers procedures, equipment, protection and, when feasible, the use of less hazardous chemicals,” the NPRA said. “IST is not just a safety program; it is a process safety program that involves understanding chemical engineering and the supply chain for petroleum-based, natural gas liquids-based and other organic chemicals derived from these basic feedstocks. “We strongly oppose the inclusion of any IST provisions in chemical security legislation. IST and chemical engineering decisions should be left to individual sites and not mandated by the federal government.” The association remains “ready and willing to work with the Committee and Congress toward the implementation of sound, responsible, effective chemical facility security policy.”

US demand for activated carbon growing CeraComp™ Components

A single pump failure can disrupt your plant for days – bringing production to a halt and impacting your bottom line. Replacing silicon-carbide with CeraComp™ dramatically reduces your risk of pump failures! This new material offers the chemical and thermal resistance you require with the increased toughness and fracture resistance you’ve been looking for. CeraComp delivers increased reliability and MTBR (mean time between repair), eliminating catastrophic failure and keeping your plant running efficiently. Contact Greene, Tweed today to learn more about this exciting new material!

45678 Greene, Tweed & Co. | PetroChem & Power | Tel: +1.281.765.4500 Fax: +1.281.821.2696 | www.gtweed.com 11/10-GT AD-US-PP-004

Select 153 at www.HydrocarbonProcessing.com/RS 20

US demand for activated carbon, including both virgin and reactivated products sold by activated carbon suppliers, is forecast to grow 15.8% per year to 1.2 billion pounds in 2014. The main driver of this exceptional growth will be new demand in mercury control technology for industrial air purification applications. These and other trends are presented in a new study from The Freedonia Group. Through 2014, demand for activated carbon in mercury control applications alone is forecast to grow more than fivefold to 520 million pounds. An activated carbon injection (ACI) system used for mercury control in a large industrial facility can consume up to two million pounds of activated carbon annually. As a result, the enactment of even a portion of the emissions standards currently in draft form will represent a tremendous growth opportunity for US suppliers. As powdered activated carbon (PAC) is overwhelmingly the product type used in mercury control technology, the PAC segment will expand to account for twothirds of US product demand in 2014 in volume terms. HP

HPIN CONSTRUCTION HELEN MECHE, ASSOCIATE EDITOR [email protected]

North America Sasol plans to construct what is said to be the world’s first commercial ethylene tetramerization unit, capable of producing over 100,000 metric tpy of combined 1-octene and 1-hexene at its Lake Charles production site in Louisiana. The unit will use Sasol’s proprietary technology to convert ethylene to 1-octene and 1-hexene. This unique process selectively produces alpha olefins required for the high-growth polymer markets. Construction will commence in 2011, and the plant will reach beneficial operation in mid-2013. Endicott Biofuels, LLC (EBF) has an agreement with KMTEX Ltd. to construct a 30 million-gpy biorefinery in Port Arthur, Texas. The biorefinery will use EBF’s proprietary technology for producing highpurity G2 Clear biodiesel. KMTEX will host EBF as well as provide certain construction and operational services. Equity funding will come from Haddington Ventures, LLC, and construction is expected to begin in late January 2011. Jacobs Engineering Group Inc. has a three-year contract with North Atlantic Refining Ltd. to provide turnaround and small capital work services at the company’s refinery in Newfoundland, Canada. Jacobs will provide turnaround planning and execution, including pre-planning and post turnaround activities, as well as delivery of small capital works at the site.

South America Albemarle Corp. and Petrobras have signed a memorandum of understanding to build a world-scale hydroprocessing catalyst (HPC) production plant on the site of their existing joint-venture Fabrica Carioca de Catalisadores SA (FCC SA) in Santa Cruz, Brazil. The new facility will complement existing production of fluid catalytic cracking (FCC) catalysts. The plant will be constructed ahead of significant growth in demand for hydroprocessing catalysts, as Petrobras begins to introduce new hydrotreaters to existing and new refineries over the coming years. Albemarle will provide FCC SA with its leading technology for manu-

facturing HPC, enabling production of STARS catalysts.

Europe Alfa Laval has received an order for compact heat exchangers from a refinery in Russia. The order value is about SEK 70 million and delivery is scheduled for 2011. The compact heat exchangers will be used in the refinery’s distillation process, where the crude oil is preheated for further refining into high-value products such as gasoline. By using Alfa Laval’s compact heat exchangers, it is possible to recover heat from other parts of the process and use it to preheat the oil, thereby achieving a highly energy-efficient solution. The Dow Chemical Co. has increased its monopropylene glycol (MPG) capacity by 15%, an additional 35 kilotons/yr, in its Stade, Germany, plant after completion of an advanced energy improvement and technology optimization project. The Stade expansion was completed in August 2010 during planned maintenance, and it raises the plant’s propylene glycol nameplate capacity to approximately 270 kilotons/yr. Stamicarbon, the licensing and intellectual property center of Maire Tecnimont S.p.A., has acquired the Italian engineering company Noy Engineering from Tecnimont. With this acquisition, Stamicarbon’s extensive licensing, innovation and customer-service experience are combined with Noy Engineering’s polyester and polymerization technologies. Noy Engineering, established in 1983, is said to be a leading company in the field of process engineering and plant contracting. The company designs and builds plants worldwide, based on proprietary technologies. It has developed an extensive portfolio of polymer technologies and acrylic.

Middle East Qatar Petroleum and Shell have signed a memorandum of understanding to jointly study development of a major petrochemicals complex in Ras Laffan Industrial City, Qatar. The scope under consideration would include a mono-

ethylene glycol plant of up to 1.5 million tpy, using Shell’s proprietary only MEG advantaged (OMEGA) technology and other olefin derivatives to yield over 2 million tons of finished products. Süd-Chemie AG and Yara International ASA have a five-year framework agreement on catalysts for fertilizer production. Moreover, this long-term supply agreement will cover more than 50% of the requirements of Qatar Fertiliser Co. (Qafco), a joint venture of which Yara owns 25%. Under the agreement, Süd-Chemie will develop, produce and deliver all frontend catalysts involved in producing ammonia, as well as applied technical support. Süd-Chemie expects to generate more than $40 million from the agreement during the next five years. In particular, Süd-Chemie will provide advanced catalytic technologies for feed purification, hydrodesulfurization, steam reforming, and high- and low-temperature CO conversion and methanation. JGC Corp. has an award to build the gas processing facilities for the Barzan Onshore Project in Qatar. The Barzan Project is managed by RasGas Co., Ltd., which is owned by Qatar Petroleum (70%) and an affiliate of ExxonMobil (30%).

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 depends on the size and complexity of the sort requested. You can focus on a narrow request, such as the history of a particular type of project, or you can obtain the entire 35-year Boxscore database or portions thereof. Simply send a clear description of the data needed and receive a prompt cost quotation. Contact: Drew Combs P.O. Box 2608, Houston, Texas, 77252-2608 713-520-4409 [email protected] HYDROCARBON PROCESSING MARCH 2011

I 21

"
TNBMM
QSPCMFN
DBO
TPNFUJNFT
HP
VOEFUFDUFE
*G
POMZ
ZPVµE
TFFO
JU
DPNJOH :PV
SFMZ
PO
NBOZ
WBMWFT
UP
LFFQ
ZPVS
QMBOU
PQFSBUJOH
TNPPUIMZ
*U
UBLFT
POMZ
POF OPOSFTQPOTJWF
WBMWF
UP
VQTFU
ZPVS
FOUJSF
QSPDFTT
8JUI
UIJT
JO
NJOE
XF´WF
EFTJHOFE EFT
UIF
'JTIFSˆ

XJSFMFTT
QPTJUJPO
NPOJUPS
GPS
ZPVS
BOBMPH
DPOUSPM
WBMWFT
5IF

QSPWJEFT
OE
QPTJUJPO
GFFECBDL
XJUIPVU
UIF
DPTU
BOE
IBTTMF
PG
XJSFT
8IBU´T
NPSF
JU´T
TJNQMF
UP
VTF
BOE
FBTZ
UP
JOTUBMM
/PX
ZPV
DBO
EFUFDU
TNBMM
QSPCMFNT
CFGPSF
UIFZ
CFDPNF
MBSHF
8BOU
UP
MFBSO
BSO NPSF
7JTJU
XXX'JTIFSDPN

5IF
&NFSTPO
MPHP
JT
B
USBEFNBSL
BOE
TFSWJDF
NBSL
PG
&NFSTPO
&MFDUSJD
$P
‰

'JTIFS
$POUSPMT
*OUFSOBUJPOBM
--$


Select 69 at www.HydrocarbonProcessing.com/RS

HPIN CONSTRUCTION The project, located in Ras Laffan Industrial City, 80 km north of Doha, calls for the engineering, procurement and construction (EPC) of the gas processing facilities. This includes a gas-processing unit, a sulfur-recovery unit and an NGL-recovery unit to produce methane, ethane, propane, butane and condensate. The lump-sum turnkey contract is a multi-billion US dollar EPC contract. The Elliott Group has been selected to supply the compressor packages for the residue fluid catalytic cracker (RFCC) and the crude-oil distillation plant as part of Abu Dhabi Oil Refining Co.’s (Takreer) Ruwais refinery expansion. The RFCC unit is the centerpiece of the project. Under contract with the engineering procurement contractor, GS Engineering & Construction Corp., Elliott will provide seven compressor trains, a powerrecovery expander train and associated auxiliaries. Equipment includes a wet-gas compressor, two heat-pump compressors, two refrigeration compressors, a propylene compressor and a hot-gas expander. The Elliott Group will provide the compressors for the crude-oil distillation plant under contract with SK Engineering & Construction Co. Delivery is scheduled for mid-2013, with commissioning to follow in the first quarter of 2014.

between GDF SUEZ and Santos Ltd., has a planned LNG capacity of two million tpy.

beginning of 2012. The investment of more than €10 million will create 60 new jobs.

LANXESS continues to expand its Indian production site in Jhagadia, Gujarat State. The specialty chemicals group broke ground for new compounding facilities, with an initial capacity of 20,000 metric tpy. These facilities will start producing the high-tech plastics Durethan (polyamide) and Pocan (polybutylene terephthalate) at the

Fluor Corp. has an engineering, procurement and construction (EPC) contract with Santos Ltd. for its Gladstone Liquefied Natural Gas (GLNG) project in Queensland, Australia. Fluor’s EPC contract includes upstream facilities associated with the 7.8 million-tpy LNG project that will extract and liquefy gas from coal

 

%LRGHJUDGDEOH

'HFRQWDPLQDWHQDWXUDOO\LQDVLQJOHVWHS

,QRQHHDV\VWHS=\PH)ORZŠUHPRYHVKD]DUGRXVFRQWDPLQDQWV IURPUHÀQHU\DQGSHWURFKHPLFDOXQLWVQDWXUDOVDIH IRU\RXUSHRSOH6XOÀGHV+6 DQGS\URSKRULFVDUHHOLPLQDWHG /(/VDQGEHQ]HQHDUHUHPRYHG5HVLGXDORLODQGJDVDUHJRQH $OOZLWKRXWLPSDFWLQJZDVWHZDWHUIDFLOLWLHVSHUVRQQHODQGWKH HQYLURQPHQW6LPSO\SXWLWҋVDQDWXUDOIRUIDVWDQGHIIHFWLYHUHVXOWV ;LS!c;VSS-YLL!ca`TLÅV^JVT

Asia-Pacific Air Liquide has signed a long-term contract with Tongmei Guangfa Chemical Industry Co., Ltd., whose major shareholder is Datong Coal Mine Group Co. Under agreement terms, Air Liquide will invest around €60 million in a large airseparation unit (ASU) with production capacity of 2,000 tpd of oxygen to supply oxygen and nitrogen to the customer’s methanol-production project in Datong, Shanxi Province, China. Industrial production is scheduled to begin in July 2012. During Phase 1 of the project, 600,000 tpy of methanol will be produced. KBR’s consulting subsidiary, Granherne, has been selected by GDF SUEZ Bonaparte Pty. Ltd. to execute the upstream pre-front-end engineering and design (pre-FEED) study for the Bonaparte Liquefied Natural Gas (LNG) Project, a proposed floating liquefaction plant to be located in the Bonaparte Basin, Northern Territory, Australia. The project, being developed through a joint venture

=\PH)ORZŠLVDPDUNRI8QLWHG/DERUDWRULHV ,QWHUQDWLRQDO//&8QLWHG/DERUDWRULHV ,QWHUQDWLRQDO$OO5LJKWV5HVHUYHG

:RUOGZLGH/HDGHULQ5HÀQHU\ 'HFRQWDPLQDWLRQ

Select 154 at www.HydrocarbonProcessing.com/RS

23

HPIN CONSTRUCTION deposits for eventual export to Asia and other global markets. Fluor booked $3.5 billion in its fourth quarter of 2010 for this new contract. KBR and SK Innovation have started up their advanced catalytic olefins (ACO) demo plant in Ulsan, South Korea. Operations to date have met the companies’ expectations for high-olefins production—particularly propylene, with improved economics relative to steam cracking—due to the technology’s higher total olefins yields and increased propylene/ethylene ratios approaching 1.0. The startup is said to mark the first commercial demonstration of ACO. The demonstration unit achieved design feed rate as scheduled in late October 2010. The ACO process provides an attractive alternative to naphtha steam crackers and, in addition to offering higher olefins production, the process also produces a lower emissions footprint than a conventional cracker. The keys to this novel technology are the development of a proprietary catalyst and optimization of operating conditions by SK innovation, coupled with KBR’s

know how in fluid-bed reactor design and polymer-grade ethylene and propylene production. IndianOil and LanzaTech have an understanding to collaborate in a technology demonstration that will enable IndianOil to produce fuel-grade ethanol. As a part of the collaboration, IndianOil will evaluate LanzaTech’s proprietary gas-fermentation technology in one of its refineries to produce fuel-grade ethanol. Hyperion Systems Engineering has been awarded a contract by The Linde Group to supply an operator training simulator for an ethylene cracker and associated units that form part of a polymer complex to be built in Dahej, India. The plant will manufacture 1.1 million tpy of ethylene, 400,000 tpy of propylene, 150,000 tpy of benzene and 115,000 tpy of butadiene. Together with consortium partner Samsung Engineering of Korea, Linde will build the turnkey plant for India’s ONGC Petro-additions Ltd. When it comes online in late 2012, the Dahej plant will reportedly be India’s largest ethylene plant and the

anchor of a larger petrochemical complex. Lummus Technology, a CB&I company, has a contract with Formosa Chemicals and Fibre Corp. (FCFC) for the license and engineering design of a grassroots cumene and phenol plant to be built in Ningbo, China. The plant, which is expected to start up in 2013, will use Lummus Technology’s Polimeri Europa/ Lummus cumene and phenol technologies to produce 450,000 metric tpy of cumene and 300,000 metric tpy of phenol. KBR’s technology business unit has a contract with Tianji Coal Chemical Industry Group, Co., Ltd., to provide licensing and related engineering services for a grassroots aniline plant to be located in Lucheng, Shanxi, China. The aniline technology is offered by KBR through a licensing alliance with DuPont. KBR will license this leading technology, and provide basic engineering and field-support services for Tianji’s 450 metric-tpd aniline plant. This award follows the successful licensing by KBR of an existing 150,000 metric-tpy aniline plant for Tianji in China. HP

Think Environmental Protection. Think Cashco Vapor Control. The full line of Vapor Control System from Valve Concepts has established the industry standard for engineered quality and in-field adaptability. The engineered modular design enables us to reduce capital outlay costs from 33% to 66% depending on the model.

Our vents are engineered to be fully modular in design so they can be converted in design and function in the field. Any one of our vents can be changed to a pipe away, spring loaded, or even a pilot operated vent without having to buy a whole new unit. Now that’s innovation that VCI customers profit from.

www.cashco com Innovative Solutions

Model 3100/4100

Model 3400/4400

Model 5200

Cashco, Inc. P.O. Box 6, Ellsworth, KS 67439-0006 Ph. (785) 472-4461, Fax: (785) 472-3539

24

I MARCH 2011 HydrocarbonProcessing.com

Select 155 at www.HydrocarbonProcessing.com/RS

Sharper Detection of Off-Angle Cracks Team Phased Array Scanner Improves Inspection Results

Leak Repairs Field Heat Treating Field Machining

NDE/NDT INSPECTION Hot Taps / Line Stops Technical Bolting Valve Repair Valve Insertion

T

he world leader in NDE/NDT Inspection, Team now brings you the Phased Array Scanner. Lower costs, higher quality, greater speed … you get all the advantages of phased array in a highly advanced system. Driven by high-speed electronics and real-time imaging, Team’s Phased Array Scanner reveals the precise location and size of off-angle cracks, f laws and defects. Inspection time and costs are reduced as Team technicians produce fast, detailed cross-sectional images of welds and other internal features. Flaws or defects are measured accurately and marked for repair immediately following examination.   From small boiler tubes to massive turbines and vessels, Team’s Phased Array Scanner saves you time and money by delivering fast, accurate results. Call +1-800-662-8326 or visit www.teamindustrialservices.com/phasedarray. Select 73 at www.HydrocarbonProcessing.com/RS

Emissions Control Pipe Repair Services

HPI CONSTRUCTION BOXSCORE UPDATE Company

City

Plant Site

Project

Capacity Unit Cost Status Yr Cmpl Licensor

Engineering

Constructor

Sonatrach Sonangol SAMIR

Algiers Lobito Mohammedia

Algeries Lobito Mohammedia

Refinery Refinery Treater, Kerosine

2013 2015 2012 UOP

SONARA KBR Tecnicas Reunidas

Technip

Santos\PETRONAS JV Unocal Indonesia Ltd Mangalore Rfg & Petrochemicals Esso Highlands PNG LNG Hyundai Oilbank Co., Ltd. Petrovietnam

Queensland Sichuan Mangalore Kutubu Daesan Dung Quat

Bowen-Surat Basin Sichuan Mangalore Kutubu Daesan Dung Quat

LNG EX Sulfur Refinery EX LNG Refinery, Heavy Ends (2) Refinery EX

1.5 212 9.69 6.6 510 6.5

Mtpy MMcfd MMtpy MMtpy bpd MMtpy

750 U 1300 E 2400 U U 2330 C 3000 P

2011 Total 2013 2011 EIL|Toyo Japan 2014 2011 2016

Fluor WorleyParsons EIL JGC|Chiyoda

EIL CB&I

Technip|JGC| Tecnicas Reunidas

Tecnicas Reunidas JGC|Technip

Altagas Murphy Oil Co Ltd

Harmattan West Tupper

Harmattan West Tupper

Gas Plant Gas Plant

95 MMcfd 180 MMcfd

50 P 180 U

2012 2011

Gas Liquids Eng Gas Liquids Eng

TAHK Projects Ltd

Mozyr Refinery Eval Europe NV Lukoil Neftochim Bourgas Hellenic Petroleum SA Eni SpA AGIP KCO Kuwait Petro Corp Galp Energia Rosneft Repsol YPF Powerfuel Plc

Mozyr Antwerp Burgas Elefsina Sannazzaro Kashagan Rotterdam Sines Angarsk Cartagena Hatfield

Mozyr Antwerp Burgas Elefsina Raffineria di Sannazzaro Kashagan Field Rotterdam Sines Angarsk Cartagena Hatfield

Treater, Tail Gas 240 t/a Polymer (2) EX t/a Hydrocrack, Resid 2.2 MMtpy Amine Recovery 280 tpd Sour Water Stripper 3.5 Mcfd Gas Dehydration (1) 200 MMcfd Sulfur Recovery Unit (2) None Cracker, FCC RE None Sulfur Recovery Unit 114 m-tpd Coker, Gas Oil 920000 tpy Sulfur Recovery Unit 50 m-tpd

E 470 M 95 E U U U 100 C U E U E

2013 2012 2013 2011 2012 2013 2011 2011 2013 2011 2014

135 Mtpy 50 bpd

S U

41 bpsd

E

AFRICA Algeria Angola Morocco

RE

60 Bcfd 200 Mbpd 600 t/a

908 M U E

ASIA/PACIFIC Australia China India Papua New Guinea South Korea Vietnam

Fluor

CANADA Alberta British Columbia

EUROPE Belarus Belgium Bulgaria Greece Italy Kazakhstan Netherlands Portugal Russian Federation Spain UK

Siirtec Nigi Kuraray Axens Haldor Topsøe Siirtec Nigi Siirtec Nigi

Siirtec Nigi Aker Kvaerner Technip Tecnicas Reunidas

UOP WorleyParsons Axens WorleyParsons |Cryoplants

Tecnicas Reunidas WorleyParsons Tecnicas Reunidas WorleyParsons

Tecnicas Reunidas

2013 2011

Tecnicas Reunidas

2014 Axens

Tecnicas Reunidas

Rio San Juan Constr Constr N. Odebrecht Tecnicas Reunidas

2011 CLG|Neste Jacobs 2012 Uhde Inventa-Fischer 2012 WorleyParsons 2014 2014

Samsung Eng

Samsung Eng

WorleyParsons KBR Tecnicas Reunidas

Tecnicas Reunidas

2012 2011 UOP 2011 UOP

Mustang Mustang Mustang

Aker Kvaerner

Siirtec Nigi

Tecnicas Reunidas

LATIN AMERICA Brazil Mexico

Agrenco Bio-Energia Pemex

Parana Minatitlan

Parana Minatitlan

Biodiesel Hydrotreater, Gasoil

Peru

Petroperu

Talara

Talara

Hydrotreater, Diesel

Bahrain City Salalah Mesaieed Yanbu Izmit

Bahrain City Salalah Mesaieed Yanbu Izmit

Lube Oil Refining PET (2) Sulfur Recovery Refinery Utilities

TO

Kenai Tyler Salt Lake City

Kenai Tyler Salt Lake City

Benzene Reduction Cracker, FCC Reactor Benzene Reduction

EX RE EX

EX

MIDDLE EAST Bahrain Oman Qatar Saudi Arabia Turkey

BAPCO\Neste Oil Corp JV Octal Holding & Co Qatar Petroleum Saudi Aramco TUPRAS

36 527 308 400

m-t Mt m-tpd bpd None

9300 296

C E E 580 U E

Petrofac

UNITED STATES Alaska Texas Utah

Tesoro Corp Delek Refining Tesoro Corp

None None None

90 A 10 C 55 C

BOXSCORE DATABASE

AltairStrickland

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, [email protected], or visit www.ConstructionBoxscore.com

26

I JANUARY 2011 HYDROCARBON PROCESSING

Select 156 at www.HydrocarbonProcessing.com/RS

Select 97 at www.HydrocarbonProcessing.com/RS

Reliability has no quitting time. Think about ITT.

In oil and gas facilities around the world, ITT delivers pumps, valves, composite piping, switches, regulators and vibration isolation systems that can handle harsh conditions and keep going. After all, in the 24/7/365 refinery business, the last thing you want is a piece of equipment that fails. With ITT, your processes stay up—and your total cost of ownership stays down. For more information, and to receive our Oil and Gas catalog, visit www.ittoilgas.com or call 1-800-734-7867. Conoflow | Enidine | Fabri-Valve | Fiberbond | Goulds | ITT Standard | Midland-ACS | Neo-Dyn Select 86 at www.HydrocarbonProcessing.com/RS

CORROSION CONTROL

SPECIALREPORT

Updates on improving refractory lining service life Tips help maintenance and operations care and maintain refractory products in high-temperature operations M. MAITY, SABIC Technology Centre, Jubail, Saudi Arabia

T

he hydrocarbon processing industry (HPI) utilizes high-temperature conditions and relies on the performance of refractory lining for various furnaces and vessels. The total installed cost of refractories in HPI facilities is negligible compared to the total cost of the entire complex. However, refractory lining is very important and it plays a critical role in the total performance, profitability and reliable operation of the plant. There are several instances of refractory lining non-performances and premature failures resulted in unplanned emergency shutdown. We will discuss common problems and failures encountered in HPI facilities and some remedial measures to follow.

Background. In the HPI, refractories are mostly installed on fired heaters, hydrogen reformers, ammonia primary and secondary reformers, cracking furnaces, incinerators, process gas boilers, catalytic cracking units, coke calciner, sulfur furnaces, utility boilers, air heaters, ducting, stacks, etc. Some of the listed equipment operate under high pressure, and operating temperature can vary from very low to very high (approximately 500°C to 1,600°C). Refractories play a critical role for the total performance and reliable operation of high-temperature processing units. Refractories can be the controlling factor in the success or failure of a furnace and vessel’s service life, as well as the safe and profitable operation of the plant. Most HPI facilities operate under continuous operating mode and will run for several years before a scheduled shutdown for maintenance or turnaround. Therefore, the prime objective here is equipment reliability. Also, in the HPI, the time between

shutdowns and maintenance outages is increasing with the implementation of stringent quality control and preventive maintenance programs. The shutdown period is usually short in duration and is planned primarily for mechanical overhaul. The life and durability of refractory lining should not be the determining factor in the frequency and duration of shutdowns. In spite of its importance, refractories are, in many cases, neglected, misunderstood and abused, and the uncared for refractory can cause several problems during regular plant operations. The unexpected problems can cause an emergency shutdown or require longer maintenance time to rectify both the damages in the refractory lining as well as mechanical damages to unit equipment. Also, the sudden failure of the lining can pose a significant risk and threat to plant safety. Therefore, it is important for HPI facilities to optimize the lining reliability and performance in various applications. It may be possible to minimize refractory related problems and reduce unnecessary expenses by introducing sound engineering practices, following proven guidelines and sharing practical experiences while designing the lining and selecting construction materials, installation methods, etc. This article will discuss several common problems and failures of refractory lining and highlight important considerations to mitigate such problems. Common problems and failures.

The performance of any lining in a furnace is considered to be reasonable when similar service lives are achieved on a regular basis. Premature lining failure may be defined as one that does not achieve normal or average performance and service life.

The furnaces and vessels in the HPI do not consume the refractory with corrosive liquid metal, slag, abrasion, impact, etc., which are common in metallurgical furnaces. Refractory lining problems and failures are mainly due to thermo-mechanical stresses, erosion and chemical attack. The most common refractory problems as experienced in the HPI are: • Hot spots (higher casing temperature) • Excessive cracking • Spalling of lining (thermal, mechanical, structural) • Erosion and thinning of lining • Chemical attack/corrosion from process gases (such as hydrogen, carbon monoxide, sulfur dioxide, alkalies), flue gases (sulfur, sodium, vanadium), steam, etc. • Acid-gas dew-point corrosion of refractory and metallic parts • Partial melting and degradation of lining • Excessive shrinkage and development of gaps • Anchor failure and detachment of lining from wall • Failure of metal liner over refractory • Explosive spalling during dry out • Mechanical damages. The extent of damages and failures may vary equipment to equipment. Sometimes the problems appear within a short time of operation or during commissioning, and this can become a major concern. Most processing industries handle highly combustible hydrocarbons. Therefore, lining problems in critical pressure vessels and boilers are a major concern and, in many cases, causes immediate shutdown to avoid any accidents. HPI processing plants are complicated involving continuous chain reactions in the interconnected network of HYDROCARBON PROCESSING MARCH 2011

I 29

SPECIALREPORT

CORROSION CONTROL

reactors, vessels and pipelines. Any problem in any particular vessel due to a refractory problem can result in a complete shutdown of the unit and/or the entire facility. Here are some of the common examples of refractory damage (Figs. 1–12). The reduction in lining thickness in the catalytic cracking unit is caused either by cracking and spalling due to heavy thermal shock or erosion by catalyst particles and subsequent hot spot or partial exposure of

30

shell plate. Also, mechanical damage in the cyclones due to erosion of the lining and plate may disturb the unit operation. Failure of the lining due to inadequate anchor system is very common for all kinds of lining. Explosive spalling may be caused during the initial dry out due to uncontrolled heating. Differential movement of the shell and lining due to a mismatch in expansion behavior, uncontrolled heating-cooling,

FIG. 4

Typical refractory lining failures— Castable damage and anchors exposed.

Typical refractory lining failures— Castable wall detached.

FIG. 5

Typical refractory lining failures— Loose bricks hanging.

Typical refractory lining failures— Roof lining collapse.

FIG. 6

Typical refractory lining failures— CF module fallen from roof.

FIG. 1

Typical refractory lining failures— Crack in castable lining.

FIG. 2

FIG. 3

I MARCH 2011 HydrocarbonProcessing.com

mechanical stresses, etc., can cause various problems in the lining. In many cases, localized hot spots or high temperatures are controlled by steam impingement to reduce the casing temperature and continue plant operation. Reductions in thermal efficiency, as well as associated risks and plant safety, are major concern for such cases. Failure analysis and corrective actions. Refractory-lined equipment

function as a system. There are several interacting physical and chemical effects that may be ongoing, progressive, cyclic, etc., that will definitely control the performance of refractory. Therefore, in most of the cases, it may be very difficult to conclude a single reason for nonperformance and premature failure of the lining. Also, there are numerous precommissioning factors related to design, material selection, installation, etc., as explained previously that directly affect performance. In some cases, the poor quality material or installation workmanship of the refractory may contribute to the problem. But it is also possible that a good quality refractory or installation can give unsatisfactory performance because of a combination of other factors. The analysis of any refractory problem should consider numerous factors and identify the main root cause for the problems and select appropriate recommendations. Identifying the actual reason of nonperformance for the lining is a difficult task, and this involves systematic study and analysis of the problem. Reviews of background information particularly design engineering, quality and source of material, installation procedures and records, operational records, post-service inspection and maintenance history are important for the root-cause analysis. Awareness of the operational parameters and potential degradation mechanisms that can lead to failure of the lining is essential to understand the problems and remedial measures. A thorough system analysis should result in a better understanding of the various factors that control the performance of the lining and yield in sound basis for corrective remedial measures and actions. Therefore, clues and relevant facts of failure should be gathered, analyzed, explored and studied to make a meaningful conclusion. Collecting samples and selective laboratory testing should be part of the failure analysis, if required. Important factors responsible for the performance of the lining are briefly explained here.

How come the weather is the only nasty thing at this gas field?

Visit us at booth A220, hall 1 at GASTECH 2011, March 21–24, Amsterdam, Netherlands

E50001-E440-F140-X-4A00

Innovative compressor trains from Siemens boost production and preserve the environment. After 50 years of operation, the Groningen gas field in the Netherlands is now, and also for the next decades, fit to secure the supply of its clients. The facilities are fully modernized. One key success factor was the long-term relationship of the operating company NAM and its contractors. Siemens has advanced the compression and variable speed drive technologies to ensure the adaptation of the gas supply to fluctuating demand, to slash maintenance requirements, and to maximize environmental performance. Highest availability and low power consumption of all units are the best basis for an eco-friendly and successful operation. Learn more: www.siemens.com/energy

Answers for energy. Select 52 at www.HydrocarbonProcessing.com/RS

CORROSION CONTROL

Maximize Material Performance! SilcoTek coatings make the impossible... possible. Solving problems for the process sampling, analytical inertness, oil, gas and semiconductor industries for over 20 years.

s%LIMINATESURFACEINTERACTIONWITH active chemicals like H2S, mercury and many more! s$RAMATICALLYIMPROVECORROSION resistance s%LIMINATECOKINGORcarbon fouling s2EPELSMOISTURE QUICKDRYING Improve performance of many common process materials

s3TAINLESSSTEEL s.ICKELALLOYS s#ERAMIC s'LASS

s4ITANIUM s#ARBON

Important factors governing refractory lining performance.

Whenever there are some problems in lining, we mostly conclude that either the refractory material was bad or the installation was poor. However, in reality, the problems are probably due to a combination of multiple factors and may not be solely just one factor—poor installation or inferior refractory quality. Clients as well as the project contractors, suppliers and others don’t always recognize that their actions and oversights can directly affect the performance of the lining. To address the problems associated with refractories, it is necessary to recognize the main factors that are involved and contribute refractory related problems. These factors are: • Design of furnaces/vessels • Design of refractory lining and detail engineering • Selection of refractory materials and specification • Quality of refractory materials • Installation of lining • Curing, startup and maintenance of lining

FIG. 7

Typical refractory lining failures—Casing plate corrosion with perforation.

FIG. 8

Typical refractory lining failures— Acid condensation below lining.

,EARNHOW3ILCO4EKCANIMPROVE the performance of your products, VISITOURWEBSITE

WWWSilcoTek.com or call us at (814) 353-1778.

Select 157 at www.HydrocarbonProcessing.com/RS

• Operation practices • Inspection and maintenance practices. It is important to give attention to these listed factors to avoid and minimize unexpected and premature failure or problems of lining. Design of furnace/vessels. The performance and stability of the refractory lining depends on the structural design of the furnace and its configuration. Sometimes adequate attention is not given to the refractory lining and its engineering related issues during early plant equipment design and detail engineering. One of the most common observations is that the refractory designers or specialists are involved at the final stage of project implementation or during installation. This may lead to several compromises with refractory-lining design and engineering practices as there is limited scope for change in vessel design, operating conditions and the process to reduce the impact of these factors on lining performance. The problem of refractory lining may be due to insufficient combustion volume. The heat released within the system is more than absorbed by the process and is dissipated through walls or exhausted with flue gases. In such cases, there are possibilities of the lining approaching the flame temperature and causing several problems. The burner type, its design, location, flame shape, possibilities of flame impingement, flowing pattern of flue gases, etc., may affect the lining. In many cases, limited vessel dimensions, inaccessibility and complicated configuration restricts the best lining practices during initial construction as well as subsequent maintenance and repair. Design of refractory lining and detail engineering. The design and detail engineering of the lining for a furnace and vessel should be done on the basis of careful analysis of service conditions, availability of refractory materials, thickness requirements, anchorage, ease of installation and future repair and maintenance. Adequate knowledge on operating conditions that are active—such as temperature, pressure, chemical attack, thermal shock, abrasion, erosion, furnace gas composition, mechanical movement, vibration, etc.—should be very useful for the optimum lining design and selection of refractory. Chemical attack may occur from gases such as steam, hydrogen, carbon monoxide, alkalies, sulfurous gases, etc.; these acid gases can initiate various problems in the lining, which

MERICHEM COMPANY

The Merichem You Know. The Merichem You Want to Know. Next-generation hydrocarbon-treating technologies, upstream and downstream, worldwide For 65 years, Merichem Company has been a leader in hydrocarbon sweetening and sulfur extraction processes. We still are. But there’s more. We’re also a global provider of focused technology, chemical and service solutions. Visit our new website at www.merichem.com to see how a customer-driven, multi-technology approach to H2S removal, mercaptan removal and caustic management can make a difference for you. And get to know us, all over again.

Sweet Solutions.™

www.merichem.com

Select 79 at www.HydrocarbonProcessing.com/RS

SPECIALREPORT

CORROSION CONTROL

are explained in the literature. All of the important operating factors and any other criteria specific to the process under consideration should be verified for their possible effect on the performance of the lining. Thermal calculation is essential for any lining to ensure design casing temperature, temperature gradient in the wall and heat losses. Thermo-mechanical FEM analysis may be carried out for critical vessels and load bearing refractory structures to predict temperatures, stresses and displacements in the lining. The FEM analysis is a reliable tool to investigate the spalling mechanisms and to develop ways on improving the lining behavior. Anchors are used for almost all types of refractory applications. These are mostly metallic type. Lining failures due to inadequacies in the anchoring system are very common (Figs. 6, 9 and 10). Selecting the proper metallurgy, anchor dimensions, configurations, and spacing are very important to achieve the maximum service life of the lining. Where metal liners are used over the lining, the mechanical design should be sound and allow free movement of the liner on one end from its fixed positions.

While designing a new lining for a vessel it is important to consider ease of future maintenance and repair. However, this aspect of the lining design is compromised in many cases because a lining system that is maintenance friendly may be more expensive with respect to initial materials and installation expenses as compared to a lining that is adequate to meet the initial contractual requirements. Details of the lining layout structure, thickness, dimension, shape and sizes of individual bricks and other shaped items, their laying and bonding patterns, provisions for expansion allowances, support of brick-wall, etc., should be part of the detail engineering for each piece of equipment. Finally, practical experiences and experience-based judgments are very important for successful and reliable design of any refractory lining. Therefore, involvement of experienced engineers from the design stages to final implementation is one of the essential parameters to get the optimum performance of lining. Selection of refractory materials and specification. The majority of refractories used in the HPI are alumina–silicate and

FIG. 9

Typical refractory lining failures— Oxidation of anchor.

FIG. 11

Typical refractory lining failures— Brick wall bulged.

FIG. 10

Typical refractory lining failures— Surface spalling and exposed anchor.

FIG. 12

Typical refractory lining failures— Brick wall collapsed and hexmesh detachment.

34

I MARCH 2011 HydrocarbonProcessing.com

high alumina varieties—both insulating and dense types. Mainly bricks, monolithics, ceramic fiber items, different types of insulating blocks, etc., are used for lining. Bricks and monolithics are available for both dense and insulating types with a wide range of properties and each material has an application that is more suitable. Selecting materials should always be based on properties and specifications suitable for the specific application and operating conditions. Most refractory materials react and change during service according to the principle of thermo-chemistry. It is important to know the furnace atmosphere, presence of any major or minor chemicals and their possible effects on the lining. Selecting materials solely based on price and ease of installation should be avoided. Very often, monolithic lining system is selected in the lining design of critical vessels where brick lining or some other design may be more suitable. The selection may be due to cheap and easy availability of monolithics and easier installation than brick lining and to avoid preparation of too many engineering drawings for the complicated brick shapes and laying details. In many cases, recommendations of refractory manufacturers are biased and based on their available product ranges, which may not be appropriate for the required conditions. Selection should be based on the desired service life and cost considerations. Initial cost of refractory lining should not be the selection criteria but rather the service life of lining under operating conditions. It is better to develop the material specification for any application based on discussions with the manufacturers to ensure it is more practical and realistic. The specification should be regularly reviewed and updated based on actual performance of used materials and current industry practices. Quality of refractory materials. Refractory materials are heterogeneous, and quality varies both as manufactured and as installed. Materials should be procured against specifications most appropriate to the specific application. For critical applications, purchasing of materials based on a comparison of product datasheet or catalogue specifications or equivalent principles should be avoided. The actual performance references and records for specific products or brands should be verified against similar applications. Reviews of manufacturing facilities and quality-control program, and random inspection and testing of important properties are essential.

MERICHEM COMPANY

Problem: Sour Gas Sweetest Solution: LO-CAT H2S Removal/Recovery

®

With a wide range of system capabilities, Merichem Company offers both liquid and solid media desulfurization technologies to sweeten gas and air streams containing virtually all levels of hydrogen sulfide or mercaptans. Our extensive experience includes treatment of natural gas, amine acid gas, sour water stripper gas, fuel gas, hydrogen recycle gas and Claus tail gas. LO-CAT’s flexible technologies and worldwide services are backed by over three decades of reliability. Join 200+ licensees in 29 countries on 6 continents meeting today’s compliance requirements by turning nasty H2S into elemental sulfur — efficiently, effectively and environmentally sound. Learn how sweet it is, visit www.merichem.com/LO-CAT Merichem: A global provider of focused hydrocarbon-treating technology, chemical and service solutions.

Sweet Solutions.™ P: 847.285.3850 | E: [email protected] | www.merichem.com Select 78 at www.HydrocarbonProcessing.com/RS

SPECIALREPORT

CORROSION CONTROL

Lining installation. Unlike other engineering subjects, there are very few wellestablished and recognized engineering standards, design and installation guidelines for refractory jobs to ensure quality installation of the lining and its subsequent satisfactory performance. In many applications and contracts, the only quality assurance is limited to warranty and guarantee of material and lining for a limited operating period. Installations of refractory rely upon manpower. Because of the human element, care should be taken to ensure involvement of only experienced manpower in the installation. Developing job specific installation procedures, quality plans and acceptance criteria of the installed lining, prequalification materials, and installation crew are some of the important factors that companies must address before any job. API 936 guidelines, developed by the American Petroleum Institute (API) are very useful tools for quality control of monolithic lining. There are also some specifications and standards developed by Process Industry Practices (PIP) especially for process industries. Prequalification of materials, installation procedures, machinery and crew, testing of as installed samples, ambient condition monitoring, acceptance criteria for installed lining, involvement of neutral inspection agency for quality monitoring, etc., are important requirements of these standards. Many clients and licensors have started recommending compliance to these guidelines for critical applications. Possible quality control for brick and ceramic fiber lining in similar lines are expected to improve quality for the total installation job and compliance to engineering practices. Using common standards and guidelines will help the industry to mitigate installation problems. This also helps in developing quality installation manpower that are actually executing the jobs in the field, particularly crews, masons and supervisors. Dry out and heat up. The heat dry out of a new lining, particularly monolithic lining, is a critical step when considering the total quality for the installation. Slow and controlled removal of free and chemically bonded water from the lining system is essential before actual startup of the unit. Explosive spalling or cracking may occur in lining when quick and uncontrolled initial heat up or dry out of the refractory is done. Also, alkali hydrolysis is a major concern for monolithic lining in tropical and 36

I MARCH 2011 HydrocarbonProcessing.com

subtropical weather conditions. Dry-out needs to be done at the earliest to prevent damage. When delays in dry out or complete dry-out are not practical, suitable sealants may be used on monolithic lining to reduce alkali hydrolysis reaction and damage. Also, natural-air circulation should be maintained within the furnace to avoid hot and humid conditions. Developing job specifications for the dry out schedule is essential instead of following general guidelines from the supplier. Burner size and location, exhaust location, air volume, velocity, temperaturecontrol locations, etc., need to be properly addressed. Permanent burners or special external burners may be used for dry out depending on requirements. Permanent burners have limitations of inadequate temperature control at the initial stage. Many specialized dry-out agencies are available to carry out this job in most professional manner. Unit operation. Production and operation personnel should be aware of the process parameters that may affect the service life of the refractory lining for furnaces or reactors. Minor changes in operating conditions and processes may strongly influence the performance of any lining. Abnormal changes in burner operation— such as flame impingement on refractory surface, incomplete burning of fuel causing change in furnace atmosphere, changes in temperature, pressure, fuel quality (dirty fuel), heating and cooling rate, etc.—have direct effects on the refractory lining. Operating at a higher temperature than specified in the design can reduce the service life of the refractory. High limit thermocouples should be located at strategic positions for monitoring and controlling temperatures within the system. In many cases, the problem or initiation of deterioration in lining due to operational issues may not become visible immediately. Therefore, it is important to gather information on operational information and records while studying the problem. Inspection and maintenance. Regular inspection of the lining and condition monitoring should be part of the operating plan for critical equipment. The frequency of inspection may be decided based on historical problems, severity of operating conditions, complexity of design and other factors. Timely identification of problems and corrective actions may lead to longer life of the lining. Temperature-sensitive paints are widely used to monitor casing

temperature and locate hot spots. Infrared thermography is an important tool for online-temperature measurement, condition monitoring of lining, predicting problems, and maintaining equipment uptime during a problem. Thermography is very useful for locating and monitoring effected areas in case of any operational upset or localized problem in the furnace, and thus allowing the inspectors insight into what is happening inside the lining. This allows the plant to make appropriate decisions in planning the shutdown schedule and maintenance repairs and estimating the total materials needed for these repairs. The maintenance strategy for refractory linings should be based on cost-effective proactive systems rather than on conventional reactive systems. The probable reasons and mode of failure should be ascertained before redesigning or repairing a lining. Change in lining design and installation practices without proper analysis of factors limiting the service life of the existing lining may not be a longterm solution. All repair and maintenance jobs should be treated like a new job with proper quality control. It is important to inspect and record all repairs to maintain a proper trend and database. Other factors. There are many other factors that may directly or indirectly affect the performance of the lining. In most construction sites, refractory installation is one of the last activities. With any delay in other pre-activities, there is always pressure on shortening and possibly compromising the refractory installation schedule to make up for earlier delays. This attitude of getting the job done fast may have major adverse effects on quality. Ambient temperature and working conditions for workers have direct effects on the quality of the installation job. Implementing cost-cutting measures, purchasing refractory and selecting the contractor solely on the basis of commercial issues with less importance on quality, services, etc., may be the contributing factors to poor performance over the longer term. Observations for quality. Refrac-

tory is a diverse class of materials that are used to insulate and protect industrial furnaces and vessels. The properties of the refractories are tailored to specific applications by varying the composition of raw materials. The technology of refractories is making remarkable progress recently.

CORROSION CONTROL Developments in refractory lining design system and performance specifications with as-built quality requirements are very important for this specialized field. With every lining failure, there is a degree of uniqueness that results from variability in design and application, complexity of service conditions and material behavior. Awareness of the potential degradation mechanisms of lining and operating parameters is essential to mitigate such problems. Implementing various quality control programs, advanced installation procedures and online inspection can contribute to satisfy results. HP BIBLIOGRAPGHY American petroleum Institute, “API RP 936, “Refractory installation quality control guidelines-inspection and testing monolithic refractory linings and materials.” Biglin, J., “Refractory Maintenance and repair,” The American Ceramic Society Bulletin, Vol.75, No. 5, May 1996. Crowley, M. S., “Design better vessel linings,” Hydrocarbon Processing, December 1979. Devera, D., “After installation the importance of a controlled dry-out for castable refractories,” The Refractories Engineer, July 2003. Gardner, A., “FCC Cyclone Refractories,” Today’s Refinery, November 1998. Hanley, R. M., “Refractories utilization in the hydrocarbon processing industries,” The Refractories Engineer, July 2000. Hancock, J. D., “Practical Refractories,” Cannon & Hancock CC. Heard, N. E., “Quality Control Practices in the US Petrochemical Industries,” Unitcer, 1989. James, S., “The Fundamentals of Refractory Inspection with Infrared Thermography.” Schacht, C. A., Refractory Linings, Marcel Dekker, Inc. Semler, C. E., “Overview of refractory problems in industry,” Interceram, Vol.40, No.7, 1991.

MERICHEM COMPANY

Sweet Solutions.™

Announcing… next generation hydrocarbon-treating technology Problem: Mercaptan Odor Removal. Solution: It’s modular, simple and cost effective, too. Before your crude hits the pipeline, the light mercaptans must go. In remote areas, that’s especially tough. MERICAT™ C uses reliable FIBER-FILM® patented technology to sweeten mercaptan odors, even where access is limited.

Manabendra Maity is working as a refractory specialist at the Materials & Corrosion Section of Sabic Technology Centre, Jubail, KSA. He holds B.Tech degree in ceramic engineering from Calcutta University and a M.Tech degree in ceramic engineering from IT-BHU, India. He has more than 16 years of extensive experience in refractory lining design, engineering, installation & quality control, failure analysis and troubleshooting for furnaces and vessels for the refining, petrochemical and metallurgical industries. He started his career in 1994 as a refractories & nonmetallics engineer in Engineers India Ltd., New Delhi and continued there until 2007. It was followed by two years in Ciria Division of Thermal Ceramics. Mr. Maity is life member of India Ceramic Society & Indian Institute of Ceramics. He has qualifiedfor API-936 Refractory Personnel Certification Program.

Finding the right treating application for hydrocarbon streams is challenging. Merichem’s decades of experience and commitment to innovation means treating gaseous and liquid hydrocarbons is efficient, economical and clean. Learn how sweet it is at www.merichem.com/MERICATC Merichem: A global provider of focused technology, chemical and service solutions.

P: 713.428.5000 | E: [email protected] | www.merichem.com Select 158 at www.HydrocarbonProcessing.com/RS

37

Anytime, Anywhere

®

Anchor-Loc 3 insulating fiber

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.

Fast, cost-effective delivery The Unifrax sales team provides design recommendations, engineering layout and product sourcing options, ensuring a costeffective furnace lining solution wherever you’re located in the global market.

Universal specifications

For more information and a list of our worldwide manufacturing locations, visit the Unifrax website, call 716-278-3800 or email [email protected].

Anchor-Loc 3 modules are produced in each of our global manufacturing centers using the same raw material specifications, dimensional tolerances and assembly procedures, providing product uniformity and consistency worldwide.

www.unifrax.com

Select 68 at www.HydrocarbonProcessing.com/RS

CORROSION CONTROL

SPECIALREPORT

Flare stack structure revamp: A case history An innovative approach was used to repair an older flare structure online without an extensive shutdown S. SINGH, Reliance Industries Ltd., Nagothane, Maharashtra, India

A

gas flare, alternatively known as a flare stack, is an elevated vertical conveyance that is part of installations such as oil and gas wells, oil rigs, refineries, chemical, petrochemical and natural gas plants, and other facilities (Fig. 1). On oil- production rigs and in refineries and petrochemical plants, the flare stacks primarily serve to protect vessels or pipes from overpressuring during unexpected plant upsets.

Safety system. Whenever plant equip-

ment is over-pressured, the pressure, relief valves on the equipment automatically release gases (and sometimes liquids as well) that are routed through large piping runs called flare headers after liquid hydrocarbons are completely vaporized and then send to the flare stack. The released gases are burned as they exit the flare stack. The size and brightness of the resulting flame depends on how much flammable material was released.

Steam can be injected near the end of the flare tip to reduce formation of black smoke. The injected steam does, however, increase the noise level of the burning gas. To keep the flare system functional and instantly useable, a small amount of purge gas is continuously burned. It thus resembles a pilot light, maintaining the system ready for its primary purpose as an overpressure safety system. The continuous gas source also helps to prevent oxygen ingress into the system. As mentioned earlier, flare systems enhance plant safety by dependably disposing of all hydrocarbons discharged during plant upsets. All safety valve releases go to the flare system. There are, however, two types of flare feeder systems in ISBL: • A wet flare header is used to handle flare gases that contain moisture but are not “cold” gases. • An intermediate flare header, which could contain some moisture and nor-

mally handles some cold vapors (up to –45°C). • A dry flare header designed to handle dry flare gases. These will also be cold, with normal temperatures below –45°C. • A low-pressure acetylene flare header, exclusively provided to handle acetylenerich gases. At Reliance’s Nagothane facility, a large flare stack with a design load of 1,000 metric tph is located on the north-east side of a gas-cracker plant. Flare headers from individual plants—polypropylene, lowdensity polyethylene, linear-low density polyethylene, gas cracker-OSBL and gas cracked-ISBL) join the main flare header, which routes to the flare stack (Fig. 2). The main flare header leads to a knockout drum in the flare area. The purpose of the knockout drum is to separate entrained liquid droplets carried with the gases passing through relief valves. Liquid capture avoids the danger

Water seal drum Water inlet

CPP

Flare stack

Knockout drum

FIG. 1

Flare stack.

FIG. 2

LD

LLD

WF drum

PP

ISBL

B-1

OSBL

Flare system schematic at the Nagothane plant in India.

HYDROCARBON PROCESSING MARCH 2011

I 39

SPECIALREPORT

CORROSION CONTROL piping were found damaged as well and some grating had been totally eaten away by corrosion. Replacement or repair of the entire structure during a projected 17- day maintenance shutdown was contemplated but judged very difficult. It was also realized that working on a flare stack structure during normal plant operation involves high risks; needless to say, flaring can occur at any time due to plant upsets.

FIG. 3

Repair approach. The conventional

Damaged structure.

FIG. 6

FIG. 4

Extreme corrosion on a flare stack in India.

Lift arrangement and protective metallic shields.

The molecular seal consists of a gas “lead pipe” and an inverted cylinder over the pipe. Gas flows in an upward direction, turns through 180° and flows downward for a short length before being redirected again through 180° and back to the original flow direction. In the static condition, gas lighter than air will tend to collect in the upper bend and heavier gases will tend to settle at the lower bend, sealing off the stack against backflow of air. The flare tip is mounted on top of the molecular seal and contains three pilot burners. Damage to the flare tip due to flame burn back near the tip is avoided through the use of refractory lining on all exposed anchor and mesh surfaces. Exploring the failure history. The

FIG. 5

Pre-shutdown scaffolding work.

of burning droplets falling from the top of the flare stack. Flare gas free of liquid flows to a water-seal drum; its purpose is to provide protection against pulling a vacuum and to prevent a flash back in the flare header. Occasionally, the stack draft effect could decrease pressures below atmospheric at minimum flare gas loads. The water seal also eliminates the ingress of air into the flare system and any attendant risk of explosion. The flare stack at this facility is 100 m high and has a diameter of 1.52 m. The flare height of 100 m includes the flare tip and a molecular seal installed just above the flare stack and below the flare tip. 40

I MARCH 2011 HydrocarbonProcessing.com

flare stack at Nagothane was commissioned in 1989. Since then and at every plant shutdown, the flare tip was being replaced because it experienced damage during flaring operation. Until 2010, the flare stack structure had never been repaired and neither had it been repainted after plant commissioning because no time was available during annual or major shutdowns. However, inspections of the flare stack structure, ladders, grating, clamps and associated piping was conducted before a major turnaround scheduled for early 2010. The support structure of the flare stack was found damaged, and loss of thickness was observed and measured at various locations, mainly under the support plates (Figs. 3 and 4). Fuel gas and steam

mode of replacing or repairing a flare structure, piping and subsequent painting would take more than 100 days. It was, therefore, judged impossible to do the entire job during a planned shutdown of only a 17-day duration. With that in mind, initial discussions were aimed at completing the job in discrete phases; specifically up to 44 m elevation, in steps dubbed non-shutdown or pre-shutdown tasks. The remaining work from 44 m to 100 m elevation was to be done during the scheduled major shutdown. Scaffolding and crane arrangements were implemented as pre-shutdown work (Fig. 5). That left about 24 days as the time required for work conducted while the facility was shut down. Therefore, and after further deliberations, it was agreed to plan additional pre-shutdown work to a height of 65 m during non-shutdown and carry out the remaining jobs from 65 m to 100 m elevation with the facility shut down. Risk assessment and safety. Listed

among the special risks and risk mitigation steps were: • Heat radiation due to flaring • Exposure to work at heights above grade • Descending “fire balls” during heavy flaring • Stinging insect attack or bites. Among the major work items were protective metal shields of 1 mm thickness. These were installed at elevations 26 m, 44 m and 65 m (Fig. 6). The sheet-metal guards were affixed to the grating of all scaffolding grating. In addition, ceramic blankets were fastened to the sheet metal to substantially reduce the intensity of the radiant heat and avoid burning risks. Flood lights were provided for job execution at night, and water shields were installed at the 66-m elevation to effect cooling during flare events. As part of the water-shield system, two water-curtain nozzles were affixed horizontally to the

CORROSION CONTROL structure. Their effectiveness was demonstrated before they were mounted at the jobsite. Two lifts and a crane (hoist) were deemed appropriate for worker rescue and to facilitate the lifting of both personnel and materials. One crane was designated for emergency rescue of workers; and a suitable cage was fabricated and load tested before usage. Of course, the crane was also used for lifting and lowering of materials. The rack and pinion lifts were rated at 1 ton and 0.4 ton capacities, respectively. They too could be used for rescue purposes and up to 22 persons could be evacuated in case of an emergency. Nomex coveralls were mandatory for all workforce members and their supervisors. Whenever heavy flaring was to take place, warnings would be issued to the workforce in the flare area through redundant means, including mobile handsets and a plantwide loudspeaker (audio) system activated from the control room. The water-spray curtain would commence immediately so as to proactively cool the working area. All persons could immediately retreat safely to the protective area below the metallic shield (Fig. 7). In essence, the non-shutdown and shutdown work encompassed: • Erection and dismantling of crane and lifts • Scaffolding erection and removal up to 100-m elevation • Affixing of metallic shields on the scaffolding gratings at elevations of 26 m, 44 m and 65 m • Water-shield system installation at the 66 m elevation • Replacement or repair of 20 metric tons of structure and replacement of 2.3 metric tons of grating (Figs. 8 and 9) • High-pressure water blasting of structure and flare stack; power tool cleaning instead of manual wire brush; all followed by painting • Insulation and cladding replacement of 3-in. and 8-in. steam lines up to 100 m elevation • Damaged fuel gas and steam line replacement. Goals. Initially, the non-shutdown tasks were planned to be done during daylight hours. With unscheduled flaring on some days, the daytime work had to be suspended. Lost time was recovered and work execution scheduled on a round-the-clock basis using floodlights at night to make up for lost time and to complete the non-

FIG. 7

SPECIALREPORT

Water shield at 66 m.

FIG. 10A Massive flare stack at full usage.

FIG. 8

Platform and clamps after replacement.

FIG. 9

Piping, insulation and cladding replacement.

shutdown part of the repair job in time. All repair work on the flare stack structure was successfully done without incident within the scheduled period—-85 days for non-shutdown work and 16 days for shutdown work. This was the first time in the history of Reliance that repair work on a rather massive flare stack structure (Fig. 10) has been done online without any safety incident. HP ABBREVIATIONS NMD- Nagothane Manufacturing Division PP- Poly propylene LDPE- Linear density polyethylene LLDPE- Linear-low density polyethylene GC- Gas cracker OSBL- Outside battery limit ISBL- Inside battery limit

FIG. 10B Flare stack structure after repair and painting.

Surinder Singh is vice president (mechanical) with Reliance Industries Ltd. at the Nagothane Manufacturing Division in Maharashtra, India. He has over 30 years of petrochemical industry experience. At present, he is assigned as head of plant mechanical maintenance for the entire complex. He has had wide experience in plant downtime reduction and major turnaround planning. He is credited with filling lead roles and involvement in the development of various safety procedures. Mr. Singh graduated with a BSc degree in mechanical engineering from Regional Engineering College, Kurukshetra, India. HYDROCARBON PROCESSING MARCH 2011

I 41

PROCESS INSIGHT Selecting the Best Solvent for Gas Treating Selecting the best amine/solvent for gas treating is not a trivial task. There are a number of amines available to remove contaminants such as CO2, H2S and organic sulfur compounds from sour gas streams. The most commonly used amines are methanolamine (MEA), diethanolamine (DEA), and methyldiethanolamine (MDEA). Other amines include diglycolamine® (DGA), diisopropanolamine (DIPA), and triethanolamine (TEA). Mixtures of amines can also be used to customize or optimize the acid gas recovery. Temperature, pressure, sour gas composition, and purity requirements for the treated gas must all be considered when choosing the most appropriate amine for a given application.

Tertiary Amines A tertiary amine such as MDEA is often used to selectively remove H2S, especially for cases with a high CO2 to H2S ratio in the sour gas. One benefit of selective absorption of H2S is a Claus feed rich in H2S. MDEA can remove H2S to 4 ppm while maintaining 2% or less CO2 in the treated gas using relatively less energy for regeneration than that for DEA. Higher weight percent amine and less CO2 absorbed results in lower circulation rates as well. Typical solution strengths are 40-50 weight % with a maximum rich loading of 0.55 mole/mole. Because MDEA is not prone to degradation, corrosion is low and a reclaimer is unnecessary. Operating pressure can range from atmospheric, typical of tail gas treating units, to over 1,000 psia.

Mixed Solvents In certain situations, the solvent can be “customized” to optimize the sweetening process. For example, adding a primary or secondary amine to MDEA can increase the rate of CO2 absorption without compromising the advantages of MDEA. Another less obvious application is adding MDEA to an existing DEA unit to increase the effective weight % amine to absorb more acid gas without increasing circulation rate or reboiler duty. Many plants utilize a mixture of amine with physical solvents. SULFINOL® is a licensed product from Shell Oil Products that combines an amine with a physical solvent. Advantages of this solvent are increased mercaptan pickup, lower regeneration energy, and selectivity to H2S.

Primary Amines The primary amine MEA removes both CO2 and H2S from sour gas and is effective at low pressure. Depending on the conditions, MEA can remove H2S to less than 4 ppmv while removing CO2 to less than 100 ppmv. MEA systems generally require a reclaimer to remove degraded products from circulation. Typical solution strength ranges from 10 to 20 weight % with a maximum rich loading of 0.35 mole acid gas/mole MEA. DGA® is another primary amine that removes CO2, H2S, COS, and mercaptans. Typical solution strengths are 50-60 weight %, which result in lower circulation rates and less energy required for stripping as compared with MEA. DGA also requires reclaiming to remove the degradation products.

Secondary Amines The secondary amine DEA removes both CO2 and H2S but generally requires higher pressure than MEA to meet overhead specifications. Because DEA is a weaker amine than MEA, it requires less energy for stripping. Typical solution strength ranges from 25 to 35 weight % with a maximum rich loading of 0.35 mole/mole. DIPA is a secondary amine that exhibits some selectivity for H2S although it is not as pronounced as for tertiary amines. DIPA also removes COS. Solutions are low in corrosion and require relatively low energy for regeneration. The most common applications for DIPA are in the ADIP® and SULFINOL® processes.

BR&E

Choosing the Best Alternative Given the wide variety of gas treating options, a process simulator that can accurately predict sweetening results is a necessity when attempting to determine the best option. ProMax® has been proven to accurately predict results for numerous process schemes. Additionally, ProMax can utilize a scenario tool to perform feasibility studies. The scenario tool may be used to systematically vary selected parameters in an effort to determine the optimum operating conditions and the appropriate solvent. These studies can determine rich loading, reboiler duty, acid gas content of the sweet gas, amine losses, required circulation rate, type of amine or physical solvent, weight percent of amine, and other parameters. ProMax can model virtually any flow process or configuration including multiple columns, liquid hydrocarbon treating, and split flow processes. In addition, ProMax can accurately model caustic treating applications as well as physical solvent sweetening with solvents such as Coastal AGR®, methanol, and NMP. For more information about ProMax and its ability to determine the appropriate solvent for a given set of conditions, contact Bryan Research & Engineering.

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

CORROSION CONTROL

SPECIALREPORT

Avoid brittle fracture in pressure vessels Key points identify effects from auto-refrigeration on steel vessels F. KHAZRAI, H. B. HAGHIGHI and H. KORDABADI, Chagalesh Consulting Engineers, Tehran, Iran

D

uring an emergency, equipment failure or a planned maintenance event, hydrocarbon-processing industry (HPI) pressure vessels are normally depressurized. This action may cause auto-refrigeration and low-metal temperature situations in which the likelihood of brittle fracture may occur in steel vessels and reactors. This case history describes the results from a simulation regarding auto-refrigeration effects on HPI reactors. The study also included investigation on brittle-fracture phenomenon and recommendations for a proactive engineering approach to mitigate such failures. Key points highlighted from the study are: • Although the process-fluid temperature from auto-refrigeration drops to –86°C, considering the vessel’s metal-mass heat capacity and ambient temperature, the short-term vessel minimum metal temperature does not become colder than –28°C. Therefore, selecting expensive material of construction can be avoided. • Complying with the ASME rules or other internationally recognized codes for minimum requirements is crucial to the structural integrity of a pressure vessel. However, proactive engineering practices and precautions pertaining to the design, materials, fabrication, nondestructive examinations and operation are also required to ensure that the vessels are resistant to brittle fracture.

PROCESS ENGINEERING

This case study focuses on a gas field production facility, which uses several separation vessels and a stabilization unit to obtain dew-point control for the natural gas products and Rvp-controlled condensate products. The process vessels operate as three-phase separators containing vapor, light-liquid hydrocarbons and heavy-liquid phase. The study focused on the simulation and design of three interconnected separation vessels—V-100, V-101 and V-102 (Fig. 1). Since in accordance with API 521, all process equipment with operating pressure higher than 18 barg must be depressurized in case of an incidence, the fluid pressure should be reduced to 6.9 barg and the blowdown lines including the restricted orifice were designed based on depressurizing to 6.9 barg within 15 minutes.4 In practice during depressurization and blowdown events, the actual vessel-fluid pressure drops from operating pressure (initial pressure) down to almost atmospheric pressure (final pressure). The general assumptions and process design basis parameters used in the simulation include: • Minimum ambient temperature of –13°C is the minimum outer metal-wall temperature of the vessels • “PV work term contribution” is defined as isentropic expansion efficiency and assumed as 100% (a conservative assumption)

• Construction material is carbon steel • Other design basis parameters are listed in Table 1. The first simulation was done without including the vessels’ metal mass. In other words, the control volume of depressurization study was limited to the fluid inside the vessel, and the metalwall temperature was assumed to be the same as the inventory fluid temperature. Also, the temperature difference between vapor and liquid was assumed to be negligible. Table 2 lists the final fluid temperatures obtained in the first simulation. In the second depressurization simulation, the metal mass of each vessel was included in the control volume of the model. Table 3 shows the results of the second simulation based on the metal mass values. As shown in Table 3, the calculated inner-wall temTABLE 1. Design basis parameter for simulation V-100

V-101

18.3

6.2

8.6

Initial liquid volume, m3

1.5

1.0

1.1

Initial mass of vapor, kg

2,115

687.1

620.3

Vessel volume, m3

Initial mass of liquid, kg

V-102

917.0

584.0

656.3

41,700

11,500

9,200

Initial operating pressure, bar-g

120

105

69

Initial operating temperature, ºC

30

4

–10

Vessel metal mass, kg

Produced dry gas Feed gas from manifold production line V-100 V-100 3-phase inlet separator

FIG. 1

Feed heat exchanger V-101 1st stage 3-phase separator

V-102 2nd stage 3-phase separator V-101

V-102

To condensate stabilization unit

Flow diagram of three vessels for the separation process of the gas plant. HYDROCARBON PROCESSING MARCH 2011

I 43

SPECIALREPORT

CORROSION CONTROL

peratures are considerably higher than the calculated fluid final temperatures listed in Table 2 from the first simulation. The simulation work indicates that including the metal-mass heat capacity into evaluation increases the accuracy of estimated minimum metal temperature of the vessels. Consequently, more accurate vessel wall temperatures aid cost-effective selection of construction materials for the separation vessels. MECHANICAL ENGINEERING

All three separation vessels were designed using ASME Code Section VIII , Division 2. Table 4 lists the design data for the separation vessles.5 MDMT of vessels. The minimum design metal temperature

(MDMT) of a vessel is the minimum metal temperature in which the vessel can sustain its full design pressure without having to be impact tested. When the vessel operates at pressures less than its full design pressure, concessions on MDMT are allowed based on ASME Section VIII. Table 5 lists the result 40 30

Temperature, °C

20 10 0 LMT MAT

-10 -20 -30

of MDMT calculations for this study’s vessels based on ASME, Section VIII, Div. 2. Minimum allowable temperature (MAT), as defined in API 579, is “the lowest (coldest) permissible metal temperature for a given material and thickness based on its resistance to brittle fracture. It may be a single temperature or an envelope of allowable operating temperatures as a function of pressure.6 The MAT is derived from mechanical design information and material specification. MAT at design pressure is MDMT. Lowest metal temperature (LMT). LMT as defined and

used in this article is the lowest metal temperature due to the operating condition and minimum ambient temperature. The LMT may be a single temperature at an operating pressure or an envelope of temperatures and coincident pressures. Actually, the LMT, in this case, is derived from the calculated inner wall temperature due to the contained process fluid temperature and also the minimum ambient temperature. The LMTs of the vessels coincident with final pressures (after depressurization and blowdown) are shown in Table 6. As shown in Figs. 2–4 and Table 6, the LMTs for all of the vessels at the final pressure as well as other coincident pressures are on the safe side based on the rules and design philosophy of ASME Section VIII Div. II. Although the code requirements have been satisfied, further considerations and precautions are required to ensure the design and construction of the vessels are resistant against brittle fracture. Several key factors in combination can contribute to brittle fracture of steel vessels; a proactive engineering approach is recommended. TABLE 2. Final fluid temperatures in first-pass simulation

-40 -50 -60

FIG. 2

120

100

80 60 40 Pressure, barg

20

0

LMT curve for vessel, V-100, during depressurization event.

V-100

V-101

V-102

Final pressure (after blowdown), barg-g

0.02

0.02

0.02

Calculated fluid final temperature, ºC

–35

–57

–86

TABLE 3. Simulation results, including metal-mass values V-100

V-101

V-102

10

Final pressure (FP), barg

0.02

0.02

0.02

0

Mass of vapor at FP, kg

24.74

9.686

14.40

-10

Mass of liquid at FP, kg

425.8

291.6

243.2

-20

Inner-wall temperature at FP, ºC

11

–14

–28

Temperature, °C

20

-30 -40

TABLE 4. Design data for separation vessels

-50

Vessels

-60

Design pressure, barg

-70

Design temperature, °C

-80 -100 -110 100 FIG. 3

Material of construction

LMT MAT

-90

80

60 40 Pressure, barg

20

0

LMT curve for vessel, V-101, during depressurization event.

I MARCH 2011 HydrocarbonProcessing.com

V-101

V-102

128

113.4

76.4

80

80

80

Plates: A516 same as Gr. 70 normalized V-100 flanges: A105

same as V-100

TABLE 5. MDMT calculations Vessels MDMT, °C

44

V-100

V-100

V-101

V-102

–20

–22

–22

CORROSION CONTROL The major concern for low-temperature vessels is brittle-fracture phenomenon, which can be a cause for vessel failure. Many metals loose their ductility and toughness; they become susceptible to brittle fracture as the metal temperature decreases. At normal or higher temperatures, a warning is normally given by plastic deformation (bulging, stretching or leaking) as signs of potential vessel failure. However, under low-temperature conditions, no such warnings of plastic deformation are given. Unfortunately, an abrupt fracture can cause a catastrophic event. Only materials that have been impact tested to ensure metal toughness at or above a specified metal temperature should be used. However, certain paragraphs in the ASME Pressure Vessel Code applying to low-temperature vessels indicate when impact testing may not be required for a pressure-vessel component material (impact test exemptions). In general, four main factors, in combination, can cause brittle fracture of steel vessels. These factors are represented in the form of “brittle fracture square” as shown in Fig. 5. The factors that contribute to the brittle fracture of carbon or low-alloy steel pressure vessels are reviewed briefly here: Low temperature. A metal depending on its toughness prop-

erty has a transition temperature range within which it is in a semibrittle condition (ductile to brittle transition). Within this range, a notch or crack may cause brittle fracture (notch brittleness). Above the transition range (warmer), brittle fracture will not happen even if a notch exists. Below the transition range (colder), brittle fracture can happen even though no notches or cracks may exist.3 Although the transition from ductile to brittle fracture actually occurs over a temperature range, a point within this range is selected as the “transition temperature” to delineate the boundaries of ductile and brittle zones. One of the ways to determine this temperature is by performing many impact tests on the construction material.

phosphorous (P) present in steels decreases the transition temperature of steel and improves weldability. In general, steel-transition temperature is a function of carbon content percent plus 20 times the percentage of phosphorous. Furthermore, adding nickel to steel can increase steel toughness and decrease its transition temperature. Stainless steel 304 with 8% nickel can resist impact loads at –320°F. Furthermore, sufficiently low carbon equivalents contribute to the weldability of the material (reducing hardness and cold-cracking susceptibility) and, thus, making metal crack-free girth welds.4 Selecting the appropriate welding material also is a determining factor to ensure a crack-free weld.3 • Steel structure. A correlation was developed between steel structure (microstructure and grain size) and fracture-toughness by numerous fracture toughness tests at different low temperatures. Based on this correlation, steels with coarse-grained microstructures have lower toughness at low temperatures as compared to steels with the fine-grained microstructure. During an 1999 incidence with a high-density polyethylene (HDPE) reactor, a brittle fracture occurred at a temperature of –12°C in a 24-in. flange of ASTM A105 material that had a coarse-grain microstructure (ASTM grain size number 5 to 6 ferrite-pearlite microstructure ).1a 0

LMT MAT

-10 Temperature, °C

BRITTLE FRACTURE PHENOMENA

SPECIALREPORT

-20

-30

Loading. The type and level of mechanical/thermal loading -40

-50

FIG. 4

Inner-wall temperature at FP, °C

V-101

V-100

0.02

0.02

0.02

11

–14

–28

Minimum ambient temperature, °C

–13

–13

–13

LMT at FP, °C

–13

–14

–28

MAT at FP, °C

–48

–104

–46

50

40 30 Pressure, barg

20

10

0

LMT curve for vessel, V-102, during depressurization event.

Loading

TABLE 6. Final vessel conditions after depressurization V-102

60

Susceptible steel

Susceptible steel. Susceptibility of steels depends on several parameters such as poor toughness, material flaws (cracks and notches), corrosion vulnerability, large thickness, etc.: • Steel composition. Steels with lower carbon content (C) are proven to have higher toughness at lower temperatures. Also,

Final pressure (FP), barg

70

Brittle fracture square

Crack/stress risers

will affect the vessel’s susceptibility to brittle fracture. Dynamic loading associated with cyclic mechanical/thermal or impact loading, as opposed to quasi-static loading, is a brittle-fracture contributing factor. Furthermore, shock-chilling effects, defined as rapid decreases in equipment temperatures, can be a cause for brittle fracture.6 Based on the stress levels applied (in a quasi-static loading), component material, effective thickness and minimum metal temperature, ASME Section VIII, Divisions 1 and 2 present criteria for vessel-component material-impact test requirements and/or exemptions.

Low temperature FIG. 5

Brittle fracture square affecting carbon and low-alloy steels at low temperatures. HYDROCARBON PROCESSING MARCH 2011

I 45

SPECIALREPORT

CORROSION CONTROL

• Hydrogen cracks (hydrogen-induced cracks or so-called flakes). When hydrogen atoms diffuse into the metal during material manufacturing operations such as forming, forging and welding or when hydrogen is introduced to the metal through a galvanic or hydrogen sulfide (H2S) corrosion process, the metal is prone to hydrogen cracks. Perform autorefrigeration simulation

Implement “Control of Operation”

Select (or reselect) materials, and design vessel considering “PE”

Fabricate vessel, applying relevant PEs measures

Yes

There are various techniques to prevent hydrogen cracks, including appropriate heat treatments or slow cooling after forging, in which the hydrogen within the metal diffuses out. In the case of welding, usually pre-heating and post-heating are applied to diffuse out the hydrogen and to prevent any cracks and brittleness. • Environmental stress fracture. Steels exposed to corrosive fluids such as wet H2S, moist air or sea water are prone to premature fracture under tensile stresses, considerably below their “fracture toughness” threshold. Suitable steel materials should be used when Are material No exposure to corrosive fluids is possible. requirements satisfied ?

Determine MAT and LMT envelope Examine/inspect materials specification/quality versus required specifications

Compare LMT with MAT

No

FIG. 6

46

Is LMT< MAT ?

Yes Nomenclature LMT Lowest metal temperature MAT Metal allowable temperature PE Proactive engineering

Order materials applying relevant PE's measures

Proactive engineering program in designing and manufacturing vessels to avoid brittle fracture from auto-refrigeration.

I MARCH 2011 HydrocarbonProcessing.com

Select 159 at www.HydrocarbonProcessing.com/RS

Crack/stress risers. Steel vessels with thicker walls have a greater probability potential for brittle fracture due to the larger thermal gradient across the wall thickness. Thicker metal walls can result in differential expansion of material across the wall thickness and could possibly lead to a crack occurrence and eventually brittle fracture. Stress raisers such as sharp or abrupt transitions or changes of sections, corners or notches (as may be found in weld defects) as a result of design or fabrication processes are all stress risers, which can cause stress intensification. The weak points are prone to brittle fracture when other susceptible conditions exist.

CORROSION CONTROL PROACTIVE ENGINEERING

a

b c

d

e

f

NOTES Research was conducted by the Belgian Institute for Welding Techniques on pipe flanges made in forged steel complying with ASTM A105. In June 2002, the study produced a series of recommendations for new flanges as well as flanges already in service.1 The beneficial effect of a hydrostatic test is that crack-like flaws located in the component are blunted resulting in an increase in brittle fracture resistance.6 Requiring full penetration would minimize any highly localized stresses (especially at Category C and D joints) that can have deleterious effect on the vessel’s ability to resist brittle fracture.”2 Carbon equivalent in terms of welding is a rate of weldability related to different alloying elements including carbon, manganese, chromium, molybdenum, vanadium, nickel and carbon content, which affect hardness of the steel being welded. Fracture toughness is an important property of any material for virtually all design applications; it indicates the ability of a material containing a crack to resist fracture. Proper PWHT reduces residual stresses, improves the resistance of the hard heat affected zone to environmental cracking, and improves the toughness.

LITERATURE CITED For complete literature cited, please visit www.HydrocarbonProcessing.com.

Faramarz Khazrai has worked as a mechanical engineer for over 30 years in the areas of piping, static equipment and machinery. In 1986, he joined Chagalesh Consulting Engineers, Tehran, Iran, and supervised mechanical engineering activities of several hydrocarbon processing projects. Currently, he is the machinery department head. He graduated from the Sharif University of Technology with BS degree in mechanical engineering in 1972.

Hamed Basir Haghighi is a mechanical engineer specializing in the area of static equipment engineering. He has participated in various hydrocarbon processing projects at Chagalesh Consulting Engineers since 2001. Currently, he is the static equipment project specialty leader and also project engineering manager. His fields of specialization are detail design of static equipment, composite material selection and finite element method. He graduated from Azad University of Tehran with BS and MS degrees in mechanical engineering.

Hojat Kordabadi, as a process engineer, has participated in the design of various process plants pertaining to the hydrocarbon processing industry. He joined Chagalesh Consulting Engineers in 2007 and has worked in the process engineering department as a project specialty leader. He is the author of three technical paper published in the Chemical Engineering Journal (April 2005, December 2007, September 2008). He holds a BS degree in chemical engineering from Amir Kabir University and a M.S. degree in chemical engineering from Shiraz University, Shiraz, Iran.

CONTROL CORROSION with these products from Gulf Publishing Company

The Fundamentals of Corrosion a and nd Scaling S

Based on the brief technical information given here, several proactive measures can ensure resistance of carbon or low-alloy steel vessels against brittle fracture under quasi-static loading: • Design pressure vessels, if justifiable, by analysis in accordance with the ASME Section VIII, Div 2 part 5, or other internationally recognized codes that result in lower wall thicknesses. • Order vessel materials from reliable and capable manufacturers. Key vessel components still require attention to proper heat treatment, avoiding hydrogen cracks, quality control, etc. • Specify fine-grain steel materials with appropriate specifications and require production tests for plate/piece (from the same heat) if an impact test is not requested. Ensure that the steel with fine-grain microstructure/toughness is supplied; do not rely just on the material certificates. Also, conduct impact tests on test pieces to verify required toughness. • Take benefit of the recommendations contained in the document indicated in reference 1 for ordering pipe flanges made in forged steel complying with ASTM A105. • Ask the material manufacturer for effective construction/ fabrication methods such as vacuum degassing to prevent hydrogen-crack formation in the metal and require stringent nondestructive examinations and quality control. • Do nondestructive testing (NDT) to identify cracks or reject materials with detectable cracks. • Eliminate “stress risers,” at the design and fabrication stages • Verify full-penetration welds with adequate toughness using appropriate welding material/processes and require weldprocedure qualification and production-weld test specimens for both the weld and heat-affected zone for each weld process.c • Conduct proper vessel post-weld heat treatment (PWHT), preferably in a furnace in one piece whenever practical, and examine heat-affected zone hardness to ensure the beneficial effects of the performed PWHT.d • Perform the vessel hydrostatic test in accordance with the rules of the ASME Section VIII Code or other internationally recognized codes.b • Apply “control of operation” proactively, whenever practical, (e.g., after a depressurizing to ensure that the vessel metal temperature is sufficiently warm prior to re-pressurization). A proactive engineering program, as envisioned in Fig. 6, can incorporate the listed measures during vessels design, procurement and construction stages. HP

SPECIALREPORT

The Fundamentals of Corrosion and Scaling for Petroleum and Environmental Engineers Price: $195

Corrosion Awareness Video Price: $995

GULF P U B L I S H I N G C O M PA N Y

+1-713-520-4426 l +1-800-231-6275 Email: [email protected] I www.GulfPub.com Select 160 at www.HydrocarbonProcessing.com/RS 47

refining your profit

UOP helps you exceed your goals with innovative technology, catalysts and optimization solutions specifically designed to meet your needs. UOP hydroprocessing solutions and optimization services are designed to help you maximize your return on investment and grow your business. As regional market demands shift, we provide the process technologies, catalysts and services that will meet your changing business needs. Our experts work closely with you to meet your desired yields and product specifications including ultra-low sulfur diesel standards while improving your operational efficiency. Backed by over 50 years of hydroprocessing innovations, UOP offers the best and most advanced solutions to keep your business one step ahead.

For more information about UOP, visit www.uop.com ©2010 UOP. All Rights Reserved.

CORROSION CONTROL

SPECIALREPORT

Improving pH control mitigates corrosion in crude units Equipment and pipe failures can be avoided through better desalting practices and inhibitor injections D. L. N. CYPRIANO, J. A. C. PONCIANO, A. T. VILAS BOAS, P. D. MURRAY and M. R. NASSER, Petrobras, Duque de Caxias, Brazil

F

or crude-unit overhead systems, pH is the main process parameter that impacts corrosion rates. To control corrosion conditions, many operators use various neutralizers at optimum ranges determined by site-specific conditions. A four-year study (2005–2008) was conducted at a Petrobras refinery using amine-blend solutions to control pH. Over this period, corrosion rates were measured through ultrasonic inspections and weightloss coupons. Important process parameters monitored included: • pH, chloride and iron concentrations at the bottom of the overhead drum • Neutralizer and inhibitor flowrates. A qualitative comparison was done with two refineries, using two other neutralizers: sour water from fluid catalytic cracking (FCC) unit and an ammonium aqueous solution. This investigation proved that maintaining a low chloride level and stable pH levels were the most effective ways to control equipment damage from corrosion. Also, the study found that several inspection techniques were particularly useful in estimating service life for pipes and other crude-unit equipment. Applying better pH control and improved monitoring and inspection programs can reduce equipment damage from corrosion.

Background. Hydrocarbon-processing companies follow dif-

ferent methods in controlling crude distillation unit (CDU) overhead corrosion. Common approaches include inhibitors to neutralize acid solutions. Even with a good control on crude oil in storage tanks and the desalting process, hydrochloric acid (HCl) will still be present at the atmospheric tower overhead and it demands proper chemical treatment. Merrick and Auerbach performed a study on 129 different distillation units. From these studies, it was observed that the average chloride concentration was 10 ppm to 30 ppm in accumulator overhead drums.1 Chlorides are generated from some salts contained in the crude oil that is processed in the CDU; thus HCl is formed. There are three main ways to neutralize acidic aqueous solutions at the CDU overhead; they include injecting: • Gaseous ammonia (NH3) • Ammoniac water (NH4OH solution) • Neutralizing amine solutions. Regardless of the neutralization technique applied, the pH is lower than the dew point of water. This adds more challenges in measuring pH when condensation occurs; this is the preferred

region for the corrosion process to begin. Neutralization equations are: HCl (aq) + NH3 (aq) => NH4Cl (aq) HCl (aq) + RNH2 (aq) => RNH3Cl (aq) One concern for neutralization is the difficulty of controlling the ammonia or amine flowrates, which depend on the varying HCl levels in the CDU. The neutralizer injection levels can be too low and the pH in the overhead can drop. Excess neutralizer levels, especially in the presence of hydrogen sulfide (H2S), contribute to precipitation of salts, such as ammonia or amine disulfides or chlorides. Once formed, these salts (molten or solid) deposit on pipe surfaces, likewise, they can cause localized corrosion with a high rate of thickness loss. If salt formation occurs after condensation, then its dissolution into water represents minimal corrosion risk.2 In this article, some field results are presented, including chemical analysis, pH and corrosion rate for a CDU tower overhead. A qualitative comparison was conducted investigating the different ways to control corrosion, as listed in Table 1. Field data. At Refinery A, the observed corrosion rates in pipes, heat exchangers and accumulator drum, were obtained from thickness measuring via ultrasonic testing. Corrosion rates reached values of 0.15 mm/yr. The heat exchanger tubes presented an average service life of only seven years, and corrosion deposits were found in baffle-plate regions. Some thickness loss and stresscorrosion cracking were also reported on the shells of the equipment, which can be attributed to high H2S levels (2,553 ppm) in the neutralizing solution used. At Refinery B, high chloride levels, caused by inefficiencies in the crude preparation and desalting processes, generated high corrosion rates. The average corrosion rate observed by the coupon weight loss over two years was 0.29 mm/yr. The pipes connecting

TABLE 1. Refineries and neutralizing solutions used for overhead corrosion control Refinery

Neutralizer for overhead control

A

N1—sour water from FCC unit

B

N2—amine blend, based on MEA

C

N3—ammonium aqueous solution HYDROCARBON PROCESSING MARCH 2011

I 49

SPECIALREPORT

CORROSION CONTROL

the top of the atmospheric tower and condensers have flaws from previous campaigns. Localized under-deposit corrosion in the lower blank of the condenser shell was observed. At Refinery C, monitoring results for coupons installed in the overhead condenser (air cooler), had average corrosion losses of 0.16 mm/yr. This reflects a uniform thickness loss expected in equipment and pipes. But there were failures in pipes caused by localized under-deposit corrosion. In the air cooler, the average tube service life was five years, and failures were reported immediately after the flow entrance, where condensation begins. Thickness measuring. For this study, two regions of the overhead pipe were selected at Refinery B to conduct thickness measurement via ultrasonic testing. Initially, the testing was separated into two areas: • Overhead atmospheric tower and condenser • Between the condenser and accumulator drum. Different behaviors are expected from the pipes carrying the fluid before the condenser in the vapor phase (by design), then after, where the water is already in liquid phase. Thus, the observed corrosion rates were different, as shown in Fig. 1. The locations for thickness measurement are always chosen based on the experience of the inspection team supervising the unit and the measurements usually apply these aspects: • In the curves, the corrosion rates may be higher due to an increased propensity for the occurrence of corrosion associated with erosion. • Regions of encounter between two pipes, in the form of “T,” are also preferred regions for erosion. • In the straight sections, fewer points are selected, which are expected to be representative of the system.

TABLE 2. Relationship between problems in desalination and corrosion rates in the overhead atmospheric tower system Desalting stopped, Time–hours

Corrosion rate, mm/yr

1

2/13–4/20

24

0.359

2

4/30–5/29

0

0.073

3

5/29–6/28

0

0.086

4

8/1–9/3

0

0.014

5

9/3–11/13

4

0.259

6

11/13–12/21

5

0.220

After condenser

Before condenser

9 Overhead condenser

6

Dec/08

Nov/08

Oct/08

Aug/08

Jul/08

Jun/08

0

Apr/08

Sour water

Mar/08

Naphtha

3

Feb/08

Accumulator drum Atmospheric tower

include how operating conditions had contributed to equipment deterioration. For example, in 2007, some studies researched the impact from the chloride content variations in the feed at the preflash tower overhead, while the corrosion rates were measured by coupons. Due to the ineffectiveness of desalting, there was a direct influence on the corrosive process in the overhead system, as is illustrated in Table 2. During these periods, electrical problems caused transformer problems that affected the inner electrodes to the desalting drums. Poor desalting of the crude led to chloride levels above 1,000 ppm in the overhead accumulator drum. Also, pH was affected, reaching values approximately 4. Weight-loss coupons were installed in the inlet connections of the atmospheric overhead condensers. To improve desalter efficiency at full operating conditions, more tests were made by adjusting the differential pressure of the mixer valve. Usually covered with ΔP = 1 kgf/cm², this value was increased by 0.2 kg/cm². Result: Without any other changes in operating parameters, a reduction of 44% in the chloride content in the accumulator drum was obtained. In the overhead atmospheric system, pH, chloride, iron and corrosion rates were monitored by weight-loss coupons. Fig. 2 shows the historic data of pH values measured in the accumulator drum since 2008. The figure shows the mean values and standard

Jan/08

Corrosion inhibitor Neutralizer

Process data. For Refinery B, the study was expanded to

pH of atmospheric system-Refinery B

Period analysis, (Year–2007)

In 2004, measurements were made on about 70 points before the condensers. Another 70 points were inspected with the same technique in pipes after the condensers. The same 140 points were inspected again in 2005. The results allowed defining several average corrosion rates: • Before the condensers: 0.14 mm/yr • After the condensers: 0.16 mm/yr. Also, there were high standard deviations in both cases, 0.16 mm/yr before and 0.15 mm/yr after the condensers. The highest rate observed in the first case was 0.63 mm/yr, and the lowest 0.02 mm/yr. After the condensers, the highest rate was equal to 0.61 mm/yr and the lowest 0.02 mm/yr. Before the condenser, 25 points were measured again in 2008; the average corrosion rate (2005–2008) was equal to 0.17 mm/ yr. The data from the corrosion coupons indicated an average rate of 0.19 mm/yr in the same period. In December 2008 and June 2009, five points were measured in random areas of the pipes before the condensers, resulting in an average corrosion rate equal to 0.21 mm/yr. In the same period, some corrosion coupons were analyzed monthly, positioned on the inlet connections of overhead condensers; these coupons had an average corrosion rate equal to 0.28 mm/yr.

Time FIG. 1

50

CDU showing locations identified for thickness monitoring by ultrasonic testing.

I MARCH 2011 HydrocarbonProcessing.com

FIG. 2

Historic data of pH values in the overhead accumulator drum of the atmospheric tower for refinery B.

CORROSION CONTROL

The mass balance at the tower overhead is shown in Fig. 7. It is known that the chloride content measured in the top accumulator is directly linked to the presence of HC1 formed from the hydrolysis of salts present in the feed. Thus, it is possible to set base values for neutralizing agent flowrates. From the condensate analysis in the overhead drum, several periods were selected in which the chloride content was close to 100 ppm, or 50% of this, 50 ppm. On the same dates, the average flowrates of the neutralizing solution and pH were recorded, as listed in Table 3. With the pH near the equivalence point, if we consider only the presence of HCl, neutralizer and water, the result is salt formation, N2Cl, which dissociates. We can determine the resulting pH; the reactions are:3 N2Cl j N2+ + Cl(1) N2+ + H2O = N2OH + H+ (2) From the salt concentration, it is possible to determine the expected pH: K [N 2OH ]×[H + ] [H + ]2 Ka = w = = = 5.6×10−5 Kb [N 2+ ] [N 2+ ] As Ka is very low, the salt concentration Cs = [N2+]: 4 3 2

FIG. 4

7.6

D4

49

115.2

7.1

D5

97

115.2

7.1

D6

100

43.2

5.1

D7

100

115.2

6.8

D8

103

80.6

5.3

0

Dec/08

Nov/08

Oct/08

Aug/08

Jul/08

Jun/08

Apr/08

Historic data of neutralizer amine flowrates at overhead pipe in the atmospheric tower for Refinery B.

50

Historic data of chloride values in the overhead accumulator drum of the atmospheric tower for Refinery B.

10

FIG. 6

Dec/08

Nov/08

Oct/08

Sept/08

Aug/08

Jul/08

Jun/08

0 May/08

Dec/08

Nov/08

Oct/08

Aug/08

Jul/08

Jun/08

Apr/08

Mar/08

Feb/08

Jan/08

0

20

Apr/08

50

30

Mar/08

100

40

Feb/08

150

Jan/08

Inhibitor injection, l/d

Chloride concentration of atmospheric system Refinery B, ppm

30

FIG. 5

200

FIG. 3

60

Dec/08

6

11.5

Nov/08

43.2

49

Oct/08

48

D3

90

Sept/08

D2

120

Aug/08

7.10

Jul/08

115.2

Jun/08

46

May/08

D1

150

Apr/08

pH, mean

Mar/08

Flowrate N2, l/d

Historic data of iron values in the overhead accumulator drum of the atmospheric tower for Refinery B.

Feb/08

Cl–, mean

Jan/08

Day

Neutralizer injection, l/d

TABLE 3. Relationship between levels of chloride neutralizer flow (N2) and pH analyzed in the condensate from the overhead drum—Refinery B

Mar/08

0

Feb/08

1 Jan/08

Iron concentration atmospheric system Refinery B, ppm

deviations for measurements over each month, except May and September, when there were no analysis reports. It is observed that the average pH over the years has always been very close to or within the recommended range. But the high standard deviations showed a lack of control during some periods. There were some incidents in January in which a pH reaching 1.5 was observed and adjusted to 3 on the same day and recovered to a pH = 6 on the next day. On two days, the pH reached 4. The higher standard deviation observed in this month contributed significantly to increased corrosion rates. Fig. 3 shows the measured chlorine values in the same drum. The target is 40 ppm as the maximum, which can only be guaranteed with efficient control in crude preparation at the storage tanks and desalter. It is observed that the values remained above the recommended targets throughout the year, showing deficiency in the early stages of crude processing. As an immediate consequence, we can expect greater usage of neutralizers and corrosion inhibitors. What is not always sufficient to maintain is the appropriate pH and low corrosion rates over slack periods, as observed in January (average of 108.96 ppm chloride). The iron level in the water was also monitored. Iron can be another indicator of corrosion in the overhead system. In Fig. 4, the measurements from 2008 are shown; conditions exceeded the maximum value of 1 ppm over the year. Also, we can observe that the iron content was below the recommended limit 4 of the 10 months evaluated. These results vary greatly over the month, with standard deviations above the mean values; the data is not included in Fig. 4. Intakes of neutralizing solutions and corrosion inhibitors also represent relevant data on analyzing control parameters in the overhead system. Figs. 5 and 6 show the injection rates for neutralizers and inhibitors for Refinery B in 2008.

SPECIALREPORT

Historic data of inhibitor flowrates at overhead pipe in the atmospheric tower for Refinery B. HYDROCARBON PROCESSING MARCH 2011

I 51

SPECIALREPORT

CORROSION CONTROL on the inlet connection of the overhead condenser. There were many lack periods, in which the corrosion rate is at greater than the established limit (0.125 mm), such as in November 2004 (0.60 mm/yr), January 2008 (0.53 mm/yr) and November 2008 (0.55 mm/yr).

Kw ⇔ 2 log[H + ] = Kb 1 1 1 ×log K w − ×log K b + ×logC S ⇔ 2 2 2 1 1 ⇔ pH = 7 − × pK b − logC S 2 2

[H + ]2 = C S ×

There are many other contaminants in the overhead system, such as H2S, ammonia (NH4), sulfur oxides (SOx) and others that can alter conditions and force changes on the predicted pH values. We cannot establish a direct relationship between the chloride (Cl-), flowrate and pH neutralizer from field results. However, we can determine the salt concentration (N2Cl) from the N2 solutions, as described in Table 4, and compare it with the expected resulting pH. Table 4 lists the results; observing that, in a few cases the values coincide, as in D1, D3, D4 and D5, and the neutralizing added on top is extremely diluted into the total water solution (264,000 l). Corrosion monitoring—weight-loss coupon. Fig. 8 shows the historic data of the weight-loss coupons, installed Hydrocarbon FG+LPG+Naphtha 86.66% Aqueous solution H2O+HCl+H2S (pH = 2.5) 13.43%

Overhead condenser

Hydrocarbon FG+LPG+Naphtha 86.66% Aqueous solution pH = 6.0 13.43%

Neutralizer, N2 Solution pH = 11 0.01% Inhibitor Water soluble 0.002%

Atmospheric tower

Nov-04 Dec-04 Jan-05 Feb-05 Mar-05 Apr-05 May-05 Jun-05 Jul-05 Aug-05 Sept-05 Oct-05 Nov-05 Dec-05 Jan-06 Feb-06 Mar-06 Apr-06 May-06 Jun-06 Jul-06 Aug-06 Sept-06 Oct-06 Nov-06

0.70 0.60 0.50 0.40 0.30 0.20 0.10 0.00

Atmospheric tower

0.70 0.60 0.50 0.40 0.30 0.20 0.10 0.00

FIG. 8

52

Mass balance of the atmospheric tower overhead system—Refinery B.

Apr/07 May/07 Jun/07 Jul/07 Aug/07 Sept/07 Oct/07 Nov/07 Dec/07 Jan/08 Feb/08 Mar/08 Apr/08 May/08 Jun/08 Jul/08 Aug/08 Sept/08 Oct/08 Nov/08 Dec/08 Jan/09 Feb/09 Mar/09 Apr/09 May/09

Corrosion rate, mm/yr

Corrosion rate, mm/yr

FIG. 7

Weight loss monitored by corrosion coupons, installed at the inlet connection of the overhead condenser—Refinery B from November 2004 to May 2009.

I MARCH 2011 HydrocarbonProcessing.com

Discussion. At the three refineries presented in this study, various problems caused by corrosion are sourced to low operating efficiencies in the crude desalting unit, which is initiated at the storage tanks. Checking field data and literature to find benchmark values for evaluating the effectiveness of existing desalters can help maximize salt-removal efforts.4 Also, leakages observed in pipelines in Refineries B and C were mainly caused by deficiencies in pH control. This is the main control parameter in the tower overhead, and it must be kept within the range with the minimum possible deviation. We could not associate a neutralizer type to observed failures. The results of Refinery B showed that even with at stable pH behavior over the study period, corrosion increased. The standard deviation observed during 2008 was 0.54, with daily routine measurements. This value is consistent with observed deviation cited in the literature, equal to 0.78, when gaseous ammonia was used as a neutralizer in the same unit.5 The literature shows that low pH values lead to high corrosion rates on mild steel, even though the presence of inhibitors may be insufficient to alleviate this problem.6 Conversely, a pH too high can also bring negative consequences: • Using excess neutralizing solutions, based on amine or ammonia, favors the occurrence of deposits, leading to localized corrosion with extremely fast kinetics. • In stream containing H2S, such as the CDU, stability of the protective iron-sulfide film is compromised while increasing its solubility, thus accelerating corrosion.7 We can analyze a phase diagram for H2O-HCl and correlate it to the overhead corrosion process.8 It is possible to observe a temperature range of approximately 100°C to 102°C, in which an average concentration observed in the field (0.7% HCl), and in which two phases are present in equilibrium conditions: vapor (rich in water) and liquid (rich in HC1). At the temperature where condensation begins, the HCl concentration in the liquid is 10 times higher than vapor phase. Only below 100°C, in equilibrium condition, the steam is fully condensed, and the final concentration of the liquid is reached. In Refinery C, this

TABLE 4. Relationship between levels of chloride neutralizer flow (N2) and pH analyzed in the condensate from the overhead drum—Refinery B Concentration, Concentration, CS (molar) pH, mean CS (molar)

Day

Flowrate, l/d

D1

115.2

0.000017

7.1

0.000016

D2

43.2

0.002754

6.

0.000006

D3

11.5

0.000002

7.6

0.000002

D4

115.2

0.000017

7.1

0.000016

D5

115.2

0.000017

7.1

0.000016

D6

43.2

0.173780

5.1

0.000006

D7

115.2

0.000069

6.8

0.000016

D8

80.6

0.069183

5.3

0.000011

CORROSION CONTROL

Not Mozart, Yet a Classical Genius

behavior was well marked, as leakages occurred in the starting point of condensation on the overhead air cooler, while the rest of the pipes were found in good conditions. To increase the process data analysis, the measured consumption of neutralizing amine in the overhead during 2008 were compared with values originally estimated by the supplier—data presented in Table 5. The comparison was done in a period in which the main process variables, such as pH and chloride content in the overhead drum, did not suffer interference from typical discontinuities, such as high levels of base sediment and water in oil. The selected period was the months of June 2008 to August 2008, in which the corrosion rate was below the recommended target of 0.125 mm/yr, as shown in Table 6. Application of neutralizing amine can be varied for many reasons, such as incorrect pH measurement, which interferes directly in injection flowrate. If the quality of the crude is kept almost constant, the product amount injected into the overhead stabilizes. This is the condition studied in the chosen period—optimum injection to compare the predicted with the far field. From Table 5, the relationship between the measured and predicted consumption of neutralizer is doable. For a maximum chloride content of 50 ppm at the overhead using data of steam injection background and specific consumption provided by the manufacturer, the amount of amine provided at the top would be 60 l/d, while in practice, keeping variables under TABLE 5. Relationship between predicted consumption and the measured one Date, 2008

Chloride content, Predicted Measured kg MCl/kg consumption, consumption, solution l/d l/d

Measured/ Predicted

7/30

87

46

95

2

7/24

90

62

86

1

7/23

86

62

89

1

7/21

86

65

69

1

7/11

80

70

66

1

7/4

39

38

69

2

7/3

64

66

101

2

7/1

121

129

101

1

7/1

109

120

101

1

6/20

50

57

124

2

6/16

49

60

115

2

Just like Mozart‘s compositions SAMSON‘s Series 240 Valves are world renowned and appreciated. Tuned like organ pipes, the Series 240 suits all pressures and flows, from adagio to allegro. Yet, the valves definitely work piano so nobody will be roused by a sudden beat of the drum. And, just like in an orchestra, the number of instruments is your choice. With positioners, solenoid valves and limit switches, further virtuoso performers are waiting to come in.

TABLE 6. Corrosion rate in June and July 2008 (overhead atmospheric system—Refinery B) Initial date, coupon installation

Final date, coupon removal

Corrosion rate, mm/yr

06/16/2008

07/23/2008

0.049

07/23/2008

08/26/2008

0.071

We supply the instruments, you be the conductor.

TABLE 7. Comparison of corrosion rate obtained by weight loss coupons and ultrasonic thickness (UT) measurement—Refinery B Period

Coupon rate, mm/yr

UT rate, mm/yr

March 2005–Dec. 2008

0.19

0.17

Weismüllerstraße 3

Dec. 2008–June 2009

0.28

0.21

60314 Frankfurt am Main x Germany A01007EN

Select 161 at www.HydrocarbonProcessing.com/RS 䉴

SAMSON AG x MESS- UND REGELTECHNIK

Phone: +49 69 4009-0 x Fax: +49 69 4009-1507 E-mail: [email protected] x www.samson.de

SPECIALREPORT

CORROSION CONTROL

control, the measured consumption was 120 l/d. We can conclude that the predicted flowrate for the neutralizing solution can be a guide for the process, but only constant pH monitoring (preferably online) can promote adequate control for amine injection. Corrosion rates are directly proportional to pH. Accordingly, field monitoring uses weight-loss coupons to validate the quality of process parameters control. At Refinery B, measurements were made from 2004 until early 2009, when only 45% of cases were below the limit—0.125 mm/yr. Throughout 2008, the weight loss was framed in only 30% of the months monitored. Comparing these results with inspections by thickness measurement, we realized that the difference between the rates obtained with both techniques was short only at the second decimal number, as shown in Table 7. This study listed a number of results available in many CDUs. But the relationship between them can generate even more support for inspection teams that manage equipment integrity. From the temperature (T) and pressure (P) in the overhead pipe, it is possible to estimate if water vapor and its components reach the dew point before the condenser. The pH measured in the accumulator drum indicates how the developed corrosive process will progress throughout the system. The chloride content, which is directly related to the flowrate of the neutralizer, also increases corrosion at high values, even if the pH is controlled. Injecting inhibitors can reduce corrosion rates but not with the same intensity as pH adjustments. Thus, we must work to meet the primary objective of the refinery integrity program: to reduce unplanned shutdowns, identify root causes for corrosion degradation of equipment and ultimately develop a good corrosion monitoring program.9

Conclusions. Among the available neutralizing solutions,

refiners should use the one that provides the best efficiency, coupled with the cost benefit for each unit, while considering environmental aspects from waste generation and final treatment. There are pros and cons associated with each neutralizer.10 The results showed that the type of neutralizer used on the CDU atmospheric tower overhead was not the determining factor in minimizing corrosion. Only a good control of process parameters, especially the desalting efficiency (low chloride level at the overhead accumulator drum), can increase equipment service life. We can also establish a direct relationship between the historic data of the process parameters (chloride level, pH, temperature and pressure) and the expected thickness loss of the equipment and pipes. Monitoring weight-loss coupons is essential to validate the quality of the process parameters’ control. At Refinery B, the rates obtained with the coupons were compared to results from inspections by ultrasonic thickness measurement, where only a small difference in the second decimal number (0.02 mm to 0.07 mm) was observed. With these low rates and constant monitoring, the likelihood of failure is minimized, and it becomes possible to predict damage to equipment and avoid unplanned shutdowns due to equipment failures by corrosion. Plant results and literature data indicate that there is an optimal pH control range for the CDU overhead system. The main process parameter, defined in terms of two main corrosion mechanisms are: • At low pH (pH below 5.5) the HCl causes severe corrosion in the mild steel • At high pH (pH above 6.5), due to the presence of H2S, there is an increase in the uniform corrosion rate due to the breakdown of the iron sulfide layer, and localized corrosion under deposit is also more likely to occur because of the salts formed. For each system, an optimal range should be specified. It will depend on the chemical composition of the final solution obtained in the accumulator drum. It is important to note that pH stability is dependent on system automation. More reliable online information enables low deviations if there is an instrumented injection control fed by online pH measurement. HP LITERATURE CITED Merrick, R. D. and T. Auerbach, “Crude unit overhead corrosion control,” Materials Performance, September 1983, p. 15. 2 Couper, A. S. “Bothered by corrosion of your crude-unit condensers?,” Oil & Gas Journal, July 1964, p. 79. 3 Harris, D. C., Quantitative Chemical Analysis, 7th ed., California, 2006. 4 Gutzeit, J. “Controlling crude unit overhead corrosion by improved desalting,” Hydrocarbon Processing, February 2008, p. 119. 5 Jambo, H. C. M., D. S. Freitas and J. A. C. Ponciano, “Ammonium hydroxide injection for overhead corrosion control in a crude distillation unit,” International Corrosion Congress, Granada, Spain, September 2002. 6 Gutzeit, J. “Effect of organic chloride contamination of crude oil on refinery corrosion,” Nace, Orlando, Florida, March 2000. 7 Sardisco, J. B. and R. E. Pitts, “Corrosion of Iron in an H S-CO -H O 2 2 2 System: Composition and Protectiveness of the Sulfide Film as a Function of pH,” Corrosion, November 1965. 8 Potolokov, V. N., V. A. Efremosv, S. V. Nikolashin, T. K. Menshchikova, E. G. Zhukov and V. A. Fedorov, “Liquid-Vapor Equilibrium in the AsCl3HCl-H2O System,” Inorganic Materials, September 2006, p. 1027. 9 Ropital, F. “Current and future corrosion challenges for a reliable and sustainable development of the chemical, refinery, and petrochemical industries,” Materials and Corrosion, July 2009, p. 495. 10 Jahromi, S. A. J. and A. Janghorban, “Assessment of corrosion in low carbon steel tubes of Shiraz refinery air coolers,” Engineering Failure Analysis, November 2004, p. 569. 1

Select 162 at www.HydrocarbonProcessing.com/RS 54

TURNAROUND AND MAINTENANCE 2011 Special Supplement to

CONTENTS How would you rate leadership of your capital projects? T–57 What are the “magnificent seven” elements to successfully pick a contractor? T–60

Corporate Profiles Cooper Crouse-Hinds T–56 AltairStrickland T–63 Curtiss Wright Flow Control T–65 Dunn Heat Exchangers T–67 Microtherm T–69 Rentech Boiler Services T–71 Dollinger Filtration T–73 Voith T–74 Cover Photo: Suncor Plant in Edmonton, Alberta. The curtain material were utilized to shield workers from the environment and enclose maintenance activities. Photo courtesy of HiTemp Products. www.hitemp.ca

CORPORATE PROFILE: COOPER CROUSE-HINDS GMBH TURNAROUND AND MAINTENANCE 2011

Maintenance Headline equipment for hazardous areas (2 lines) improves efficiency and safety Servicing and maintenance in hazardous areas can be time-consuming and costly, particularly if engineers are not provided with the right tools to carry out the job quickly and safely As industrial processing plants become more complex and safety requirements more stringent, these plants have to become more efficient in terms of their maintenance and servicing activities. The objective is to minimize costly production downtime and to guarantee the safe operation of the plant. However, the challenges facing servicing and maintenance personnel can be daunting, time-consuming and costly, particularly if the engineer is not provided with the appropriate tools. A wide range of explosion-protected electrical equipment for plants or offshore oil platforms is now available to help engineers minimize service and maintenance costs. Explosion protected portable torches, search lights and hand lamps, including LED versions, will illuminate the working area quick and safe. Mains connected fluorescent light fittings, floodlights and pendant light fittings complete with flexible power supply cable will brightly light up wide areas. These fittings can be connected to the mains by cable reels and socket distribution units. The objective is to minimize the time and effort required by the engineer, whilst guaranteeing the safety of personnel at all times.

Two line caption

Contact information Neuer Weg-Nord 49 D-69412 Eberbach Phone: +49(0)6271 806 500 Fax: +49(0)6271 806 476 Email: [email protected] Website: www.coopercrouse-hinds.eu

Enhancing Safety & Productivity

Servicing & Maintenance in Hazardous Areas Safe and efficient! CEAG portable lighting, cord reels and power distribution units will reliably support your maintenance activities. E-mail: [email protected]

www.coopercrouse-hinds.eu T-56

I TURNAROUND AND MAINTENANCE 2011

Select 165 at www.HydrocarbonProcessing.com/RS

SPONSORED CONTENT

TURNAROUND AND MAINTENANCE 2011

How would you rate leadership of your capital projects? R. M. PATTY and M. A. DENTON, Consultants To achieve substantially improved benchmarks in project performance, profound change is needed

lence. World-class clients and industry-leading senior managers of FEL and EPC projects periodically assess remaining project vulnerability (to cost, schedules and productivity over-runs). These assessments identify the value gained by improving current work processes and procedures through management by lean work process standards. Sometimes called norms, their development and use provide a promising opportunity to take FEL and EPC project performance and reliability to the next level.

WRLP

Bid

Recently, in a major oil company, a team of senior project managers and value improving practices experts assessed the impact of implementing lean methods during front-end-loading (FEL) and concluded that both total-in-place cost (TIC) and schedule would improve by at least 10% (see Fig. 1). The company’s vice president (VP) approved two pilot projects, with high priority; however, they failed to overcome middle management resistance to change, stalling their recommendations Creating a foundation of sustained excellence. What and approvals before actual piloting. separates a good project from a poorly executed one? Some factors include: Under director level leadership, a major engineering department (approximately • Sub-task level work process standards depict engineering and management 1,500 engineers) evaluated the engineering-lean potential to increase throughput expectations regarding the specifics of what will be done, how, by whom and in Two line caption at about 25% with corresponding project cost reduction. Under pressure from the what sequence to achieve desired measurable results during actual circumstances team’s lean recommendation and client dissatisfaction, the VP of engineering said, faced by employees. “We recognize the value, but we have a lot of things on our plate right now. We • Lean work process standards are derived with performance measures estabthink you are about a year ahead of when we can do this.”The VP of engineering lished to provide just what is needed for those doing the job to consistently enable had been personally responsible for most of the systems currently in use. In the face best practice. Subdividing tasks (e.g., sub-task size to a single deliverable) must be of overwhelming evidence presented by his team investigating lean, he could not sufficient to assure each sub-task-lead has everything they need to start, execute deny the benefits, so, he did the next worst thing: admitted the need, but delayed and deliver what is needed without ever stopping. Sub-task sequencing extends implementation, after all, the clients keep paying the bills. Although resistance was the planning to include all active sub-tasks in the current week to four-week natural, the lack of executive leadership was also evident and a profound disapexecution window. pointment to the team. • Lean management by standards requires both policy deployment (calling Under the author’s guidance, foremen and construction managers at a major for commitment to the standards by the leadership responsible to execute them) engineering, procurement and construction (EPC) contractor site, quantified the and actual progress of each active task at the workface to be visible to manageimpact of and opportunity for construction-lean (see partial results in Fig. 2). The ment. If any standard does not cause the right things to happen, consistently and EPC team proceeded to improve many things within their control; then, they solicreliably, then it is not considered lean. The team must improve: the standard, and/ ited the client to achieve the really profound savings through improved planning or the standard’s deployment policy, and/or workface progress visibility, until the during design. The issue involved the EPC aligning seven chemical plant operating right things happen. divisions during FEL to improve reliability. It is now evident that the team should perform nearly everything in engineering, The Client declined involvement in the face of profound opportunity to improve construction and business according to the best work process standards or their the root cause of poor planning—i.e., late client information and changes. Client equivalent by some other name (e.g., norms). Teams should define standards jointly, leadership-of-change among the seven divisions was lacking. Client middle manled by those who are responsible to manage and must include those who perform agers resisted the necessary alignment—although senior management was crying inside the company or within their supply and subcontracting chain. from the profound losses. Short of doing all the work themselves, standards are, in fact, the best way that Our recently published handbook1 presents many examples of substantial engineering discipline leads or management at each level can effectively assure improvements and serious root causes in recent multi-billion dollar losses and explains the processes that created ERA the improvements and could have prevented the losses. Traditional project The authors’ bring the reader a rapid improvement Design Project proposal Detailed design basis discipline with the means for operational trust and methMC OS Procurement fabrication and delivery ods of profound leadership. To do so, we have integrated Construction Startup experience implementing lean, six sigma, theory-of-conERA Lean project delivery straint and quality-function-deployment, etc., to enhance value-improving practice and constructability principles Design System Component Detailed design basis criteria criteria and methods. The former are not yet formally deployed MC OS Construction Procurement fabrication and delivery on most large facility delivery projects and programs. Planning Construction Startup Sustained, market excellence. TypiFIG. 1. Major oil company assessment of lean impact on traditional project delivery engineering release cally, we have found improved standards are a good approval (ERA), mechanical completion (MC), onstream (OS), waste reduced lean procurement (WRLP). starting point and the foundation enabler of excelHYDROCARBON PROCESSING TURNAROUND AND MAINTENANCE 2011

I T-57

TURNAROUND AND MAINTENANCE 2011

their team understands and implements their ideals, principles and expectations. Lean standards at the work process (e.g., sub-task) level constitute the foundation level extension of corporate governance into the workface. The workface is where the team can add or manipulate information or material to add value. During project design, it is where the team assimilates information, makes calculations or decisions, renders drawings and writes program code or specifications. During manufacturing or construction, it is where the team adds, cuts away, alters or assembles material to add value. The team should consider the following as wasting resources: most contributory work (see examples in Fig. 2), idleness or rework (in engineering, fabrication or construction), and any available workface that is not fully utilized. Teams can reduce or eliminate these sources of waste by further application of lean principles2 and tools.3 An available workface is where the team can productively perform design, manufacturing or construction without such work rendering any other work less than fully productive. The establishment of lean work process standards, policy of use and systems that provide transparency to achieve aligned progress of value added work at every available workface, profoundly benefits cost and performance reliability.

Benefits—reliable best practice performance. Traditional project planning and management systems harness considerable control of risks and associated chaos that would otherwise exist. By establishing management by lean work process standards, aligned with a sequence and system, transparent4

Non-contributory, waiting and non-value added work 25.2% Direct value added work 35.8%

Contributory work 39%

Safety work, 3.8% Rigging and flagging, 1.3% Inspection and testing, 0.5% Material and equipment loading, unloading and storage, 1.6% Clean up, 3.2% Maintenance and repair, 1.0% Personal time, 1.3% Move self, 8.9% Move tools and materials, 14.8% Locating and positioning, 2.2% Holding materials or equipment, 0.4%

Non-contributory,waiting and non-value added work 25.2%

Contributory work 39%

Idle – crew balance, 6.2% Idle – interference, 2.6% Idle – talk, 0.4% Idle – over manning, 2.5% Idle – late start or early quit, 3.2% Idle – discretionary, 3.2% Idle – institutionalized standby, 4.2% Ineffective work, 1.5% Rework, 1.5%

Non-contributory, waiting and non-value added work 25.2%

Direct value added work 35.8% Contributory work 39%

Direct value added work 35.8%

Effective setup 13.5% Dismantle, 1.9% Fabrication and pre-assembly, 5.8% Excavating and backfilling, 2.8% Final assembly, 11.4% Placing, 0.4%

FIG. 2. Partial results of workface sampling during chemical plant construction, Jan. 14–24, 2008. T-58

I TURNAROUND AND MAINTENANCE 2011

HydrocarbonProcessing.com

for balanced progress of every available workface, management eliminates substantial remaining risk and chaos within able and diligent teams that are trying to figure out how to most effectively perform. The content of standards, their sequence and transparency become the basis upon which teams evaluate performance and derive further improvements. Lessons learned for safety, quality, productivity, constructability, maintainability, environmental improvements, etc., are institutionalized quickly by building them into sub-task level standards. Management and engineering skill and stakeholders build their experience, e.g., what they know about how to avoid problems, into the standards and expect them to be executed and improved. Teams are more effective and confident when operating within established standards and being evaluated accordingly. Team trust and morale improves when these systems are in place. Management’s expectation that teams will anticipate problems before they happen and improve the standards they use while executing them enables continuous improvement. If, notwithstanding the team’s best efforts, circumstances prevent performance at the standards, then employees are generally expected to halt execution and seek immediate reevaluation of the standard and its content, sequence or transparency improvement by applicable skill and stakeholders. The benefits of employee empowerment to do so are similar to those experienced by authorization to halt work that an employee considers unsafe. Employees know halting the workflow is extremely expensive, and ownership of standards they use coupled with management trust and dependent peers’ visible expectations, will motivate them to anticipate problems and eliminate them before they happen. All the universal performance measures and their reliability are profoundly improved: 1) safety, 2) quality, 3) productivity, 4) cost, 5) schedule, 6) environmental protection, and 7) employee morale.

Current opportunity, senior resource leveraging. In an industry strained for expertise and experience, standards can close the performance gap quickly between ambitious young engineers or managers and their highly experienced senior peers. The sub-task level standards enable reasonably trained and experienced employees to quickly come up to performance at best practice. Managers who have built what they know and expect into standards for about 90% of what their subordinates do, can use transparent systems to more effectively manage many more people than they can with conventional oversight. A broad, flat and highly effective management structure emerges for reliably achieving best practice. Corporate knowledge and experience are captured in the standards and made available when and where they are needed—not lost by transfers, attrition or loss of people to a competitor. It is senior management’s fiduciary responsibility to their clients, shareholders and employees to recognize any project vulnerability resulting from current policies and procedures. They must become experts themselves or engage a lean subject matter expert to quantify the benefits of establishing lean standards at the work-process level, together with visible workface optimization planning. With this evidence, senior managers resource the work process standard development function at the workface then set the example by deriving lean work process standards in support of the workface, with their middle managers at every level. Each must assure agendas include time (about 5%) for reflection on how to eliminate the source of problems, and build what it will take to prevent problems into the standards. Consider what is wrong with the recent response of a well-compensated oil and gas company executive to a well-evidenced lean introduction. “If we hire a lean consultant, he is going to expect us to do the right things, not just look good, and that is going to be a whole lot of work. As long as projects continue to go more or less as they have before, we’re just fine. If not, we are victims of circumstance and not responsible.” While few will argue against experience being the best teacher, it is usually the most expensive. Knowledgeable stockholders cringe and clients’ satisfaction

TURNAROUND AND MAINTENANCE 2011

wanes when employees learn by experiencing critical (and avoidable) incidents at client or stockholder expense. Managers can and should reliably know before it is too late. Cultures can and should support employee use of fully aligned skill and stakeholder expertise. Lean methods, such as management by lean work process standards, are operational on FEL (design basis, preFEED, FEED) and EPC (detailed engineering, contracting, procurement, construction, commissioning and startup) projects and in their supporting organizations. Both motivation and increased team enthusiasm for differentiating performance are created by managers with a healthy recognition of current project vulnerability who choose to benchmark current status and measure the opportunity specific to lean tools. To do so now, racing the industry to generally adopt the tools and establish the supporting culture, is a promising current FEL and EPC opportunity to leverage senior resources for sustainable performance excellence. Consider what is wrong with the recent response of well-paid executives of a major oil and gas EPC service provider to a well-evidenced lean introduction. “If lean is so important, clients would be willing to pay for it. If we begin to experience loss of work that a client acknowledges is a result of our not using lean, then we will just do it.” With the advantage of the primary author’s training from Boeing and Shingijutsu and an extensive technical review team,6 we have deftly described the transformation to lean, not just at the introductory levels but transformation of the entire business model and all the supporting processes to solidify, sustain and perpetuate: • More effective metrics and timely tools for measuring performance and long-term impacts of using lean production techniques are presented. The metrics provide universally needed management information for transparent control of project performance, safety, quality, productivity, cost, delivery-schedule, environmental responsibility and employee morale. • The tricky part is to change the mindset of just accepting tradeoffs, e.g., improving schedule at the expense of cost or vice versa. Experienced and successful managers must gain the trust that it will be of mutual benefit to implement lean principles because, so far, their companies have rewarded them for their past successes without using lean principles. Successful project, construction and other discipline managers excel in making decisions in the face of uncertainty to a fault. They fast track their schedule by expediting front end loading and planning and rely on their intuition and experience to address unexpected issues occurring during project execution. Lean principles guard against such practices and save schedules and cost. Lean principles, tools and methods improve most, if not all project performance metrics, simultaneously, i.e., in harmony. • The obvious and superficial lean production mechanisms—such as standard work, work place organization, kitting and consumption-based replenishment are put in proper perspective with the goals of achieving flow and application of countermeasures. • Mastering rapid improvement techniques as a first step is later linked to overall system improvement via value chain diagnostics and redesign. • We give you a heavy dose of supply-chain management including contracting. Even if your processes are fine tuned and operating well, your supply chain will still be subject to the natural chaos that occurs in logistics and human nature. • To achieve quick wins, it is not necessary to implement sweeping changes all at once. Create and sustain market-dominating excellence short- and long-term by taking time to understand these concepts and implementing the pieces that will improve performance. Eventually, examine every system, sub-system, and process in the business to achieve “system harmony.”

■ Profound leadership is required to achieve profound rapid improvement • Further, nearly every performance issue affects the trust that project people experience. The level of trust and unity impacts the speed of just about everything, including the feasibility for rapid, sustained organizational improvement. We provide supporting principles and intervention tools to assess and improve trust, unity and culture to solidify, sustain and perpetuate.

Lessons from the past. The rapid improvement discipline has developed, building on the work of Dr. Edward Deming. Several decades ago, when US executives resisted, Dr. Deming told the Japanese that they required profound knowledge to make correct improvement decisions. We contend that while human nature hasn’t changed, due to the work of Deming and many others. Today, during large plant asset delivery, the improvement challenge is not primarily a technical one, but also a need for profound leadership—to cross traditional boundaries to collect the profound data and act on it starting with defining and aligning work-process excellence (in EPCs, client owners and the supply chain). Casting executive dismissal-of-the-need to improve, profoundly, to the realm of cordial hypocrisy, we contend that projects can and must improve and that heretofore unseen client and EPC executive leadership is essential for it to succeed. Subsequent articles in this series will elaborate on what constitutes profound leadership and some necessary lean improvement strategies. HP 1

2 3 4 5 6 7

LITERATURE CITED Patty, R. M. and M. A. Denton, The End of Project Overruns, Lean and Beyond for Engineering, Procurement and Construction,” Universal Publishers, Boca Raton, FL, 2010. Ibid. pp. 66–69 Ibid. pp. 14–26 Ibid. p. 479 Ibid. pp. 54–61 Ibid. Acknowledgements, pp ix–x Ibid. pp. 386, 53

Robert M. Patty, PE, MBA, PhD, civil engineering, currently serves as an advisor and mentor for company leaders seeking to implement the principles and systems of rapid improvement. He served as a constructability/lean consultant for PetroCanada, Saudi Aramco and BP and recently, as KBR’s constructability technology chief and lean program manager worldwide. Dr. Patty has personally led implementations on major capital projects in the US, Canada, Venezuela and Nigeria. Reach by [email protected].

Michael A. Denton holds MS degrees in petroleum engineering and economics. Currently, he is senior appraisal reservoir engineer for $5 billion Knotty Head deepwater Gulf of Mexico project for Nexen Petroleum. He developed skills and gained experience in petroleum engineering, lean project management and leadership working for Mobil E&P, Amoco, BP, Chevron and Nexen Petroleum Oil and Gas companies in asset development and delivering major capital projects in Alaska, Kuwait, Korea, Europe, Africa, South America, the North Sea and the Gulf of Mexico.

HYDROCARBON PROCESSING TURNAROUND AND MAINTENANCE 2011

I T-59

TURNAROUND AND MAINTENANCE 2011

What are the ‘magnificent seven’ Headline elements (2 lines) to successfully pick a contractor? M. McMAHON, Coating Systems, Inc., Savannah, Georgia Valuable pointers help industrial plant managers minimize downtime, maintain quality and safety to improve operations

the contractor to provide a list of the potential workers and request their job history. If not available, think twice.

3. Right equipment for the job. Often underestimated, the At some point in time, every industrial plant must bring in an outside contractor to do specialized work such as boiler blasting, concrete waterproofing and ceiling painting that in-house manpower cannot perform on a cost-effective basis. Such an option makes sense, in that many industrial operations do not enjoy the luxury of reassigning staff to do labor-intensive work that requires additional training. Nor does facility management have at their ready disposal the unique equipment required to perform major maintenance or upgrade projects. However, the greater challenge lies not in deciding whether or not to call in outside help, but rather, determining which contractor is best able to do the job on time, within budget, with the best outcome and the least lapses in safety. With the right selection, an outside contractor can act as an ongoing partner to help plant managers and facility engineers lower costs and add value over the long run.

1. Precise planning. The need to run at 100% production levels at all times heads the priority list at most every processing facilities. Downtime for maintenance or upgrades equates with an interruption in revenue stream. In defense, the best way to avoid having any outside work halt the process is to ensure that the contractor provides a precise, highly detailed plan of the project work in advance. If a contractor can’t tell you how he’s going to do that job, and lay it out in an organized, detailed, step-by-step fashion, then you shouldn’t hire him. If you can’t build it on paper, then you can’t build it in reality. For example, by using “critical path method scheduling” (which incorporates close to 30 items and covers the scope of work, the crew, specifications, safety checks, tasks broken down by each different craft and a complete timeline from start to finish) a project schedule should be provided to the plant manager well in advance of any work.

painful truth is that inappropriate or underperforming equipment can greatly increase the time to complete a project. Conversely, a contractor can actually bring about a cost savings for plant management, and return the plant to full operation quicker, if proper equipment is selected with forethought and applicability to the specific project. When tackling a critical project such as applying a coating of epoxy novolac to the inside of a 300-ft diameter storage tank, contractors should be willing to go through the trouble of bringing in portable air conditioners, or heaters depending on the time of year, to manage the environment within the tank. This controls the Two line caption humidity and prevents premature rusting of exposed metal before the coating goes on. Without such precaution, unanticipated coating failure could develop. At the same time, the controlled environment allows workers to continue spraying 24 hours a day instead of just 8. The job gets finished in one-third of the time, so, the tank can get put back online sooner. Even something as simple as ready access to the equipment and tools can make a difference in the timeline. For example, one informal time/motion study revealed that the average mechanic spends an hour and five minutes each day looking for tools. Ask to see photographs of the contractor’s equipment and tool trucks. If you see a gang box filled with a bunch of tools that guys have to dig through to find what they need, then that disorganization can lead to cost overruns.

4. Safe work practices. Safety can never be compromised for the sake of speed. If anything, a serious accident can stop a project in its tracks and immediately place a project budget in peril. Checking a contractor’s commitment to safety begins at the top.

2. A qualified workforce. Given the present scholastic environment where far more students study computer science as opposed to metalworking, the pool of skilled craftsmen continues to dwindle. After soliciting RFQs, the down-selection process must include a careful evaluation of the contractor’s complement of tradesmen. The importance of having a job go smoothly rests, in great part, on the skill of the people actually twisting the wrenches. They must possess a basic aptitude for the job, as well as a good work ethic. Advance determination of such qualities is not as difficult as it seems. Recognized training programs can vouch for satisfactory performance levels from a given craftsman. Additionally, most every technical discipline has credentialing bodies, which evaluate respective contractors and their employees for competency. The Society for Protective Coatings, for one, offers its SSPC QP1 certification to contractors that meet a set level of performance in key areas such as management procedures, technical ability and quality control. Such certification provides facility owners and specifiers a means to determine whether the painting contractor has the capability to do surface preparations and coating applications on storage tanks, pipelines, flooring, process equipment and other plant infrastructure. Judging work ethic takes more effort. Look for a contractor who features a dedicated, long-term team of workers vs. hiring a local crew “off the street.” Ask 60

I TURNAROUND AND MAINTENANCE 2011

HydrocarbonProcessing.com

FIG. 1. SSPC QP1 certification provides facility owners a means to determine whether a painting contractor has the capability to perform surface treatment and coating applications on storage tanks and pipelines.

TURNAROUND AND MAINTENANCE 2011

Headline (2 lines)

The mechanics will do whatever the supervisor lets them do. If the foreman allows the workers to stand on a ladder without a safety belt, they will do it. So, supervisors should attend process safety management training classes so that they will set the right tone. Once a project begins, conditions should be constantly monitored, and safety inspections are conducted weekly by the operations manager. A contractor’s membership in the American Society of Safety Engineers also indicates a commitment to reducing injuries. Additionally, the prospective contractor should be able to demonstrate site-specific training of its employees. Examples include training in fall protection, respiratory protection, hazardous waste handling, Mine Safety and Health Administration procedures, and a confined-space program.

5. Access to spare parts and equipment for unforeseen circumstances. Every product manufacturer understands the need for a “second-source” supplier. It should be no different for contractors who show up to do critical work at a plant. The contractor must outline a systematic process to acquire spare parts on an urgent basis when the “inevitable” emergency occurs. You have to have “Plan B” as well as “Plan C”. To be on the safe side, the contractor should have duplicate pieces of machinery at the ready so if a part breaks, it won’t halt the work. For example, when working on a tight timeline for a project, it’s a good idea to ship backup equipment to the site. It may just sit there as a backup and never be used, but the expense is well worth the peace of mind.

customer is crucial. The customer should receive three separate reports at the end of each day, each one covering construction overview, safety and quality.

7. A willingness to partner for the long run. An index of suspicion should rise when a contractor appears anxious to take the money and run. Some eventually declare bankruptcy, leaving plant management with no recourse if anything goes wrong. Look for a contractor who is willing to maintain an onsite presence well after completion of the scheduled work. Even beyond that, added value stems from a contractor who is willing to act as a resource for long-term maintenance planning. Such partnerships actually free up the plant’s workforce to concentrate on more immediate needs. Plant foreman can benefit from permanently delegating some of their technical services to a contractor with expertise in their respective fields. A supplemental part of some contractors’ businesses is to develop specifications and procedures to reduce rework and extend service life. Many foremen stay on at a given site to provide such services as corrosion surveys, failure analyses, computerized maintenance painting programs, industrial cleaning, fireproofing and OSHA pipe labeling and safety-sign surveys, which can prove to be very valuable services for most plants. Ultimately, enlisting the help of a proven contractor on a year-round basis allows processors and manufacturers to keep their own staff focused on the core competency of the organization. HP Two line caption Michael McMahon is president of Coating Systems, Inc. (CSI), Savannah,

6. Constant communication with plant management. Upon completion of a project, few plant managers like surprises such as unexpected, expensive change orders or up-scoping. A conscientious contractor must be willing to provide project reports up-front and on a daily basis. Clarity with the

Georgia. CSI is a SSPC QP1-certified specialty maintenance contractor that provides a full range of industrial painting and protective coating services for power plants, transmission pipeline companies, petrochemical plants and chemical processing companies. Its clients include Shell, DuPont, Proctor & Gamble, Kimberly Clark, Olin Chemical, and Colonial Pipeline Co.

Get the Information You Need to Compete in 2011… Order the Full Version of tthe HPI Market Data 2011

The HPI’s most comprehens comprehensive and trusted forecast of capital, maintenance and operating expenditures for the local and global HPI, the HPI Market Data 2011 includes over 75 pages of expanded coverage and detailed analysis for: • • • • • •

HPI Economics Equ Maintenance and Equipment Natural Gas/LNG Petrochemicals Refining En Health, Safety and Environment

f Includes a BONUS CD featuring: • More than 10 years of trends on global construction activity and spending from previous forecasts. Box • HPI Construction Boxscore Updates 2009 and 2010. Hydro • 20 articles from Hydrocarbon Processing picked by the ke trends and issues. editors to highlight key

ORDER YOUR COPY TODAY and make strategic decisions in 2011 and beyond! Online: www.GulfPub.com/2011hpi Call: +1 (713) 520-4426

Select 163 at www.HydrocarbonProcessing.com/RS TURNAROUND AND MAINTENANCE 2011

I 61

Select 97 at www.HydrocarbonProcessing.com/RS

CORPORATE PROFILE: ALTAIRSTRICKLAND TURNAROUND AND MAINTENANCE 2011

Mastering FCCU constructability issues ALTAIRSTRICKLAND has been managing and executing turnarounds and revamps since its inception in 1976. Meanwhile, refineries have become more congested and more complex but footprints remain about the same. This complicates project execution and raises multiple constructability issues. Concerns for quality, safety, schedule and budget add to the multidimensional scope. AltairStrickland stresses that preplanning is a key to the door of success. Here are just three examples of how they have addressed tough constructability issues.

FCCU Revamp, Case Study #1: This air grid installation revamp scope was extensive and included: • Installation of regenerator lower cone section • Replacement of regenerator air grid • Replacement of reactor trickle valves • Flue gas line repairs • Knife gate valves repairs • Extensive refractory work • Miscellaneous maintenance work The main constructability issues concerned the installation of the regenerator in the lower cone section and replacing the riser’s feed section. The FCCU still had the original plate type air grid. The original scope called for installing the trunk of the grid into the existing cone section, however, there was no access for welding or for weld inspection if the trunk grid was to be installed in this way. That’s when AltairStrickland went the extra mile and constructed a mock-up of the equipment so they could demonstrate the problem. This prompted the owner to procure a new cone section. Still, installation was difficult. The structural steel came up to the tangent line, there were several big beams that could not be removed, and there was an upper constraint layer of dip leg bracing and some trickle valves that had to be removed. The beams were redesigned with notches to allow as much height as possible. Two air hoists on trolleys were used as part of the rigging so the equipment could be taken from the crane and led through the door sheet. Beams were needed to support the door sheet and rigging devices. The cone section was installed with the lower part of the trunk. The air grid was brought in so the two back lateral arms could be installed first then followed by installation of the two front lateral arms. Each piece of air grid weighed about 26,000 pounds and the cone section weighed in at 28,000 pounds, still the job was completed on time and within budget.

AltairStrickland did a 3-D survey of the construction area before modeling it in AutoCAD™. This process revealed a better way to lift the 690,000-pound FCC reactor.

FCCU Crane Considerations, Case Study #3: When AltairStrickland was hired, this client already had selected a crane they wanted to use to lift the 600,000-pound reactor. The crane they had in mind required that a major freeway be shut down during the heavy lifts. AltairStrickland studied all aspects of the lift and suggested that a 660-ton crawler crane could perform the job without the hassle and expense of shutting down the freeway. The client agreed and the lift came off without a hitch. AltairStrickland has mastered both the science and the art of constructability.

FCCU Revamp, Case Study #2: A new client approached AltairStrickland for an FCCU revamp. In this case, the scope included: • New head and cyclones in the regenerator • Installation of a new reactor • Tie-ins to the FCC for a new scrubber • Flue gas cooler work • Major structure work For this major equipment installation, the client envisioned installing the combustor riser distributor cap before installing the head and cyclone assemblies. AltairStrickland presented preliminary drawings showing that the concept would not work with the secondary trickle valves on. Instead, they proposed that the cap be installed with the head and cyclone assembly. The client agreed. This satisfied client has since awarded AltairStrickland other jobs. SPONSORED CONTENT

Contact information 1605 S. Battleground Road La Porte, TX 77571 Phone: 281-478-6200 Fax: 281-478-6206 E-mail: [email protected] Website: www.altairstrickland.com

HYDROCARBON PROCESSING TURNAROUND AND MAINTENANCE 2011

I T-63

Select 95 at www.HydrocarbonProcessing.com/RS

CORPORATE PROFILE: CURTISS-WRIGHT FLOW CONTROL TURNAROUND AND MAINTENANCE 2011

CWFC offers comprehensive products and services for the oil and gas industry Curtiss-Wright Flow Control’s (CWFC’s) Oil & Gas Systems Division supplies a diverse portfolio of products and services to the oil and gas industry, including reactors, fractionating towers, separator, orifice chambers, diverter and butterfly valves, fully automated coke drum unheading systems, as well as integrated control systems, engineered valves, safety relief valves, and service and repair, and more. As demand for global fuel requirements grow, processing capacity must also increase and CWFC’s products provide the oil and gas industry with significant savings while providing technology solutions that foster plant flexibility, reliability, enhanced production and compliance with safety and environmental regulations. The business units and their brands which comprise CWFC Oil & Gas Systems provide critical technology for severe service processing. Each business unit with its brand has its own focus and market niche, and when combined with the other business units offer an extremely diversified range of products and service for the oil and gas industry. DeltaValve is the world leader in full automated coke drum unheading solutions. Their systems are available for the bottom and top of the coke drum, and completely isolate personnel and equipment from coke drum fallout and other hazards associated with the unheading process. Other innovative products include DeltaValve’s drum top blowout diverter/ drill stem guide, auto-switch coke cutting tool, and a complete line of isolation valves designed specifically for the dirty service associated with the delayed coker. TapcoEnpro International (TEI) provides products and services to improve the safety, reliability and efficiency of your Fluidized Catalytic Cracking Unit (FCCU). With 14 active patents and the largest installed base of single source FCCU valves and actuators worldwide, TapcoEnpro technology and innovation provides a complete package of state of the art, critical service, high temperature valves; fast acting hydraulic actuators; digitally controlled hydraulic power units; heavy wall reactors and pressure vessels and other FCCU components.. Total Automation Solutions (TAS) is a turnkey supplier and manufacturer of integrated automation and controls technology, products and services. TAS integrates quality OEM automation and control products with the optimum team of automation and control engineering resources to supply custom manufacturing, automation management and maintenance services, automation systems design, and PLC Programming Services Valve Systems and Controls (VSC) can manage the entire front end of your project, from conceptual thinking to product specifications, from budgets to timelines, and can supply any or all of the products and services required. VSC can also provide highly skilled service technicians for repair, retrofitting, preventive maintenance and training on valve systems anywhere in the world, regardless of manufacturers or systems integrators. GroQuip has, since 1972, been safely delivering quality as a supplier of engineering information, products Safety Relief Devices, and services to customers with pressure processes. Their customers have strict regulatory compliance mandates (OSHA-PSM; EPA-RMP; BOEMRE; etc.). Largely, the customers are in Chemical Processing Industry (CPI); Hydrocarbon Processing Industry (HPI); Upstream Exploration and Production; Midstream Gas Processing, Fractionating, Pipelining; and Downstream Refining. Farris Engineering has been a leader in the design and manufacture of a wide range of spring-loaded and pilot-operated pressure relief valves for more than 60 years. Used as safety devices, they prevent over pressurization of vessels, pipelines, and processing equipment. Farris Engineering is a recognized leader in the hydrocarbon processing, refinery, petrochemical, gas production and processing markets. SPONSORED CONTENT

Farris Engineering Services provides patented, web-based iPRSM® software, a powerful engineering calculation and documentation repository tool, assists processing plants in meeting the pressure related requirements for PSM compliance. Together with iPRSM, our Farris Engineering Services team provides comprehensive pressure system design and audit services, providing processing facilities with a safe and hazard-free work environment. Sprague Products includes air driven hydraulic pumps, gas boosters, and power units supported with a complete line of valves and pump accessories. The Sprague S-216 and PowerStar line of pumps offer various liquid pressures up to 33,500 psi (2311 bar). Sprague’s pneumatic gas boosters are a cost effective way to compress air/gas to meet high pressure requirements. The pneumatic gas amplifier design offers greater efficiency as well as being modular for increased versatility. Solent & Pratt is based in Bridport, Dorset, United Kingdom, and is a world leader in the manufacture of high performance triple offset butterfly valves for severe service applications. These valves are used within the petroleum, petrochemical, chemical and process industries.

Contact information 16315 Market Street Channelview, Texas 77530 Website: www.cwfc.com

HYDROCARBON PROCESSING TURNAROUND AND MAINTENANCE 2011

I T-65

410 21st Street South P.O. Box 3028 Texas City, TX 77592-3028 Houston: (281) 337-1222 (24 Hrs) Texas City: (409) 948-1704 (24 Hrs) Fax: (409) 945-9873 Dunn Heat Exchangers specializes in the cleaning, repair, testing, design, and fabrication of shell and tube type heat exchangers and unfired pressure vessels. Serving clients throughout the U.S., Dunn works with some of the largest refining and petrochemical complexes in the world.

Safe Transportation

High Pressure Hydro Cleaning

Dunn operates its own fleet of specially designed tractortrailers to provide fully covered, drip-pan containment of equipment for safe transportation.

Dunn’s 5 shell side cleaning bays and 7 tube side cleaning bays allows our hydro cleaning facility to simultaneously clean 12 heat exchangers.

Thermal Cleaning & Wastewater Treatment

Decommissioning and Disposal

Dunn’s licensed l d Bake-Out-Oven k thermally h ll decomposes d product residue while maintaining equipment integrity. Dunn meets or exceeds all EPA standards for liquid and solid waste treatment & disposal.

Dunn offers a service to help you with decommission and disposal of your “out of service” obsolete equipment. This turnkey service includes safe transport, dismantling and cleaning of equipment that is no longer required for plant operations.

New Fabrication ASME U Certified

Repair Certified ASME R Stamp

Dunn is a fully f ll certified fi d ASME code d ffacility l offering ff both b h repair and d new fabrication f b services. Contact Dunn today to discuss your plant requirements and how you can benefit by using the many services provided by Dunn Heat Exchangers. Visit us at www.dunnheat.com.

281-337-1222

409-948-1704 Select 59 at www.HydrocarbonProcessing.com/RS

CORPORATE PROFILE: DUNN HEAT EXCHANGERS, INC. TURNAROUND AND MAINTENANCE 2011

Critical Path Performance = Success

In the early 60’s Dunn recognized a need for off-site Heat Exchanger Service for the local Petro-Chemical plants. That idea that has grown from a shop of just over 6,000 square feet serving 2 to 3 local plants, to a thriving business serving more than 120 customers in 3 countries. Since 1968, Dunn Heat Exchangers, Inc. has worked hard to become one of the largest Shell and Tube Heat Exchanger Service companies. Serving clients needs throughout the United States, Canada and Mexico. Dunn specializes in cleaning, repair, design, and fabrication of Shell and Tube Heat Exchangers and unfired pressure vessels. With better than 150,000 square feet of covered workspace in Texas City, Texas, Dunn is capable of handling your largest shutdowns meeting your planning requirements, while alleviating turnaround congestion in your plant. Dunn is available for operation twenty-four hours a day seven days a week. Dunn’s service facility along with our cleaning capabilities enable us to clean in excess of 80 tube bundles per week utilizing a variety of processes including high pressure hydro blasting, sandblast, and thermal baking. Complimented by an equally capable service facility, your heat exchangers receive the priority treatment when serviced at Dunn Heat Exchangers. Dunn has built a reputation on prompt service of your heat exchangers. While unexpected discovery work, seems to expand work scope all too often we are prepared and equipped to handle that emergency retube, replacement bundle, component or full replacement exchanger that your needs may dictate. Dunn’s custom designed Band Saw has a maximum cut of 96 inches and plays a vital part in our exchanger repair and metal recycling services. Dunn is a certified “U” and “R” stamp ASME and National Board shop. Backed by a full machine shop and a qualified staff of welders and machinist we are ready to meet you fabrication needs. Dunn now manufactures a full line of tapered tube plugs, stocking carbon steel, stainless steel and brass. Special material requirements are manufactured as requested. Dunn offers a service to help you with decommission and disposal of your “out of service” obsolete equipment. This turnkey service includes safe transport, dismantling and cleaning of equipment that is no longer required for plant SPONSORED CONTENT

operations. Dunn owns and operates a fleet of tractor trailers for pickup and delivery of your equipment. These trucks are specifically designed, totally enclosed flatbed trailers, for safe transit of your equipment. Dunn’s on site waste water treatment facility meets or exceeds all EPA standards and guidelines for liquid and solid waste treatment and disposal. For additional information contact Dunn Heat Exchangers.

Contact information 410 21st Street South Texas City, TX 77590 Phone: 409-948-1704 281-337-1222 Fax: 409-945-9873 Email: [email protected] Website: www.dunnheat.com HYDROCARBON PROCESSING TURNAROUND AND MAINTENANCE 2011

I T-67

When space is limited . . . So are your choices.

Microtherm - Truly the Best Performance at High Temperatures

MICROTHERM

®

Aerogel

Microtherm is THE choice for low thermal conductivity insulation in high temperature applications.

Calcium Silicate

Ceramic Fiber Mineral Wool

C1676 ASTM Standard for Microporous

0.000

0.020

0.040

0.060

0.080

0.100

0.120

0.140

Thermal Conductivity (W/m-K) at 600 °C Mean

Optimize Your Process with MICROTHERM Conventional Insulation

Equivalent Volume

• 7” of Ceramic Fiber over 6” NPS • 138 °F Cold Face • 465 BTU/ft•hr Heat Loss

• • • •

0.160 Data Per ASTM Testing Standards

®

3” of Microtherm MPS over 12” NPS 132 °F Cold Face (6 °F lower) 380 BTU/ft•hr Heat Loss (18% less) Increased Production 400%!

1450 °F Internal Equivalent Personnel Protection

Equivalent Heat Loss

• • • •

• • • •

3” of Microtherm MPS over 6” NPS 127 °F Cold Face (11 °F lower) 228 BTU/ft•hr Heat Loss (51% less) Save Space, Weight, & Energy!

1 1/4” of Microtherm MPS & Quilt over 6” NPS 187 °F Cold Face 451 BTU/ft•hr Heat Loss (3% less) Minimize Space and Weight!

www.microthermgroup.com Microtherm Inc. +1 865 681 0155 Microtherm NV +32 3 760 19 80 Nippon Microtherm +81 3 3377 2821 Select 100 at www.HydrocarbonProcessing.com/RS

CORPORATE PROFILE: MICROTHERM TURNAROUND AND MAINTENANCE 2011

The world leader in high performance insulation Microtherm is the world’s leading producer of microporous insulation, which offers the lowest thermal conductivity of any insulation at high temperatures. Microtherm has been producing this high performance insulation for more than forty years and offers the best thermal performance in a variety of product forms. The offering of many product forms allows Microtherm to meet the needs of many different applications in a variety of different markets. Microtherm is a microporous insulation, which basically means that the insulation consists of a series of microscopic pores that compartmentalize air. These tiny pockets of air are so small, they almost completely prevent air molecules from coming into contact with one another and therefore they prevent most heat transfer from gas conduction and convection. Added to this pore structure is a precise mineral oxide opacifier that works to stop heat transfer through radiation. This combination works together to stop heat transfer through all modes and the net result is a thermal conductivity lower than that of still air and also a thermal conductivity that does not change much across the temperature scale. The “k” value of Microtherm is thus better than all other insulations at elevated temperatures because other insulations have a dramatic increase in their thermal conductivity as their mean temperature increases. The thermal conductivity of Microtherm is always very low, but the higher the mean temperature of an application, the more benefit Microtherm will have over other insulations as their thermal conductivities increase with temperature. In addition to this great thermal performance is the fact that Microtherm contains no organics or binders and no respirable fibers. The lack of organics makes Microtherm noncombustible and the lack of respirable fibers means that Microtherm is a safe, environmentally friendly material to work with. As the thermal conductivity of other insulations increase with temperature, the fact is that only a fraction of the thickness of these conventional insulations would be required if Microtherm is utilized. This is often taken advantage of in applications where space is at a premium or if the weight of the insulation could have an adverse effect. Microtherm insulation products can be used to achieve equivalent cold face temperatures or equivalent heat loss in a much thinner insulation package than convention insulations would require, or Microtherm can be used in an equivalent thickness to provide a much lower cold face temperature and thus heat loss savings as well. The yield of a process can also be increased with Microtherm by utilizing a larger diameter pipe or vessel insulated with Microtherm in the same space where a previously designed system required a greater insulation thickness using conventional insulations. Applications where precise temperature control is important can also make good use of Microtherm because no other insulation can retain heat as well as this excellent insulation. Microtherm offers many different product forms of insulation to suit a wide variety of needs. In the petrochemical industry, the most common products are Molded Pipe Sections (MPS), Slatted panels, and Quilted products. Microtherm MPS products are sized to fit nominal pipe sizes from ½” up to 28” pipe. Microtherm Slatted panels are segmented panels made to roll around a large pipe or vessel and can be utilized on any diameter 24” or greater. Microtherm Quilted products are available as rolls (Microtherm SlimFlex) or as distinct quilts (Microtherm Quilted panels). Both of these Microtherm Quilted products are flexible and able to conform to nearly any geometry that is necessary. All of these Microtherm products are suitable for use up to 1832° F (1000° C). The combination of low thermal conductivity and noncombustible properties allows Microtherm to also be utilized in fire protection roles. The Microtherm SPONSORED CONTENT

Microtherm Slatted Panels installed on a vessel.

products mentioned above can qualify for fire protection credits with a single layer application if certain other criteria are met. The result can be a much thinner and easier to handle removable fire blanket. This provides yet another benefit for using Microtherm products in certain applications. In addition to these most common Microtherm products used in the petrochemical industry, Microtherm offers many other products as well. Microtherm offers rigid panels and boards, bare blocks of Microtherm insulation, vacuum insulated panels (VIPs), and even a granulated formula of Microtherm for filling voids in complex geometry. With such a wide variety of offerings, Microtherm is able to meet the needs of practically any application that may benefit from using this high performance insulation. Evidence of this is the wide spread use of Microtherm in fields as diverse as fuel cells, concentrated solar power, nuclear, steel and non–ferrous, glass, aerospace, marine, automotive, rail, military, passive fire protection, dataloggers and many others. Please take the time to contact Microtherm today to learn more about the high performance insulation products they offer. An Application Engineer with Microtherm will be happy to work towards finding the best product solution for any given application. Take this time to learn about Microtherm products and optimize the potential of your process.

Contact information 3269 Regal Drive Alcoa, TN 37701 Microtherm Inc. +1 865 681 0155 Microtherm NV +32 3 760 19 80 Nippon Microtherm +81 3 3377 2821 E-mail: [email protected] Website: www.microthermgroup.com HYDROCARBON PROCESSING TURNAROUND AND MAINTENANCE 2011

I T-69

O U R

E N G I N E E R I N G

AT

R E N T E C H

C R E AT E S

RENTECH Boiler Services specializes in engineered repairs, rebuilds and upgrades of industrial boilers using headered membrane waterwall design. We retrofit any style of boiler, making RENTECH your one-source boiler company. Our work meets NBIC and ASME standards. To reduce operating costs, eliminate shutdowns, allow faster start-up and cool-down, and reduce emissions, call for personal service from RENTECH Boiler Services.

RENTECH

Boiler Services, Inc.

For more information, email us at [email protected] visit us online at WWW.RENTECHSERVICES.COM or call us at 325.672.2900 Select 83 at www.HydrocarbonProcessing.com/RS

CORPORATE PROFILE: RENTECH BOILER SERVICES TURNAROUND AND MAINTENANCE 2011

Not all boilers are rebuilt equally

An efficient rebuilt boiler is the combined result of its redesign, engineering and fabrication. Our engineering at RENTECH Boiler Services creates reliable boiler upgrades. RENTECH is your one-source, full-service boiler company because we provide reliable upgrades for many types of industrial boilers. We specialize in engineered repairs, rebuilds and retrofits of boilers using headered membrane waterwall design that eliminates refractory walls and seals. You’ll find satisfied customers of RENTECH in a variety of industries – including refining, petro-chemical, manufacturing and power generation – across the U.S. and in several other countries. Our engineers along with our service and manufacturing technicians work together in our state-of-the-art plant and in the field. RENTECH is proud of its reputation and record of service. We work diligently to help our customers operate their boilers more efficiently and safely, and our work is backed by the best warranty in the industry. Our people make the difference because of their experience, knowledge and dedication to customer service. Our qualified engineers understand all process conditions, and they can optimize your system and improve its performance in a cost-effective manner on your original footprint. We offer fully integrated solutions that comply with all performance criteria. Boilers upgraded or repaired by RENTECH provide: • faster start-up and cool-down • cooler furnace environment • minimize unscheduled outages • improved combustion control Since 1997 RENTECH has provided quality products and services, including superheaters, economizers, sulfur condensers, burner and CO/SCR system retrofits, seal-welded furnaces, watertube and firetube boilers, heat recovery boilers, and solid fuel fired boilers. We strictly abide by National Board Inspection Code (NBIC) and American Society of Mechanical Engineers (ASME) standards. Our engineering knowledge, advanced technology and commitment to customer service combine to produce value for each customer by reducing operating costs, eliminating shutdowns, reducing emissions and extending boiler life. Customers with boilers upgraded by RENTECH spend less on maintenance, allowing them to redirect those funds for other needs in their budgets for daily operations and capital improvements. SPONSORED CONTENT

Our employees at RENTECH Boiler Services have accumulated more than 1,000 years of combined service. Our plant covers 12 acres at RENTECH headquarters in Abilene, Texas. In recent years our customers have included 3M, Alon Chemical, ChevronTexaco, Dallas Independent School District, Entergy, Sinclair, Sunoco, Texas Tech University, University of Texas, and Valero. One Valero project engineer said, “I was very impressed with the level of service and quality of work that Rentech Boiler Services was able to provide. I awarded a fast-track job to Rentech for fabrication of a boiler tube bundle on a critical piece of equipment. Rentech was able to deliver a great quality product to the refinery on schedule.” We realize that an efficient boiler contributes to your profitability. So if a boiler is crucial to your plant’s operations, and your outdated boiler is costing you time and money, call or email today to discover a solution that’s right for you from RENTECH Boiler Services. RENTECH is building a reputation, not resting on one.

Contact information 5025-C Highway 80 Abilene, TX 79601 Phone: 325-672-2900 E-mail: [email protected] Website: WWW.RENTECHSERVICES.COM HYDROCARBON PROCESSING TURNAROUND AND MAINTENANCE 2011

I T-71

Filtering Everything that Flows through Industry

Since 1921 Dollinger has stood at the forefront of filtration technology, serving a vast range of industries around the world with a wide breadth of service and scope of products. t
Air Intake Filter Systems - Multistage - Pulse Jet [self-cleaning] - Inertial spin [maintenance free]

t
High Efficiency Filter Panels & Cartridges t
Oil Mist Eliminators t
Lube Oil Filter Systems

SPX Flow Technology Tel: | 800 | 344 | 2611 Email: [email protected] www.dollinger-spx.com www.spxft.com

Select 99 at www.HydrocarbonProcessing.com/RS

CORPORATE PROFILE: DOLLINGER FILTRATION TURNAROUND AND MAINTENANCE 2011

Filtering everything… …that flows through industry In 1921 Dollinger laid its foundation with the development of the world’s first air intake filter for the automotive industry. Dollinger built on this success to become a leader in process filtration technology, serving a diverse range of industries with contaminant removal for air, gas, and liquid processes. Today Dollinger is an SPX company and a global provider of engineered products and service solutions. These solutions provide technological advancements to the process industries striving to achieve higher efficiencies and output, reduce downtime, energy consumption, and environmental impacts. Headquartered in Ocala, FL, U.S.A., Dollinger ensures business leaders will achieve better operational capabilities by tailoring filtration solutions to their individual needs. Our leadership in filtration technology is supported by renowned global expertise with engineering offices in Europe, North America, India, Asia, and beyond. Our customers benefit from international engineering knowledge with a local focus. Our philosophy began with dedication to supply high-quality products and continues today with innovation through engineering.

Serving Markets Worldwide. For decades, Dollinger has been designing and manufacturing filtration and separation equipment for a broad range of industries and applications around the globe. The markets we serve include Oil and Gas (Offshore and Production, Processing and Refining, Storage, Transportation & Distribution), Power Generation, Air Separation, Petrochemical, Chemical, Nitric Acid/Fertilizer Production, Waste Gas and Biofuels and Glass Container Manufacturing. By implementing Dollinger’s premium industrial filtration products and systems, many industries have been able to implement complete solutions engineered to specific needs. These support systems keep their operations running reliably—with uptime assurance for their total peace of mind. However extreme the condition Dollinger maintains mission-critical operations all around the world with innovative technology engineered to handle the most aggressive contaminants.

Scope of Products, Breadth of Service. Dollinger specializes in fluid and air management, leveraging unmatched capabilities to make your operation more successful. With a wide range of filtration products and services, Dollinger will help you improve fluid and air quality therefore increasing profitability by optimizing the performance of processing equipment. Process Pipeline Filters. Dollinger offers Process Filtration Equipment for the Oil & Gas, Petrochemical and Power Generation Industries around the globe. This product range includes both gas and liquid fabricated pressure vessel filters. Custom designs can be incorporated and there are options available to package filter vessels onto a skid arrangement with any required instrumentation or control equipment with ensured compliance to all relevant codes. Air Intake Filter Systems. Our technical development facilities are located throughout Europe, North America, South America and Asia, and are used to simulate a diverse range of environmental conditions, in order to provide you with a detailed technical assessment of your current and desired filter system. Whether producing a small retrofit weather hood, through to a large air intake system with full enclosure, our engineers have decades of experience and are dedicated to designing and delivering a system which will ensure maximum output from your machine. Fuel and Lubricating Oil Filters. The Dollinger Oil Mist Eliminators (OME) is a filtration system of superior efficiency–it collects 99.97% of oil droplets SPONSORED CONTENT

Dollinger service technician installing Pulse Jet filters into a new installation. Replacing elements is necessary for optimal performance and operation of your compressed air systems.

0.3 micron and larger, thus removing virtually 100% of visible oil mist emissions. This performance places Dollinger at the very forefront of oil mist elimination technology. The extracted oil mist droplets can be returned back to the lube oil system removing health, safety and environmental concerns as well as making significant cost savings Keeping fluids clean and free from contaminant and moisture, is an essential requirement for maintaining efficiency. Partnered with Vokes filters and filtration systems, Dollinger can also provide Liquid Coalescers, Fuel Filtration, Lubricating Oil Filtration and Stream-Line Systems for insulating fluid treatment.

Contact information 4647 SW 40th Avenue Ocala, FL 34474-5788 Phone: 800-344-2611 Fax: 800-263-4788 E-mail: [email protected] Websites: www.dollinger-spx.com or www.spxft.com

HYDROCARBON PROCESSING TURNAROUND AND MAINTENANCE 2011

I T-73

CORPORATE PROFILE: VOITH

TURNAROUND AND MAINTENANCE 2011

World-class in turbo gears and service

ai_BHS_60.2_en aio

Voith Turbo BHS Getriebe GmbH, Germany has been one of the world’s leading manufacturers of Turbo Gears for over 75 years. More than 20,000 references and over 100,000 MW installed capacity are impressive evidence of the very high level of customer confidence in the products and services. Due to the highly qualified workforce and the latest manufacturing techniques, BHS is capable of providing optimized gearbox solutions even to surpass the stringent demands of every OEM, engineering company or plant operator. BHS offers a broad spectrum of power transmission products to meet the needs of the Oil & Gas industry for upstream, midstream and downstream applications. The designs have achieved pitchline velocities of over 200m/sec (660 ft/sec) and pinion speeds of 100,000 rpm. Up to 80 MW can be tramitted by the gearboxes. All customers are fully supported through a first class global sales and service network. This applies for their own units, supplied under the trademarks BHS, BHS Sonthofen, BHS-Voith, BHS-Cincinnati, BHS Getriebe, Krupp, Voith and Voith Turbo BHS Getriebe, but also other manufactureres. As a recognized world leader in providing reliable, efficient, high quality gear units they successfully meet the challenges of today’s high speed turbomachinery applications. Voith Turbo BHS Getriebe GmbH is part of Voith Turbo’s industry division. Voith

Turbo is the specialist for hydrodynamic drive, coupling and braking systems for road, rail and industrial applications, as well as for ship propulsion systems. Voith sets standards in the markets energy, oil and gas, paper, raw materials and transportation and automotive. Founded in 1867, Voith employs almost 40 000 people, generates €5.2 billion in sales, operates in about 50 countries around the world and is today one of the biggest family-owned companies in Europe.

Contact information Hans-Boeckler Strasse 7, 87527 Sonthofen, Germany New business +49 (0)8321 802-502 Service +49 (0)8321 802-555 Fax: New business +49 (0)8321 802-685 Fax: Service +49 (0)8321 802-545 E-mail: [email protected] or [email protected] Website: www.bhs-getriebe.com or www.bhs-gearbox-service.com

Service Technician Herbert Kuisle

Reach our new Houston Service Center at (281) 453-5500

Service for Unparalleled Gearbox Performance 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

T-74

I TURNAROUND AND MAINTENANCE 2011

Select 166 at www.HydrocarbonProcessing.com/RS

SPONSORED CONTENT

PLANT SAFETY

BONUSREPORT

Process safety: Blind spots and red flags Improving safety for organizations involve more than technological solutions; understanding processes and plant interactions are a must T. SHEPHARD, Mustang Engineering, LP, Houston, Texas

T

he Process Safety Management (PSM) regulation 29 CFR 1910.119 was developed in response to a series of major accidents. These same events led to the creation of the safety instrumented system (SIS) standard, ANSI/ISA-84.00.012004 Part 1 (IEC 61511-1 Mod). Both provide a wholistic, lifecycle approach to the design, operation and maintenance of SIS and facilities. Plant safety improves when these programs are implemented, although accidents can still occur. From studies of major accidents, most result from the simultaneous occurrence of multiple and seemingly minor errors and “incidents” that interact in complex and unforeseen ways. 1 PSM and ANSI/ISA 84.00.01 are similar in that both have interdependent elements that work together to reduce the likelihood of errors and hazards that can contribute to an accident. A failure or error in any element becomes the weak link. This article explores some of the hidden errors and conditions that can occur during the SIS or facility life cycle, and refers to them as “blind spots.” Examples of their varied modes and risks are highlighted. “Red flags” are a common prelude to a major accident. As an aid to revealing blind spots, an awareness of common red flags may be helpful. Examples from major accidents are listed. “Blind spots” are often recognized as a significant contributor to a major accident. Those discussed here have hidden or unforeseen mechanisms that can degrade an SIS or a safety management program. Independent protection layers (IPLs) applied to reduce risk are methodically selected and implemented to reduce the probability of hazard occurrence to a tolerable risk. Typical IPLs include relief valves, alarms and SIS. Accidents can result

if an IPL is inadequate, degraded or fails. Undefined hazards also exist and the associated hazard consequence and likelihood are unknown. Project execution. Today’s typical large-scale engineering projects have major teams that interact with many organizations and companies. In a relatively short time, they generate thousands of documents and a thousand-fold increase in project data that resides in many forms, formats and systems. This information is communicated through many different media. Being a human endeavor, quality checkpoints are added at key points. Schedule compression tends to increase error rates and challenge the quality-check process. Compression is common to fast-track projects, and can occur with late design changes, delayed decisions and extended approval cycles. Quality checks become less

effective if performed at the wrong time or under stress; thus, errors can be missed. A purchase order with a single digit error in a lengthy model number procures the wrong material. A person with essential technical knowledge misses a key meeting. An inspector misses an important detail at a factory check. Undetected errors can occur in the engineering data exchange between companies if the data exchange protocols are not well defined or managed. Construction projects have a higher number of personnel who work within a physically more hazardous environment. Onsite decisions are constant. Items don’t fit, material cannot be located or a key person in the communication channel is taken ill. A missed or inaccurate positive material check on a case of bulk alloy fittings is not detected. If detected, the installed locations may be unknown. The transition from construction to pre-commissioning and

Ops/maint. req’mts.

Fn safety plan

SIS Bypass, schematic reset, Standards diagrams SIF manual definitions requirements ESD SIL & STR targets SIS architecture Test & diagnostic & interfaces P&IDs, req’mts, SIF change Target SIL & STR process SIL calcs. to meet SIL Target test intervals engr. & studies SRS Valve failure mode Vendor reliability data Process response SIS time, trip settings Equipment, architecture diagnostics, & loop Validation standard design SIL calculations Validation results architecture test & inspection SIS & SIF results Make & Approved vendor list loop Action list, validation status model project design standards design SIF design & status, required Reports diagnostics minimum test frequency, auto-generated Instr. test procedures data Design Application software SRS, sheets req’mts. detailed design definition LOPA report & F/U

FIG. 1

Safety requirements specification (SRS).

HYDROCARBON PROCESSING MARCH 2011

I 75

BONUSREPORT

PLANT SAFETY

startup involves handoffs of many documents and status reports—all opportunities for missed information. Safety assessments. Safety assessments such as hazard and operability studies (HAZOPS) identify hazards and quantify their respective risks. A hidden deficiency in this process can result in risks that are underestimated so that the applied IPLs are inadequate. A hazard can be missed or incorrectly assessed if the team is missing key technical, operating or maintenance expertise.2 Combustion and process experts are needed to assess the complex impact of a major fuel gas drum swing on multiple fired vessels across the facility. Perhaps the burner data sheets no longer exist so it is not possible to verify if the burners can operate safely with the current fuel-gas composition range. Expertise needed to identify and accurately assess hazards that are unique to rotating equipment, exothermal reactors and high-pressure equipment may also be missing. The assessment may fail to consider all modes of operation, common mode failures, process response time or the complex scenarios that can result when a major upset occurs in a shared utility system, e.g., steam, instrument air or cooling water. A safety related alarm applied as an IPL may be invalid. This can occur if an operator cannot reliably respond to the alarm within the process response time (preferable half the time). Further, the alarm IPL is invalid if a common event generates multiple alarms that exceed the generally recognized operator alarm response limit of 10 alarms in a 10 minute period.3 The assessment may fail to explore this possibility. Finally, if the alarm is invalid, then the SIL assigned to an associated safety instrumented function may be insufficient. Technology. New technology and new

designs often create unforeseen “challenges.” When the industry embraced open systems, the Microsoft Operating System became a standard component in many control systems. The unforeseen risk was an ongoing urgency to install frequent software “patches” to correct security holes and software stability problems. Another is the increased exposure to destructive viruses of the type recently revealed as the Stuxnet virus.4 Computer servers require frequent replacement due to early obsolescence. Control-system vendors press users to upgrade application software and hardware to ensure future product support. These 76

I MARCH 2011 HydrocarbonProcessing.com

upgrades often have subtle and undocumented technical and performance differences. Implementing a change before it is fully tested introduces an unknown risk. If a facility’s software backup and recovery procedures are inadequate or not followed, then the wrong program or an outdated version may be loaded in response to an unplanned emergency repair. Inadequate physical and administrative control of an engineering work station connected to a safety system can compromise system integrity. Sensitive process control networks, thought to be isolated, may, in fact, connect to a business network or unprotected Internet connection and become a tempting target for computer hackers worldwide. Cross-connection of a processcontrol system network to a business enterprise network opens the opportunity for a control system interruption or upset that may be caused by a routine business network administrative change or update. High-integrity pressure protective systems (HIPPS) are increasingly being used to reduce project cost or increase production. A well-designed and managed HIPPS offers safety benefits, but is also a “hightech” solution that replaces a low-tech solution that is well understood. Management of HIPPS and other SIL 3, high-integrity safety systems require a mature, disciplined and technically talented organization for the duration of the system’s life cycle. Most of the blind-spot failures discussed here can degrade this system. Because a SIL 3 system is typically implemented to mitigate a highconsequence safety hazard, its failure or degradation can result in a major accident. Human factors. Humans will always make mistakes regardless of age, training and level of experience. A well-designed system, organization or procedure integrates humans into activities and processes where they are known to perform well, and it avoids or minimizes activities that humans are known to perform less reliably. If this is not the case, the expected error rate will be higher, and the resulting errors may be overt, hidden or unforeseen. Human error in any type of process or activity increases when humans are under tasked, over tasked or placed under stress.5 Human error is not random, but it is now understood to be systematic. The error is biased by the systems, culture and environments in which humans operate. 5 Under high stress, the perception of time can become distorted. During a plant emergency, the actual elapsed time

as experienced by a stressed individual may be significantly longer than perceived. When presented with a problem, humans tend to develop a mental model of what is happening and select data that supports that model. Data that does not support the model is often ignored—a condition that has contributed to major accidents. On the positive side, humans are essential because they provide the only means available to mitigate or manage a hazard that was previously unknown and has no other safeguards. Organization. High-performance organizations of the type needed to manage high-integrity safety systems and successfully merge PSM and ANSI/ ISA S84.00.01 are not at a natural state; the laws of entropy apply. Organizations undergo continuous change, whether desired or not. The organization affects the other listed modes in positive and negative ways, which means it contributes to blind spots. A seemingly subtle change in priorities, staffing, training, work processes, safety culture, age, technical expertise or tools can significantly affect process safety as it interacts with other listed modes. When SIS progresses through its life cycle, the safety requirements specification (SRS) provides the essential foundation document needed to define and maintain system integrity. Fig. 1 summarizes the information included in this document. An inadvertent change in any item can degrade or disable one or more safety instrumented functions residing in that safety system. Mapping each datum element to the department, technical discipline or organization charged with its creation or management provides an indication of the potential challenge. The opportunity for hidden errors and changes increases when elements are distributed across organizational boundaries. If the group charged with managing a PSM program operates like a regulatory organization, then the expected safety management culture and practices are probably not being fully realized, although “full compliance” may be what’s listed in company reports. Current organizational structures may be an impediment when attempting to merge the requirements of ANSI/ISA S84.00.01 into the existing organization. How organizations integrate this standard with their PSM program appears to be an early work in progress for many. Until this process is complete and the “bugs” are worked out, mistakes will happen.

PLANT SAFETY Operations and maintenance.

Operating modes may exist that are “below the radar” and, therefore, not assessed from a safety and risk perspective. A facility may regularly have a manual bypass valve open around a control valve to increase throughput. Others may operate a fired process heater when a forced draft fan has failed. A damper is opened and the heater is operated in a natural draft mode that was not considered in its original design. An operator tweaks a mechanical stop on a fuel-gas valve, changing a process heater’s minimum firing rate. Use of safety system bypasses may become a common and casual act. The duration that a safety function is bypassed may be increasing, but it is not tracked and goes unnoticed. On the maintenance side, off-thebooks repairs and undocumented software changes may be implemented in response to a problem that occurs during an unscheduled event, holiday weekend maintenance callout. Spare parts used may not actually meet the “replacement in kind” requirement of PSM or the more rigorous requirements in ANSI/ISA S84.00.01. Changes may be made without applying the “Management of Change” process (from PSM), or perhaps the process is not sufficiently controlled or transparent. Risk acceptance creep. Individual

risk tolerances can shift when the person is faced with an immediate decision on whether to proceed (e.g., maintain production) or revert to a known safe state (e.g., shutdown). Risk acceptance appears to increase or perhaps, risk denial occurs. For example, a difficult new unit startup is nearing completion. A safety event occurs, forcing the person in charge to decide on whether to proceed or shut down. The risk associated with proceeding is not immediately clear or understood. The time-sensitive decision increases stress and may offer little time to consult others who may understand the risk. (Perhaps the person who understands the risk is not in a position to affect critical decisions.) The decision to proceed or shut down reflects the attributes of the decision-makers and how they have internalized their understanding of the company’s management expectations, safety culture, priorities and training. The decision to proceed is made, and the situation improves, worsens or remains unclear. This may be followed by another decision to proceed and it follows the well-worn adage, “in for a penny, in for a pound.” This phenomenon, in a

slightly different form, can occur during the engineering phase of a project when a tight schedule conflicts with the time needed to finish a safety-critical assessment or quality check. Accident investigations. Analyzing and identifying the root cause of a near miss or an accident is an essential element in a safety management program. Past theory and practices for accident investigations took an approach that often cited “operator error” as the root cause. The new theory, which takes a much wider view, will often trace the root cause to a management failure or a failure of the organization or system in which humans function.5 Those applying the old approach (still commonplace) are not aware of where the true weakness in their systems exists, so similar accidents may reoccur. Management and leadership.

All organizations, whether they are project teams or operating facilities, face the dichotomy of balancing process safety with production, cost and schedule demands. By words, actions and examples, management and safety leaders demonstrate their expectations. Subordinates interpret this message and bias their actions and attitudes accordingly. Given the challenges of communications in large and complex organizations, a few misunderstood words or an ambiguous or conflicting message may degrade the process safety attitude of employees. For example, the appearance of an overriding priority on production may bias an operator’s belief that a unitshutdown button should only be used if the hazard is certain and imminent. The systematic bias may be to delay a safety response when it conflicts with production. A downsizing that lays off a key technical expert who provides maintenance support for a highly technical safety system, places that system at risk. Management and safety leaders may not be aware of the possible limitations in their safety management program. Many companies are implementing behavior-based safety programs that have been very effective at reducing injuries and accidents. These same programs may be less effective at revealing or mitigating errors caused by technology or project execution blind spots. An assumption that a given safety program sufficiently encompasses the full breadth of the safety management challenge may be a serious blind spot.

BONUSREPORT

Red flags. Several blind spot modes have been discussed. Many others exist, including training, standards and procedures, physical environment and regulatory environment, to name a few. A complete listing of possible blind spots within each mode can fill volumes. To limit their accident contributions, an awareness and acceptance that blind spots exist are essential. Another important element in a safety management program should include an awareness of the red flags that often precede a catastrophic accident. Management and safety leaders should give pause when they hear several important listed words; they may have just arrived at “that point, that last chance” when a critical failure can be prevented: • Experience says that will never happen (most catastrophic accidents)6, 7 • We need to reduce maintenance, staffing and training to cut costs (Bhopal MIC release)7 • “So we are all in agreement, RIGHT” (Shuttle Challenger and Columbia Disasters)6 • We don’t have time for that (most catastrophic accidents)6, 7 • Prove to me that it is not safe (Shuttle Challenger and Columbia Disaster).6 HP 1

2

3

4 5

6

7

LITERATURE CITED Perrow, C., Normal Accidents: Living with HighRisk Technologies, New York, Basic Books Inc., 1999. Shephard, T. and D. Hansen, “IEC 61511 Implementation—The Execution Challenge,” Control, May 2010. Bullemer, P. and D. Metzger, “CCPS Process Safety Metric Review: Considerations from an ASM Perspective, ” ASM Consortium Metrics Work Group, May 23, 2008. Bartels, N., “Worst Fears Realized,” Control Engineering, September 24, 2010. Decker, S., The Field Guide to Understanding Human Error, Surrey UK, Ashgate Publishing Ltd., Reprint 2010. Brigadier Gen. Duane W. Deal, USAF, “Beyond the Widget: Columbia Accidents Lesson Learned Affirmed,” Air & Space Power Journal, Summer 2004. Joseph, G., M. Kaszniak and L. Long, “Lessons After Bhopal: CSB a Catalyst for Change,” Journal o f Loss Prevention in the Process Industries, Vol. 18, Issues 4–6, July–November 2005.

Tom Shephard is an automation project manager at Mustang Engineering. He has 28 years of control and safety system experience in the oil and gas, refining, marketing and chemical industries. Mr. Shepherd is a Certified Automation Professional (ISA) and a certified Project Management Professional (PMI). He holds a BS degree in chemical engineering from Notre Dame University. HYDROCARBON PROCESSING MARCH 2011

I 77

BONUSREPORT

PLANT SAFETY

Consider new design criteria equipment modules Construction offers cost-effective protection of critical systems D. COLE and D. AUSTIN, Lectrus, Chattanooga, Tennessee

T

he January 2011 HP article, “Considerations for blastresistant electrical equipment centers,” focused on the history, background and key considerations of blast-resistant modules (BRMs) and blast-resistant electrical equipment centers (BRECs), designed to protect personnel and vital electrical controls, respectively. The article outlined the benefits of utilizing protective shelters at hydrocarbon processing industry (HPI) plants. The premise for greater concern with regard to both personnel and process safety was established. Whereas the discussion gave light to both shelter types, this article focuses specifically on the detailed aspects of BRECs: design, construction, analysis, blast load testing, test results and conclusions. Following the Texas City, Texas, incident of March 23, 2005, a special panel headed by former Secretary of State James Baker was convened. The panel findings are documented in what became known as the “Baker Report” of January 2007. One of the most notable sets of statements made in the report places process safety on par with personnel safety: “Not all refining hazards are caused by the same factors or involve the same degree of potential damage. Personal or occupational safety hazards give rise to incidents—such as slips, falls and vehicle accidents—that primarily affect one individual worker for each occurrence. Process safety hazards can give rise to major

accidents involving the release of potentially dangerous materials, energy releases (such as fires and explosions), or both. Process safety incidents can have catastrophic effects and can result in multiple injuries and fatalities, as well as substantial economic, property and environmental damage. Process safety refinery incidents can affect workers inside the refinery and members of the public who reside nearby. Process safety in a refinery involves preventing leaks, spills, equipment malfunctions, over-pressures, excessive temperatures, corrosion, metal fatigue and other similar conditions. Process safety programs focus on the design and engineering of facilities, hazard assessments, management of change, inspection, testing and maintenance of equipment, effective alarms, effective process control, procedures, training of personnel and human factors. The Texas City tragedy in March 2005 was a process safety accident (Fig. 1).” This underscores the need for risk managers, planners and engineers at HPI plants to put as much emphasis on providing process safety as they do on personnel safety. It naturally follows that implementing and utilizing BRECs at refineries directly impact process safety. In addition to maintaining critical process operations during and after an overpressure incident, blast-resistant equipment shelters can limit extensive downtime and prevent ever having to replace critical equipment rendered inoperable or destroyed due to the effects of a blast event. Demonstrating BREC technology. With respect to the current response to market demand for BRECs, the most important challenges are industry awareness and acceptance. Owners and engineers in the HPI and chemical industries are identifying the need for blast-rated protection of essential and critical equipment, especially in light of recent refinery overpressure incidents such as those cited here and in the January 2011 article. The precedent and need for BRECs are without argument, and this formed the basis of an extensive research and development program that established three specific equipment-center construction types—two being of interlocking steel-panel construction and the third utilizing fully welded, crimped steel plate. Now a verifiable revolution in the industry, the use of interlocking steelpanel construction for BRECs addresses both cost-effectiveness and critical-protection factors. First considerations. As discussed previously, the most desir-

FIG. 1

78

The Texas City tragedy in March 2005 was a process safety accident. Source: Chemical Safety Board.

I MARCH 2011 HydrocarbonProcessing.com

able location for electrical equipment centers at HPI plants is as close to the processing operation and maintenance personnel as

PLANT SAFETY possible. Therefore, in establishing baseline criteria for BREC performance and system design, the first step taken is typically a siting analysis. Siting analyses. Site maps of refining facilities containing concentric rings that depict various explosive potential levels are used in required siting analyses. The rings indicate overpressure levels in psi, with the higher pressures appearing at the potential blast sources or positions between blast potentials. Blast sources and reflective convergences appear in much the same manner as do the peaks on a topographical map. The site map of the Texas City refinery is shown in Fig. 2. Standoff distances. The best way to protect a building from blast loads is to ensure that it is kept as far from the blast load origin as possible. By contrast, the structures that shelter equipment required to maintain essential or critical systems are often required to be inside the potential blast zone. Close proximity for equipment is also often a function of cost due to power losses and equipment derating, as well as the heavy power cables connected to the equipment. Blast loads. The load on a structure from a nearby explosion

takes the form of an almost instantaneous pressure increase to a maximum value, followed by a brief period during which the pressure decays back to its ambient value. Pressures are measured in psi and kPa. A free-field blast load is the measurement of a blast pressure that radiates equally in all directions with no reflections. The sideon pressure is equivalent to the unreflected wave pressure at the point where it reaches the structure. This is the “rating” pressure used to map the site and to position the blast-rated structures. A free-field blast is the usual result of a vapor-cloud explosion (VCE). The pressure wave generated by the VCE impacts the structure on the facing wall, creating a peak reflected pressure due to the Doppler effect (change in the observed frequency of a wave) of the pressure reflecting off the structure’s wall. Blast pressure effects. The VCE experienced during the

Texas City incident in 2005 produced a 2.49-psi (17.2-kPa) free-field blast, which, in turn, produced an equivalent side-on pressure. This pressure level was sufficient to destroy construction trailers positioned within the blast zone, and, in fact, trailers

BONUSREPORT

nearly 1,000 feet from the blast-area center sustained damage to varying degrees. Table 1 describes three levels of blast pressure damage on buildings in HPI facilities subject to blast loads. As information, the terms damage level and response level are often used interchangeably, as shown in Table 2. Optimal blast-resistance and affordability. Recently,

a highly advanced team of designers and engineering managers with decades of experience in blast-resistant structures made a decision that is significantly impacting the HPI: A thorough research, analysis and testing program would be undertaken to rate the performance limits of existing electrical equipment center designs. It was also understood that test results would, at the same time, provide needed feedback leading to improvements in blast-resistant structure construction, and also determine the best possible material and design technology combinations for the most advanced equipment shelters. Analysis phase: complete BREC and components.

Computer analysis began, using a single-degree-of-freedom (SDOF) approach, analyzing the maximum BREC component response at various blast loadings. The SDOF approach was used to determine the blast-load capacities for various pressure-impulse (P-i) combinations. P-i diagrams (Fig. 3) are commonly used in protective-structure preliminary designs to establish safe response limits for given blast-loading scenarios. Considered here was the potential peak pressure experienced by wall panels in the blast-facing wall. The impulse was the blast duration in milliseconds times the peak pressure in psi (or kPa). This value is measured in psi-msec. TABLE 1. Building damage level/response level descriptions Building damage level

Component consequence

1 (low)

Localized building damage. Building can be used; however, repairs are required to restore structural-integrity envelope. Total repair cost is moderate.

2 (medium)

Widespread building damage. Building cannot be used until repaired. Total repair cost is significant.

3 (high)

Building has lost structural integrity and may collapse due to environmental conditions (i.e., wind, snow, rain). Total repair cost approaches building replacement cost.

TABLE 2. Component response levels and deflection range

FIG. 2

Site map of the Texas City, Texas blast-zone, showing areas of greatest over-pressure.

Component

Stiffened wall and roof panels

Damage level 1 (low)

Less than 2.1 in. Onset of visible damage; component can be repaired.

Damage level 2 (medium)

2.1 in. to 4.2 in. Permanent deformation of components requiring replacement.

Damage level 3 (high)

4.2 in. to 8.4 in. Substantial plastic deformation approaching incipient collapse. Replacement is required. Component failure is possible, although not probable. HYDROCARBON PROCESSING MARCH 2011

I 79

BONUSREPORT

PLANT SAFETY

TABLE 3. Shock tube test results

Specimen Test

Peak applied test pressure Screw size 1.2 (psi)

Panel type

Equivalent right triangular peak pressure (psi)

A

1A

16 in. wide, 3 in. deep, 16Ga G90

#10

0.9

0.8

A

1B

16 in. wide, 3 in. deep, 16Ga G90

#10

2.8

B

1B

12 in. wide, 4 in. deep, 12Ga G90

#10

3.4

B

2B

12 in. wide, 4 in. deep, 12Ga G90

#10

B

3B

12 in. wide, 4 in. deep, 12Ga G90

C

1C

C

2C

D D E

26

58

None visible

Low

2.4

97

2.6

167

69

5.5

High

98

0.75

5.3

4.3

Low

213

80

1.5

#10

6.8

Low

5.4

290

85

4

Medium

12 in. wide, 4 in. deep, 11Ga G90

.25 in.

12 in. wide, 4 in. deep, 11Ga G90

.25 in.

7.6

5.9

314

83

2

Low

8.5

6.2

462

109

4

Medium

1D

.25 in. crimped plate

N/A

2D

.25 in. crimped plate

N/A

6.8

5

277

81

2.5

Medium

12

8.7

755

126

7

High

1E

3 equipmet n doors

N/A

4.4

4

114

52

N/A

Doors remained attached

5 4 3 2 1 0 0

50

FIG. 3

Peak applied Peak dynamic impulse Duration deflection Observed (psi-ms) (ms) (in.) damage level

100

150

200

250

300

350

400

450

500

Side-on pressure-impulse diagram for 2.7-mm wall panels.

Using the SDOF approach, engineers conducted a series of single-panel evaluations on a 3-m-long, 81-cm-wide steel wall panel section at the maximum deflection point; the measured results were critical in modeling the BREC using FEA. An entire BREC structure half-symmetry model (Fig. 4) was also used, and it measured the walls’ blast resistance and integrity, as well as the global response of the entire structure. Although the front wall must resist the reflected load, the side-wall panels also play an important role; they are essential in the transfer of the roof loads to the foundation. Both the roof and ceiling were modeled as double-panel systems as described for the wall, and material properties were identical to those used in the analyses validation phase. The reflected load, as tested, used a peak pressure of 36.5 kPa (5.29 psi) at 200 milliseconds applied to the exterior panel of the front wall. The side wall, back wall and roof were subjected to side-on pressures, with a time lag included to the back wall in the analysis to effectively capture the blast wave surrounding the building. The highest stresses tended to occur at either the panel mid-span or at its end connections with the roof and base steel. Testing and recording results for these FEA building models effectively completed the computer analysis phase. Physical test specimen preparation. Subsequent to the

FIG. 4

Half-symmetry building model.

The complete electrical equipment center as an assembly was also evaluated using finite-element analysis (FEA). Using FEA, a BREC computer model was generated to verify resistance to a 2.5-psi blast load at 200 milliseconds (equivalent to the destructive Texas City blast load). Validations were performed to compare the FEA results to the SDOF model’s results and verify the SDOF calculations. 80

I MARCH 2011 HydrocarbonProcessing.com

engineering team’s completion of the SDOF and FEA phases, a risk consulting company was contracted to evaluate a series of wall panel units by subjecting them to actual physical blast pressures using a powerful device known as a shock tube. It may be said that the shock tube is to blast-resistant design research and testing what actual wind-tunnel testing is to the aeronautical and automotive industries. Fifteen tests were conducted on six different wall panel designs using seven different wall specimens and combinations of 16-, 12- and 11-gauge steel. Multiple units were built for the 16-in. wide by 3-in.-deep, 12-gauge G90 wall panel, and single specimens were provided for the five remaining panel designs. Three equipment access doors using three different gauges (14, 16 and 18) and construction methods were installed on one panel to test their performance limits. Test specimen construction. The physical test phase involved the wall, roof and floor systems, and equipment doors. Cross-section drawings of the floor, wall and roof systems are

PLANT SAFETY

BONUSREPORT

TABLE 4. Effective side-on pressure ratings Specimen/ Construction type

Panel type

Low response limiting applied load (psi, psi-msec)

Low response limiting side-on load (psi, psi-msec)

Medium response limiting applied load (psi, psi-msec)

Medium response limiting side-on load (psi, psi-msec)

High response limiting applied load (psi, psi-msec)

High response limiting side-on load (psi, psi-msec)

A/Type I

16 in. wide, 3 in. deep, 16 Ga G90

0.8, 26

0.4, 13

—

—

2.4, 97

1.2, 47

B/Type II

12 in. wide, 4 in. deep, 12 Ga G90

4.3, 213

2.0, 101

5.4, 290

2.5, 136

—

—

C/Type II

12 in. wide, 4 in. deep, 11 Ga G90

5.9, 314

2.8, 147

6.2, 462

2.9, 215

—

—

D/Type III

.25 in. crimped plate

—

—

5.0, 277

2.4, 131

8.7, 755

4.0, 344

E/Type I, II

3 equipment doors

—

—

—

—

4.0, 114

1.9, 54

shown in Figs. 5 and 6. Included in the analyses and testing was an optional inner wall comprising a series of 50-mm studs with a 1.2-mm steel liner panel. Other options for equipment support include unistruts and structural tube steel. The ceiling has a setup similar to the walls, but without the insulation and inner-liner panel. The floor system consists of 6.3- to 9.5-mm metal plate fastened above various hot-rolled steel beams and angles. Wall panels used in the analysis and testing were modeled as ASTM A36 steel. It should be noted that BRECs are actually constructed of A653CQ Grade 38 steel; therefore, the material cited in the analyses is on the conservative side. Most panels were wall panels of interlocking steel construction (Figs. 5 and 7); one panel was constructed to validate 6.3-mm seam-welded, crimped-plate (SWCP) construction (Figs. 6 and 8). Test procedure. Actual structural-system physical response to simulated blast loads was the next step. Full-scale blast tests were conducted by subjecting complete wall/roof sections and equipment doors to known, controlled blast pressures. Actual pressures of up to 8 psi were applied. The physical test program served a dual purpose: • To evaluate each wall panel unit under three blast loadings: near the low-damage level threshold, near the medium-damage level threshold, and at or near the specimen failure limit, and to follow up with documented test results. • To provide a basis for comparison to SDOF and FEA analyses validations, thereby allowing for a computer modeling and blast-load analysis program of this nature to serve as the sole criterion for blast-resistant electrical equipment center testing. The risk consultant designed its shock tube to provide an applied blast load to a structural specimen without the use of explosives. A significant advantage of the shock tube over open-air blast testing with high explosives is its ability to deliver long-duration blast loads typical of industrial explosions without requiring explosives or the use of an open-land area. To simulate the blast pressure of a free-field VCE, the shock tube applied pressure to the test panel. The tests were conducted on 3-m by 3-m wall and roof sections. Each test section was fixed to the shock tube front where a controlled release of pressurized air impacts the wall surface. The test samples were subjected to increasing blast pressures for varying duration and impulse levels. Tests were gauged to precipitate low-, mediumor high-damage responses. Component damage response levels (Table 3) follow the same pattern as the building-level responses. The test panel configurations represent those used in current BREC designs.

Interior wall

3 in.

Exterior interlocking wall panels FIG. 5

3 in. fiberglass insulation

Typical interlocking wall panel section.

2 in. x 1 in. formed channel Interior panel 1 in. – 4 in.

21⁄8 in. 315⁄16 in.

3 in.

45° 3 in. fiberglass insulation Exterior crimped plate wall panels FIG. 6

43⁄8 in. 7 in.

10 in.

Typical crimped plate, seam-welded wall section.

Panel damage level. Support rotations were also used in

determining the panel damage/response levels. The maximum dynamic deflection of each component was calculated providing the ranges used in the three damage/response levels shown in Table 2. Each component was also analyzed for various P-i combinations to determine an overall P-i diagram for the entire BREC in terms of building-response level. The building-response level definitions are provided in Table 2. Results for the FEA model, using 12-gauge wall and roof panels, are also indexed in Table 2 for side-on or free-field blast loads. Test configurations and results are shown in Table 3. The test results establish effective side-on pressure ratings for the tested panel configurations. Table 4 shows the side-on ratings for each BREC construction type, as well. Based on the actual test results, it can be confidently stated that an interlocking-panel design can be used to resist blasts up to 4 psi in side-on pressure. It was also learned that the screw type and spacing are critical. Thirdly, equipment doors, such as the ones built for this testing program, can be used. The primary differences between the standard equipment center and a BREC using construction types I or II are the gauge HYDROCARBON PROCESSING MARCH 2011

I 81

BONUSREPORT

PLANT SAFETY

and amount of material, screw spacing, door construction and equipment door configuration. A key difference in a BREC layout is the addition of a deflection space between the outer blast wall and any interior equipment supports or interior walls. For pressures above 1.0 psi, the use of special blast-rated doors and HVAC units with blast dampers is required. It is also assumed that these designs will be installed on foundations adequate to support the structures and anchor systems effective in holding the BRECs in place during a blast event. With this in mind, power and control cables can be configured to enter the structure through penetration points, preferably in the floor. Penetration points for power cables and wiring should be sealed using glands or other readily available cable sealing systems. Wrapping it all up. With a vast amount of design and build experience using both interlocking-panel and welded-steel construction in blast-resistant equipment centers, an expert team of engineers has developed computer-based blast-loading and damage profiles. Its ambitious program of evaluations began with SDOF analyses for wall and door components. The team then developed computer models of both a complete and halfsymmetry building, using FEA. The purpose was to further evaluate and verify the SDOF calculations that showed the limits of blast loadings on the wall panels and other BREC components. Armed with the results of these analyses, actual physical test specimens were prepared using 12-gauge steel sections, after which a battery of physical blast load testing regimes was run on built-up steel-wall and door components. Team members then compared the results of the physical tests with those of their computer analyses. After they developed a strong correlation between the analyses with the results of the shock tube testing,

FIG. 7

Interior and exterior wall panels used in physical test phase.

they were able to conclude that a proper program of computer analyses can be used to accurately predict equipment-center response to known blast loads. That knowledge and testing have effectively extended BREC performance limits from less than 0.5 psi to 4.0 psi. What this means for HPI companies is that there are now specific design and build parameters for BRECs that can be used to optimize their integration into a program of process safety at every facility. In short, the state of the industry in equipment centers now allows for the best combination of protection and cost-effectiveness. These factors, combined with the features list found in today’s BREC construction, result in benefits that can be directly translated to the client’s bottom line: low cost, weather-tight, contaminant-proof buildings that are flexible, easily retrofitted and repaired, and ductile in response to applied loads. The technology, effectiveness and availability of BRECs can provide every refinery with a higher level of safety and security for the process system. HP BIBLIOGRAPHY Cole, D., R. H. Bennett and D. Austin, “Protecting Essential Refining Operations Using Blast-Resistant Electrical Equipment Shelters,” IEEEPCIC-AN-22, 2008. “The Report of the BP US Refineries Independent Safety Review Panel,” The Baker Report, January 2007. Schmidt, J. A. and B. B. Brettmann, “Protective Structural Design: Resisting Blast Loads,” March 2002. “Management of Hazards Associated with Location of Process Plant Portable Buildings,” API RP 753, First Edition, American Petroleum Institute, Washington, D.C., June 2007. “Fatal Accident Investigation Report: Isomerization Unit Explosion—Final Report,” Texas City, Texas, incident date: March 23, 2005, report date: December 9, 2005. “Design of Blast-Resistant Buildings in Petrochemical Facilities,” American Society of Civil Engineers, Task Committee on Blast Resistant Design, New York, New York, 1997. “Single Degree of Freedom Structural Response Limits for Antiterrorism Design,” US Army Corps of Engineers Protective Design Center Technical Report PDC-TR- 06-08, October 20, 2006. Edel, M., J. Florek, K. Sriboonma and J. R. Montoya, “Blast Assessment of Modular Metal Building, final report,” BakerRisk Project No. 01-1958-00107, Baker Engineering and Risk Consultants, February 19, 2008. Montoya, J. R. and M. J. Lowak, “Blast Performance Testing of Wall Panels,” draft report, BakerRisk Project No. 01-02385-001-08, Baker Engineering and Risk Consultants, January 28, 2009.

David Cole is the vice president of corporate engineering for Lectrus Corp. His current responsibilities include product design, research and development, and code compliance for the company’s complete line of custom, walk-in metal electrical equipment enclosures. Mr. Cole also represents Lectrus on various technical and industry associations, including IEEE. He graduated from North Carolina State University with a BS degree in mechanical engineering in 1985 and from the University of Phoenix with an MBA in 1995. Mr. Cole has had a diverse career in medical R&D, computer-peripheral manufacturing, and electrical control and enclosure design.

Deron Austin is the vice president of marketing for Lectrus

FIG. 8

82

Wall panel of SWCP construction used in the physical test phase.

I MARCH 2011 HydrocarbonProcessing.com

Corp. Mr. Austin has over 20 years of experience in the sales and marketing of engineered products, and is a licensed professional engineer in the State of Tennessee. Prior to joining Lectrus in June 2008, he was employed by Propex, where he helped increase the global demand for the company’s civil engineering products. As marketing director for Lectrus, Mr. Austin is responsible for the company’s strategic marketing initiatives, marketing communication tactics, lead development, branding and new market, channel, product and service commercialization efforts. He is a member of the Institute of Electrical and Electronics Engineers and holds a BS degree in civil engineering from Bucknell University.

PLANT SAFETY

BONUSREPORT

Chemical Facility Anti-Terrorism Standard turns four: What’s next? An in-depth look at the standard R. LOUGHIN, ADT Advanced Integration, Greater Philadelphia, Pennsylvania

W

e hear it all the time—after 9/11, everything having to do with security changed. It forced us to take a second look at many things in our lives and it was natural to look at the security of our critical infrastructure including roads, waterways, airports and bridges. Of course, chemical security had to be part of that. Lawmakers wanted to make sure that companies using, making and storing chemicals were taking the steps to secure their facilities and contents. According to the Department of Homeland Security (DHS), the Chemical Facility Anti-Terrorism Standard (CFATS) was created in 2006 to establish security standards for facilities considered to be at high risk. CFATS defines security requirements based on a list of about 323 chemicals, called chemicals of interest (COI). CFATS does not just affect the chemical or petrochemical industries. It also includes sectors such as chemical manufacturing, storage and distribution, energy and utilities, agriculture and food, paints and coatings, explosives, mining, electronics, plastics universities, and healthcare facilities. At this time, CFATS does not apply to facilities under the jurisdiction of the Maritime Transportation Security Act (MTSA), facilities owned or operated by the US Department of Defense or those regulated by the Nuclear Regulatory Commission. Public water systems and wastewater treatment facilities currently fall under the US Environmental Protection Agency (EPA) regulations. The DHS set thresholds for each of the COIs. The facilities that use or store chemicals above those thresholds were required to submit a “top screen” to the department. So far, the DHS has indicated that about 32,000 facilities submitted top screens. Of those, about 7,000 were notified that they were required to move to the second step—

a Security Vulnerability Assessment (SVA). Facilities were placed into categories after the top screen analyzed the type, quantity, storage, manufacturing and handling of each COI. The SVA then took a more in-depth look at each facility and its existing security and vulnerabilities to come up with a final ranking based on four tiers. Facilities with the highest level of COIs and vulnerability combined, were placed into Tier 1. Those with the lowest levels of chemicals and threats were put into Tier 4. The DHS considers its criteria for tier rankings to be classified and does not disclose what elements make a facility a tier one. The rankings appear to be based on a combination of factors from the top screen to SVA submissions. Characteristics obviously change from site to site, but tier ratings appear to be based on a combination of COI type and amount, proximity to a population center and the recognition of the COI by the general public. CFATS is a risked-based mandate. At the heart of it are 18 published Risk-Based Performance Standards (RBPSs) and each tier has a specific level of security within those standards to be met. The DHS does not mandate specific technologies and procedures for facilities. Instead, it sets security goals based on a number of factors and the facilities are given the flexibility to develop their own processes and solutions. This allows for the vast differences in facilities. You might think that the larger the facility the higher the risk level, but often that is not the case. For example, a large facility may have perimeter and access security in place that makes it very secure. A small facility, like a university research center, probably does not have the ability to put in place the same perimeter security, so it has to take extra precautions to make sure access to certain chemicals is limited to very few authorized people.

After a company or facility gets its final tier assignment from the DHS, it has 120 days to develop a site security plan (SSP) using the 18 RBPSs as guidelines. This means laying out a comprehensive plan that takes into account the facility’s tier level. For example, the first RBPS addresses perimeter security. The expected security level for a Tier 1 facility is going to be much higher than a Tier 3 or Tier 4. Putting together an SSP takes a team approach. It cannot fall to one person in the facility. The RBPS mandate covers a wide range of areas including personnel, security, safety, compliance and legal issues. All of these departments need to have a seat at the table in putting together this type of plan. After the SSP is submitted, it is reviewed by the DHS and then implemented by the company. The final step is an authorization inspection by the DHS. This inspection usually takes about a week as the DHS examines the entire plan and looks at it, not only on paper but also in practice. So what is the real reason for the CFATS mandate? What are the concerns and what is the DHS looking to secure? The specific concerns about chemical production, use and storage fall into three main categories: • Release of dangerous chemicals • Theft and diversion of chemicals • Sabotage or contamination. The release of dangerous chemicals and the threat this poses to the health and safety of the surrounding public is pretty obvious. Toxic, flammable or explosive chemicals can be very dangerous and cause extensive damage to people and property. Release is a matter of keeping unwanted people out of your facility and screening your personnel to make sure that they are who they appear to be. Theft and diversion gets a little murkier. Here we are talking about stealing chemicals to create chemical weapons including HYDROCARBON PROCESSING MARCH 2011

I 83

BONUSREPORT

PLANT SAFETY

homemade bombs, explosives, gas bombs and improvised explosive devices (IEDs). Again, stealing is pretty straightforward and that threat affects almost all CFATS facilities. Both big and small facilities have to protect their chemical inventory and assets against someone going in and taking them. Diversion is a different story. Chemicals can be stolen at the facility or in route, but chemicals can also be diverted in a number of different ways. According to the DHS, diversion is the criminal act of acquiring a product (or service) by means of deception. Deception can include purchasing or paying for chemicals. The crime here is the acquisition of the chemicals even if they are purchased. Diversion includes the following tactics: Hijacking—Placing an order that puts the goods in motion and then stealing them in route. Dummy company—Setting up a fake company and placing an order. Once the order is delivered, the company disappears. Breakout scheme—Variation of a dummy company, but a real company is purchased, usually on credit, and orders are placed through that company. The company operates until the credit runs out. Co-opted customer—An existing customer is co-opted by a terrorist group and is either coerced, infiltrated or bribed into ordering materials. False flag—Terrorists place an order as an existing customer but steal the goods once they are delivered or the order is sent to a new false address. Pretext purchase—For example, someone pretending to be a professor at a university or college chemistry department places an order. Cyber attack on business management system—The network or computer system is hacked into and a reoccurring delivery is scheduled and hidden. Sabotage or contamination of materials is another concern driving the CFATS mandate. Chemicals that release toxic gases when exposed to water, fall into this category. So businesses have to not only be concerned about someone stealing or taking COIs out of the facility, but they must also be very concerned with what is coming into those facilities. All of these scenarios have to be addressed in a facility’s SSP and security measures must be put into place to limit the possibility of these situations happening. It takes a careful review of your facility and its business processes, along with knowledge of the security options available. 84

I MARCH 2011 HydrocarbonProcessing.com

CFATS just celebrated its fourth birthday. Those four years have been a learning process and, as the DHS has acknowledged, the department is learning with the industry. It has been a strong collaborative process with the usual snags and disagreements. Overall, the legislation has gotten off to a good start and is beginning to hit its stride. At this point, almost all facilities should have been given a final tier assignment and most initial inspections for Tier 1 facilities completed. The DHS has reached out to the chemical industry and is trying to work with facilities to facilitate compliance. The department started working with companies by making preauthorization inspections. These allow companies and facilities to meet with DHS inspectors to discuss what they are doing and get feedback. This seems to be a process that is working well and is giving many companies the direction and advice they need. The DHS also provides a lot of information online for facilities, as well as lists of frequently asked questions and a help line for additional assistance. The department has also initiated an open dialogue for some of the tougher issues, like personnel surety, which deals with background checks and certifications for employees, vendors and delivery people. Another area is material modification. The DHS has acknowledged that companies are constantly changing processes and the chemicals used in those processes. Handling these modifications and the impact they may have on tiering, SSPs and compliance is a difficult task. And again, in this instance, the DHS is looking to the industry for input and discussion. The biggest issue facing CFATS at this time is legislative. The initial bill expired in October 2009 and was renewed for one year. Since then, legislation has been introduced in the US Senate and the House of Representatives. In July, the Senate Homeland Security Committee voted unanimously to extend the CFATS for three years to 2013. The 13-0 bipartisan vote was for HR 2868 with an amendment from Senator Susan Collins, Republican-Maine. HR 2868 was introduced by Representative Bennie Thompson, DemocratMississippi and was passed by the House in November. That version of the bill included an inherently safer technology (IST) provision. The chemical industry is opposed to this provision because it is open to interpretation and it could be costly, especially

for smaller facilities and businesses. The Collins amendment removes this provision from the bill and adds several other elements, including: • Creating voluntary exercise and training programs • Establishing a voluntary technical assistance program • Creating a chemical facility security best practices clearing house • Establishing an advisory board to advise the DHS on implementation and the voluntary technical assistance program. In general, the industry has been very supportive of this legislation with the Collins amendment included. The National Association of Chemical Distributors (NACD), the Society of Chemical Manufacturers and Affiliates (SOCMA) and others have come out in its support. Still, the bill has to make it to the Senate floor for a vote. The chairman of the Senate Homeland Security Committee, Joseph Lieberman, I-Connecticut, has said the bill will need significant modifications to get through the Senate. Some senators have already said that they will make an effort to reintroduce an IST-type provision in the bill. With a shift after the November elections in the makeup of both the House and, to a lesser extent, the Senate, CFATS did not get much attention at the end of last year. The program will continue for another year through a rider on the DHS appropriations bill. This will allow facilities that use, store and process chemicals to continue their current work with the DHS. We may see a different approach to CFATS with a new Congress. But, as Sue Armstrong of the DHS recently reminded everyone at a security conference, terrorism is a real threat that we all need to take seriously. The CFATS mandate is not meant to be an additional burden to business, but to ensure that we are protecting our communities and our businesses. HP

Ryan Loughin is the director of Petrochemical and Energy Solutions for the Advanced Integration division of ADT (www.adtbusiness.com/petrochem). He provides security education to CFATS and MTSA-affected companies and is a member of the National Petrochemical and Refiners Association (NPRA), Society of Chemical Manufacturers and Associates (SOCMA), American Chemistry Council (ACC), the Energy Security Council (ESC) and the American Society for Industrial Security (ASIS). Mr. Loughin has also completed multiple levels of Chemical-Terrorism Vulnerability Information (CVI) which was authored by the US Department of Homeland Security.

INSTRUMENTATION

Avoid these top-10 instrumentation headaches Visual engineering program solves designer and engineer issues across the industry D. GIBSON, AVEVA, Cambridge, England

C

ontrol systems play a vital role in all aspects of modern living, from helping us drive our cars, to safely running large petrochemical complexes and power stations. According to recent industry research, instrumentation is the biggest spend item in plants. In 2010, capital expenditure for buying new instruments was estimated at $5 billion, with maintenance and operation costs projected to reach $4.9 billion. However, much of this cost is unnecessary. It arises because the technology used to plan and design instrumentation and control systems has often been developed with little regard for engineers’ and designers’ natural working methods. Procedures that can be perfectly straightforward if represented graphically— rerouting a wire, for example, or segregating cables—are all too often dependent on manual, tabular data input, which is timeconsuming, expensive and prone to error. Instrumentation and control experts were interviewed across the industry, and they identified no less than 10 key areas where instrumentation design technologies fail to meet engineers’ and designers’ requirements. These are the top-10 headaches that the engineers and designers face on a daily basis. The good news is that companies can avoid these headaches entirely by deploying the “visual engineering” approach—a field-proven instrumentation solution.

most instrumentation software systems currently work. For too long, software vendors have denied engineers and designers the simple practicality of a graphical visual engineering interface with “drag and drop” capability and inbuilt intelligence, ensuring changes are automatically replicated into all the associated data and databases. All too often, the time taken to learn the currently available systems is prohibitive. Configuring them is a major specialist undertaking, and their operation constrains engineers to work in ways that are counter-intuitive and labor-intensive. Wasted time and money, and lost productivity, are the results. This new program delivers simplicity, to fit closely with the way that engineers

and designers naturally work. As an example, Fig. 1 shows how a simple graphical user interface in a wiring manager module enables the user to route and reroute wiring—and manage all associated changes— in a few clicks of the mouse. Straightforward customization enables configuration by users without any need for programming skills. In short, this is a complete change to the way in which instrumentation and control data is created and edited, and it has led to design savings of 30% and more among current users. Simplicity of use equates to less need for configuration and training, reduced administration and support overheads, and a design and engineering team whose time to productivity is greatly reduced. The

TOP-10 HEADACHES No. 1.—Wasted time and lost productivity. Engineers and designers are

highly skilled individuals. Forcing them to enter design changes using tables, forms and spreadsheets is unproductive and uneconomical, and it increases the likelihood of human error—this is the way that

FIG. 1

A straightforward, graphical approach, combined with drag-and-drop functionality, enables wiring projects to be designed and change-managed in the simplest way possible. HYDROCARBON PROCESSING MARCH 2011

I 85

INSTRUMENTATION graphical views are role-based, so each user sees and interacts with those elements that are of most use to them. No. 2.—Lack of change management. While the creation of data is abso-

lutely key to the early momentum of a project, the ongoing challenge is in managing changes to the design and ensuring that the changes are properly reflected throughout the dataset. Often, more cables and connections are added to the plan than were originally envisaged, swelling the data considerably and producing a significantly altered design. This complicates the relationships between existing and new information, forcing a time-consuming and costly estimate revision process. The instrumentation program comprises three integrated modules that share a common, multi-user database for both design and as-built data. This integrated data environment enables extensive validation processes, automatic cross-referencing and linking of associated information, and rigorous change control. Change of all kinds can be easily tracked, highlighted and reported on, and its impact automatically flagged (Fig. 2). No. 3.—Wiring limitations. Wiring

design is a multi-phase process, involving loop diagrams, schedules and terminations—yet many technologies currently available on the market are unable to integrate these procedures into one applica-

tion. The wiring designer has to coordinate design data manually between several different applications—an open invitation to error, as well as a seriously inefficient use of a technically skilled individual’s time. To make things worse, input of data into the wiring design is usually via table and spreadsheet—there is no means of visualizing the relationships and using those visualizations as the logical starting point for the creation and editing of the wiring design. This instrumentation program, by contrast, requires only one click to enable the user to see a current graphical representation (Fig. 3). There is no need to request an output plot from a designer, which can take many hours of unnecessary work. Within a single application, loop diagrams, schedules and terminations can all be created and edited from the same visual engineering environment. No. 4.—Catalog of errors. Catalog changes are one of the biggest causes of design data mismatches in the instrumentation and control universe. Yet they are often an essential way of managing and reducing procurement costs, and so can heavily influence the economic viability of a project. For example, the purchasing department might decide on a different supplier for a particular component, causing a change in the nomenclature of that component and the associated vendor details. The problem comes when these changes are not

accurately reflected across the whole project—which they rarely are. This can necessitate massive rework later in the process. The instrumentation program provides dynamic catalog management as standard. Vendor details and component references can be changed any time throughout the project with no need for manual rework. If a pressure gauge supplied by vendor X is changed in the catalog to a similar product from vendor Y, identified by a different part or tag number, these changes will be updated (or will simply show where updates need to be made). This happens automatically across all mentions and instances of the original gauge—in cable block diagrams, loop diagrams, instrument indexes, datasheets, hookup diagrams, termination diagrams, cable schedules, bill of materials, etc. Mismatches between catalogue data and project execution data, as well as the many expensive hours needed to rectify them, are a thing of the past. No. 5.—Lack of visualization and reporting clarity. The ability to report

on a design at will is fundamental both to progress management and design quality control. Yet with many software packages, reports can only be generated by the use of programming scripts that have to be specially requested and produced—an unnecessary overhead in time and labor. There is no easy way, in most of the instrumentation software currently available on the market, to quickly build up a picture of the interrelationships in the project dataset. Likewise, no other vendor currently enables instant reporting on the database revisions to give an understanding of change history. This instrumentation program is built around user-defined reporting—across schedules, lists, bill of materials, and other data. The simple interface puts the reporting process back into the engineer’s hands and enables all items, data and documents that share the same tag to be instantly listed. This graphically shows how changes to one item might have impacts elsewhere in the design. A full audit log of database changes can also be instantly generated—vital for root-cause analysis and risk management. No. 6.—Scalability price. Database

FIG. 2

86

Information is fully auditable and reportable, enabling change to be effectively and safely managed.

I MARCH 2011 HydrocarbonProcessing.com

technology is key to effective instrumentation design—the application’s scalability is directly related to the efficiency of the database. Unfortunately, some vendors have taken excessive advantage of this dependency. While their application upgrades are usually delivered at no further cost, the

INSTRUMENTATION upgrades to the database that underpins them are often an expensive service. This means that ongoing support and scalability can only be achieved at a very high cost— the exact opposite of what flexible scalability should deliver.

ments with customers’ existing third-party applications and data types. The company does not force users to

work with multiple applications that are not integrated. Instead, it enables the creation of datasheet templates within the

No. 7.—Vendor data breakdown.

Like all engineering processes, instrumentation and control are dependent on components provided by a range of suppliers. Approaching vendors for datasheets on the components they provide is often a hit-andmiss process—the information returned can be incomplete and is typically supplied in a number of disparate formats/file types. Designing a prescribed template for the datasheets is not nearly as effective as it might be, as it usually has to be carried out in an unintegrated, third-party application. This, in turn, means that the responses have to be manually received and administrated, manually followed up when necessary, and manually linked to the data in the main design system. Any two or more individuals, equally skilled and experienced, will inevitably perform this task very differently, leading to mismatches and inconsistencies. Needless to say, these manual processes are also time-consuming and expensive—not what a project manager wants to hear. No. 8.—Inability to view instrumentation data in 3D. In many

instrumentation and control technologies, there is no integration of the data with the 3D model of the plant. This makes it difficult for engineers and designers to make judgements on spacing, tolerances, buffer zones, clashes and so forth, as well as on quantities and dimensions. For example, cables come in many different types and need to be routed in a way that effectively segregates them by voltage, function, flux, heat dissipation, etc., while economizing on the cable length. This combined requirement is virtually impossible to meet if the user cannot visually model the deployment. This program works with industry-standard Microsoft databases such as SQL Server and (for smaller projects) MS Access. Updates to both the application and the databases are received as a normal part of the licensing process. There is no additional cost. The emphasis is on protecting a customer’s investment in data, rather than exploiting it. There is no charge for updates and upgrades with customers on an active maintenance contract, and it has also made massive investments to ensure that the technology works in mixed IT environ-

FIG. 3

The reporting capability is powerful and flexible, producing instant results on screen, as well as in print-friendly format.

Asset Longevity Plant & Pipeline Performance

Quest Integrity Group is a dynamic company built on a foundation of leading edge science and technology that has innovated and shaped industries for nearly 40 years. Our asset integrity and reliability management solutions are comprised of technology-enabled advanced inspection and engineering assessment services and products that help companies in the refining and chemical, pipeline, syngas and power industries increase profitability, reduce operational and safety risks and improve operational planning. (888) 557-3363 (888) 893-7030 www.QuestIntegrity.com [email protected]

Select 164 at www.HydrocarbonProcessing.com/RS

87

INSTRUMENTATION application itself, in a way that is totally integrated with the rest of the project workflow. These templates can be partially populated by the engineer or designer with information that is already known. This gives vendors a much clearer indication of what information is needed, making their task easier and increasing the likelihood that the datasheet will be completed to the required standard. The content of the datasheet is easily searchable and reportable. It can be extracted and viewed in seconds, rather than having valuable minutes and hours wasted in attempts to search for it. 3D models are fully integrated with other providers to enable instrumentation data to be viewed in full 3D context. This means that cable data can be integrated into the 3D model straight from the instrumentation program and automated cable measurement, routing and segregation can then be generated instantaneously. Greater control, less rework and enhanced safety and compliance, without risky and time-consuming guesswork, can save millions of dollars in design time and material procurement. No. 9.—Incomplete associations.

Instruments and wiring activities gener-

ate a huge amount of related information including data sheets, documents, etc. Many isolated systems completely fail to link this information together, as it typically comes from both internal and external sources. Engineers and designers, therefore, have to second guess both the nature of the information and its location. Apart from being terrifically time consuming, this also perpetuates the problem of “unknown unknowns” and this is clearly an unsatisfactory basis for making informed design and engineering decisions. The problem is often at its most acute with external documents such as vendor datasheets. With internal documents, the designer or engineer can bring pressure to bear on the situation; he is organizationally connected to the document producers and is regarded internally as a key customer. With external documents, this dynamic is less relational—and so designers or engineers need a different way of bringing authority to their requests for information. The instrumentation program provides object-based navigation through hyperlinks. Related items of data are linked together automatically, no matter what format they are in or where they are physically

The Fundamentals of Piping Design By Peter Smith 262 pages t
Hardcover t
Pub date: April 2007 t
Price: $175 ISBN: 978-1-933762-043 Written for the piping engineer and designer in the field, this first part of the two-part series helps to fill a void in piping literature, since the Rip Weaver books of the ‘90s were taken out of print.

Advanced Piping Design By Rutger Botermans and Peter Smith 250 pages t Hardcover t
Pub date: May 2008 t
Price: $175 ISBN: 978-1-933762-18-0 An intermediate-level handbook covering guidelines and procedures on process plants and interconnecting piping systems.

The Planning Guide to Piping Design By Richard Beale, Paul Bowers and Peter Smith 300 pages t Hardcover t Pub date: September 2010 t Price: $175 ISBN: 978-1-933762-37-1 The Planning Guide to Piping Design covers the entire process of planning a plant model project from conceptual to mechanical completion, and explains where the piping lead falls in the process along with his roles and responsibilities.

To place an order, visit www.gulfpub.com or call +1 (713) 520-4426. 88

I MARCH 2011 HydrocarbonProcessing.com

located. In a single click, an engineer or designer can view the object and see exactly where all the information that relates to a specific component or design element resides. This reduces not only the direct costs of manually searching for information (estimated in recent studies to take up as much as 60% of an engineer’s time), but also the less obvious expense, such as when the designer or engineer approaches a colleague to help him find information, thus wasting two people’s time instead of one! The majority of safety related incidents have also ultimately been related to poor information accessibility, so the ability to diminish this risk substantially is a big part of the benefit that this program brings. No. 10.—Fragmented bulk data upload. The ability to bulk-upload data at

the beginning of a project is key to achieving initial traction. However, the data typically comes from many different sources and in many different formats, and this fragmentation often necessitates the use of several different applications. Piping and instrumentation diagrams (P&IDs), for example, are an absolutely integral part of the instrumentation and control design process, but they are often not an integral part of the data upload, having to be sourced and integrated independently. This reliance on a multi-application approach consumes time, effort and money, and increases the likelihood that critical data will be missed or incompletely captured. The program enables complete integration of all data types, including P&IDs. An initial bulk upload creates links and associations between these different types of information. The project benefits from much more rapid traction and the engineers and designers have all the information at their fingertips in a way that is dynamically managed and updated across the life of the project. HP

David JS Gibson is the head of product strategy for instrumentation and electrical systems for AVEVA. He joined AVEVA business development in December 1999 after serving 25 years working for a major engineering, production and construction company, formally in the engineering design and then as development project manager for engineering data management systems. He has worked on a variety of engineering projects for various clients in the oil and gas and pharmaceutical industries. Projects covered a wide range of processes for oil and gas, pharmaceutical, chemicals and polymers and food processing, and he has had experience in all aspects of engineering design. Mr. Gibson attained his management qualifications from the Open University.

ENGINEERING CASE HISTORIES

Case 61: Pressure loss in a reactor Much information is available from a simple analysis T. SOFRONAS, Consulting Engineer, Houston, Texas

T

here are times in one’s career when a quick decision is needed so a design will proceed in the correct direction. This may be in a design review meeting where different views are being presented on a systems modification.

Case history. In this example, the drawings for a pilot reactor were being reviewed. The design had been modified from an originally proposed rounded-head design, which had been feared to create a “dead space.” It now included a flat plate to eliminate the “dead space” in the reactor head so that fouling would not occur in that region. Fig. 1 illustrates a simplified view of the reactor. Since the design with the plate looked problematic, a simple analysis was done, which showed that a large pressure drop would occur with this modification. In the proposed flat-head design, the curved head volume had been reduced to a 1–in. gap flow. The resulting additional pressure drop would have caused the axial-flow propeller pump to exceed its horsepower rating. Therefore, the proposed flat-head design was not used, and the original large-volume head was successfully implemented. Recheck the decision. At a later date, a detailed analysis was performed that verified the simple analysis. Computational fluid dynamics (CFD) is an analysis tool that can analyze laminar and turbulent flows. While three-dimensional analyses with swirl are possible, a simple twodimensional analysis is applied here to add information not available from the analytical analysis. Three reactor tubes, much like heat exchanger tubes, are shown in addition to the central tube. Fig. 2 illustrates the flow velocity from an axis-symmetric model, starting at the pump discharge with the flat plate and 1-in. gap. The simplification is that the three tubes are really concentric channels with the same flow area as the corresponding tubes.

This simple CFD model produces interesting results. In Fig. 2, the velocity is going up the reactor main tube (15 ft/sec) and distribution to the three coolant tubes is very high in the 1-in. gap (c) region (red). It is high in the outer tube and low in the inner tube (blue). Fig. 3 shows the redistribution with a 3-in. gap. With the curved head and a larger gap, the flow was more evenly distributed, and the pressure drop from the main tube to the tube outlets was low. The 1-in. gap would not only have raised the horsepower requirement of the axial flow pump but would also have resulted in uneven cooling from the tubes and raised the potential for frequent fouling. Proving decisions. This is an example

where a sophisticated analysis tool, used on a simple 2D model, can produce useful results. The 2D models can be a real benefit in developing a 3D model for scale-up of

the production reactor. This would allow evaluating parameters that could increase production. HP

FIG. 2

Velocity in reactor 1-in. gap.

FIG. 3

Velocity in reactor 3-in. gap.

Dead space Head C Flow up D

Main tube

Dr. Anthony (Tony) Sofron a s , PE, was worldwide lead Pump

FIG. 1

Reactor flow with head installed.

mechanical engineer for ExxonMobil before his retirement. Information on his books, seminars and consulting, as well as comments to this article, are available at http:// mechanicalengineeringhelp.com. HYDROCARBON PROCESSING MARCH 2011

I 89

HPI MARKETPLACE

Select 201 at www.HydrocarbonProcessing.com/RS

WABASH SELLS & RENTS BOILERS & DIESEL GENERATORS FAST EMERGENCY SERVICE

800-704-2002 www.wabashpower.com Select 202 at www.HydrocarbonProcessing.com/RS

SURPLUS GAS PROCESSING/REFINING EQUIPMENT NGL/LPG PLANTS: 10 – 600 MMCFD AMINE PLANTS: 60 – 5,000 GPM SULFUR PLANTS: 10 – 1,200 TPD FRACTIONATION: 1,000 – 15,000 BPD HELIUM RECOVERY: 75 & 80 MMCFD NITROGEN REJECTION: 25 – 80 MMCFD ALSO OTHER REFINING UNITS We offer engineered surplus equipment solutions.

FAX: 847-541-1279 847-541-5600

Select 204 at www.HydrocarbonProcessing.com/RS

Select 205 at www.HydrocarbonProcessing.com/RS

Select 206 at www.HydrocarbonProcessing.com/RS

Select 207 at www.HydrocarbonProcessing.com/RS

Bexar Energy Holdings, Inc. Phone 210 342-7106 Fax 210 223-0018 www.bexarenergy.com Email: [email protected] Select 203 at www.HydrocarbonProcessing.com/RS

Call 713-520-4449 for details about

Hydrocarbon Processing’s

Recruitment Advertising Program Use a combination of print, recruitment e-newsletter, plus Website to reach our total audience circulation of more than 100,000!

90

I MARCH 2011 HydrocarbonProcessing.com

HPI MARKETPLACE 0IPE3TRESS 0ROCESS3IMULATION 0ELLETIZING$IE$ESIGN (EAT4RANSFER!NALYSIS &INITE%LEMENT!NALYSIS #OMPUTATIONAL&LUID$YNAMICS 6ESSEL%XCHANGER-ACHINE$ESIGN 2OTOR$YNAMICS3TRUCTURAL$YNAMICS 3PECIALISTSINDESIGN FAILURE ANALYSIS ANDTROUBLESHOOTINGOF STATICANDROTATINGEQUIPMENT WWWKNIGHTHAWKCOM

CA Co PE-O mp PE lian N t! HTRI Xchanger Suite® – an integrated, easy-to-use suite of tools that delivers accurate design calculations for

(OUSTON 4EXAS 4ELss &AXss

• shell-and-tube heat exchangers • jacketed-pipe heat exchangers • hairpin heat exchangers • plate-and-frame heat exchangers • spiral plate heat exchangers

Select 208 at www.HydrocarbonProcessing.com/RS

NOISE

• fired heaters • air coolers • economizers • tube layouts • vibration analysis

Interfaces with many process simulator and physical property packages either directly or via CAPE-OPEN.

CONTROL ENGINEERING

HFP Acoustical Consultants Houston TX

Calgary AB

(888) 789-9400

(888) 259-3600

(713) 789-9400

(403) 259-6600

E-mail: [email protected] Internet: www.hfpacoustical.com

Heat Transfer Research, Inc. 150 Venture Drive College Station, Texas 77845, USA Select 210 at www.HydrocarbonProcessing.com/RS

Select 209 at www.HydrocarbonProcessing.com/RS

Flexware

®

®

Turbomachinery Engineers

Flexware® Live Analysis Turbomachinery Performance Monitoring

PC Operating Flexware Live A.

B.

[email protected] www.HTRI.net

“See” Where Compressor is Operating a. Flow, Head & Efficiency vs. OEM Curve b. Surge & Choke Margin Historical Data Aids Maintenance Scheduling

www.flexwareinc.com [email protected] 1-724-527-3911

Hydrocarbon Processing seeks Process Editor Gulf Publishing Company (Houston, Texas) is seeking an editor for its industry-leading publication, Hydrocarbon Processing. The ideal candidate should have a BS degree in engineering or similar discipline and five to ten years of experience working in the HPI (refining, petrochemical/ chemical and gas processing), or extensive experience working as an editor in the refining and petrochemical industries with extensive experience with technical information. Experience in process design and/or facility maintenance is a bonus. Excellent written and verbal communication skills are mandatory, and the ability to work under tight deadlines in a sometimes high-pressure environment is required. The process editor will be responsible for researching and editing technical articles for print and website applications, monitoring trends for the HPI and maintaining a strong technical background on the latest technology innovations for the energy industry. Travel, possibly international, to attend international industry conferences and trade shows is required 2–4 times a year. Salary is competitive. Gulf Publishing Company offers an excellent work environment and benefits. Candidate must be a resident legal alien or citizen of the USA. E-mail your resume to [email protected]. No phone calls please.

Select 211 at www.HydrocarbonProcessing.com/RS HYDROCARBON PROCESSING MARCH 2011

I 91

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: [email protected] 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: [email protected]

AK, AL, AR, AZ, CA, CO, FL, GA, HI, IA, ID, IN, KS, KY, MI, MN, MS, MT, ND, NE, NM, NV, OR, SD, TN, TX, UT, WA, WI, WY, WESTERN CANADA Laura Kane 2 Greenway Plaza, Suite 1020, Houston, Texas, 77046 Phone: +1 (713) 520-4449, Fax: +1 (713) 520-4459 E-mail: [email protected]

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: [email protected]

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: [email protected]

AUSTRALIA—Perth Brian Arnold Phone: +61 (8) 9332-9839, Fax: +61 (8) 9313-6442 E-mail: [email protected]

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: [email protected] 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: [email protected] 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: [email protected]

DATA PRODUCTS AND CLASSIFIED SALES Drew Combs, Gulf Publishing Company Phone: +1 (713) 520-4409, Fax: +1 (713) 525-4631 E-mail: [email protected]

CHINA—Hong Kong Iris Yuen Phone: +86 13802701367, (China) Phone: +852 69185500, (Hong Kong) E-mail: [email protected] 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: [email protected] JAPAN—Tokyo Yoshinori Ikeda Pacific Business Inc. Phone: +81 (3) 3661-6138, Fax: +81 (3) 3661-6139 E-mail: [email protected] INDONESIA, MALAYSIA, SINGAPORE, THAILAND Peggy Thay Publicitas Singapore Pte Ltd Phone: +65 6836-2272, Fax: +65 6634-5231 E-mail: [email protected] PAKISTAN—Karachi S. E. Ahmed Intermedia Communications Karachi-74700, Pakistan Phone: +92 (21) 663-4795, Fax: +92 (21) 663-4795

REPRINTS Rhona Brown, Foster Printing Service Phone: +1 (866) 879-9144 ext. 194 E-mail: [email protected]

ARE YOU TAKING FULL ADVANTAGE OF HYDROCARBON PROCESSING?

Subscriber Only Benefits

Discover all the benefits of being a premium subscriber and gain full access to HydrocarbonProcessing.com

Twelve monthly issues in print or digital format and premium access to HydrocarbonProcessing.com, including: • All the latest issues and Process Handbooks • HP’s extensive archive containing 8 years of back issues • A subject/author index of print articles with links to articles available online • Monthly e-newsletters providing an early preview of upcoming special editorial features and exclusive content. Published since 1922, Hydrocarbon Processing provides operational and technical information to improve plant reliability, profitability, safety and end-product quality. The editors of Hydrocarbon Processing bring you first-hand knowledge on the latest advances in technologies and technical articles to help you do your job more effectively.

SUBSCRIBE TODAY! Log on to www.HydrocarbonProcessing.com or call +1 (713) 520-4440.

Subscribe online at www.HydrocarbonProcessing.com or call +1 (713) 520-4440

92

I MARCH 2011 HydrocarbonProcessing.com

As a Hydrocarbon Processing premium subscriber, you will receive full access to WorldOil.com as well as World Oil magazine in your choice of print or digital format. Start your subscription today.

FREE Product and Service Information—MARCH 2011 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 ______________________________________________________

City/State/Zip ____________________________________________________

Country ______________________________________________________

Phone No. _______________________________________________________

FAX No. ______________________________________________________

e-mail ___________________________________________________________

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 S.p.A. . . . . . . . . . . . . 19 (152) www.info.hotims.com/35901-152

Altair Strickland. . . . . . . . . . . . . T-62

(97)

www.info.hotims.com/35901-113

(55)

www.info.hotims.com/35901-55

Cashco, Inc.. . . . . . . . . . . . . . . . . 24 (155) Cooper Crouse-Hinds GmbH . . . T-56 (165) www.info.hotims.com/35901-165

(95)

(76)

(99) (59)

Silcotek . . . . . . . . . . . . . . . . . . . . 32 (157)

GPC Books . . . . . . . . . . . . . 47, 88

www.info.hotims.com/35901-157

HPI Marketplace . . . . . . . . . 90–91

Socap Srl . . . . . . . . . . . . . . . . . . . 46 (159) www.info.hotims.com/35901-159

Spraying Systems Co . . . . . . . . . . 16

Site License Program . . . . . . . . . 48 (86)

www.info.hotims.com/35901-86

(81)

www.info.hotims.com/35901-81

(79) (78)

Merichem Company . . . . . . . . . . 37 (158)

www.info.hotims.com/35901-97

(63)

www.info.hotims.com/35901-63

Team Industrial Services . . . . . . . 25

(73)

www.info.hotims.com/35901-73

Trachte USA . . . . . . . . . . . . . . . . 54 (162) www.info.hotims.com/35901-162

Unifrax . . . . . . . . . . . . . . . . . . . . 38

(68)

www.info.hotims.com/35901-68

United Laboratories International, Llc/Zyme-Flow. . . . . . . . . . . . . . 23 (154) UOP LLC . . . . . . . . . . . . . . . . . . . 48 Vega Americas, Inc. . . . . . . . . . . . 18

Neptune Research . . . . . . . . . . . . . 4 (151) Paharpur Cooling Towers, Ltd. . . . 27

Swagelok Co. . . . . . . . . . . . . . . . 12

www.info.hotims.com/35901-154

www.info.hotims.com/35901-151

(93)

(62)

www.info.hotims.com/35901-62

www.info.hotims.com/35901-100

www.info.hotims.com/35901-69 www.info.hotims.com/35901-93

Events - Save The Date . . . . . . . 95

Microtherm . . . . . . . . . . . . . . . . T-68 (100) (69)

(52)

www.info.hotims.com/35901-52

www.info.hotims.com/35901-158

Emerson Process Management . . . 6

(83)

www.info.hotims.com/35901-161

Siemens Ag . . . . . . . . . . . . . . . . 31

www.info.hotims.com/35901-156

Merichem Company . . . . . . . . . . 35

Rentech Boiler Services . . . . . . . T-70

Samson GmbH . . . . . . . . . . . . . . 53 (161)

Gulf Publishing Company

Merichem Company . . . . . . . . . . 33

RS#

www.info.hotims.com/35901-83

www.info.hotims.com/35901-78

www.info.hotims.com/35901-59

Flexitallic LP . . . . . . . . . . . . . . . . . 5

Greene, Tweed & Co. . . . . . . . . . . 20 (153)

ITT Industries . . . . . . . . . . . . . . . 28

Page

www.info.hotims.com/35901-164

www.info.hotims.com/35901-79

www.info.hotims.com/35901-99

Emerson Process Management (Fisher Controls) . . . . . . . . . . . . 22

Quest Integrity Group LLC . . . . . . 87 (164)

Linde Process Plants . . . . . . . . . . 14

www.info.hotims.com/35901-76

Dunn Heat Exchangers . . . . . . . T-66

(72)

Subscription . . . . . . . . . . . . . . . 92

www.info.hotims.com/35901-95

Dollinger Filtration, An SPX Brand . . . . . . . . . . . . . T-72

GE Power & Water . . . . . . . . . . . . . 8

HPI Market DataBook . . . . . . . T-61

www.info.hotims.com/35901-155

Curtiss-Wright Flow Control Corporation . . . . . . . . . . . . . . . 10

Company Website

Construction Boxscore . . . . . . . . 26 (156)

Bryan Research & Engineering . . . 42 (113)

Curtiss-Wright Flow Control Corporation . . . . . . . . . . . . . . T-64

RS#

www.info.hotims.com/35901-153

(53)

www.info.hotims.com/35901-53

Cameron . . . . . . . . . . . . . . . . . . . . 2

Page

www.info.hotims.com/35901-72

www.info.hotims.com/35901-97

Axens . . . . . . . . . . . . . . . . . . . . . 96

Company Website

(97)

(92)

www.info.hotims.com/35901-92

VOITH TURBO GmbH & CO. KG . . . . . . . . . . . . . . . . . T-74 (166) www.info.hotims.com/35901-166

For information about subscribing to HYDROCARBON PROCESSING, please visit www.HydrocarbonProcessing.com HYDROCARBON PROCESSING MARCH 2011

I 93

HPIN WATER MANAGEMENT LORAINE A. HUCHLER, CONTRIBUTING EDITOR [email protected]

Passivation in cooling water circuits Passivation—the formation of a corrosion-resistant oxide on a clean metal surface—is the key to optimizing system reliability on the waterside of heat exchangers. Most plant personnel are aware of the risks of corrosion. However, they are not aware of the importance of passivation. Passivation primer. During passivation, metal oxides convert

from a porous, nonprotective form to a tight, adherent, protective form. For carbon steel, the nonprotective oxide, iron hydroxide (FeOH) converts to a moderately protective oxide, hematite (Fe2O3) to the most protective form, magnetite (Fe3O4). Under the right conditions, this conversion reaction is spontaneous. But it is not necessarily a fast reaction. Optimizing the kinetics of the passivation reaction requires optimizing water chemistry and operating conditions. The optimal conditions for carbon steel passivation are: low dissolved oxygen concentration in the water, high temperature and high pH. In cooling water circuits, passivation is not spontaneous because cooling water is oxygenated (7 mg/l < O2 < 13 mg/l) at ambient or moderate temperatures—70°F–100°F (15°C–38°C)—and neutral to mildly alkaline pH (6.5 < pH < 9). High-alloy steels, admiralty and other copper alloys, form highly protective oxides more rapidly than carbon steel and under a wider range of conditions. However, high concentrations of chlorides and sulfates in the cooling water will compromise the passivation process, thus resulting in an oxide that is not protective against corrosion. Passivation decisions. Passivation of newly fabricated carbon steel heat exchangers is so important that it should be a nonnegotiable part of start-up. Plants may choose to conduct passivation procedures by isolating a single heat exchanger or circulating chemicals in the entire cooling water circuit, depending on the number of new heat exchangers or the number of new tubes. Pre-cleaning procedures are also non-negotiable since passivation procedures are only effective on clean metal surfaces. New

heat exchangers may have residual metal-working fluids from the manufacturing process or an oil-based coating to protect against corrosion during shipping and storage. Passivation of cooling water circuits following a turnaround will reduce the risk of under-deposit corrosion from solubalized iron oxides formed during idle periods due to stagnant water and/or exposure of water-wetted carbon steel surfaces to air. Procedures. There are several key issues for the design of pre-

cleaning and passivation procedures: • Most plants hire a contractor to conduct the pre-cleaning and passivation processes. Yet, plant personnel are responsible for confirming the optimal procedures. • Heating the chemical solutions will accelerate the cleaning and passivation processes, reducing the project time by as much as 50%. However, there should be minimal or no heat load from the process until the passivation process is complete. • Plant personnel may choose to treat the spent cleaning solutions in their wastewater plant to avoid offsite disposal costs. • Plant personnel should never reuse spent pre-cleaning solution for the passivation process. There is a large risk of redeposition of the contaminants removed during the pre-cleaning process. • Passivation and commissioning should immediately follow the pre-cleaning process to eliminate any corrosion that will occur on clean steel surfaces in idled, drained or stagnant cooling water systems. • Under no circumstances should plant personnel initiate passivation procedures until the iron concentration is less than 3 ppm. High iron concentrations indicate inadequate flushing and/or insufficient control of corrosion. • Typical control parameters for pre-cleaning are: pH, temperature, foam and soluble iron concentration1 • Storage of new heat exchangers requires special considerations to minimize in-situ corrosion. In summary. Proper pre-cleaning and passivation procedures

Does passivation matter? A refinery installed two new carbon steel heat exchangers in a key unit. The plant had wrapped the heat exchangers in plastic and stored them outside, in the laydown yard, for one year. Plant personnel installed and commissioned these two exchangers without implementing any pre-cleaning or pre-passivation procedures. The cooling water exceeded the recommended maximum concentration of iron during start up. Both exchangers failed within one year of commissioning. The root cause for the failure was under-deposit corrosion from deposits that formed from in-situ corrosion during commissioning. 94

I MARCH 2011 HydrocarbonProcessing.com

do increase the reliability of heat exchangers and should be a mandatory part of start up procedures. Ideally, plants will create and validate internal procedures for pre-cleaning and passivation procedures based on industry standards, experience and sitespecific limitations. HP

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: [email protected].

20 11

GULF PUBLISHING COMPANY EVENTS

SAVE THE DATE

PROCESS CONTROL AND INSTRUMENTATION CONFERENCE 9–10 March 2011 • Moody Gardens, Galveston, Texas Hosted by World Oil and Hydrocarbon Processing, the Process Control and Instrumentation Conference will be devoted to advancing process control and instrumentation in the oil and gas industry. www.GulfPub.com/PCI

INTERNATIONAL REFINING AND PETROCHEMICAL CONFERENCE Summer 2011 The International Refining and Petrochemical Conference is a market-leading program for technical and operating management in the hydrocarbon processing industry (HPI). This conference will offer you an effective means to market to engineering and operations management in the HPI. Like Hydrocarbon Processing, the International Refining and Petrochemical Conference focuses on providing the industry the very best technical content. www.GulfPub.com/IRPC

MARKETING IN THE OILFIELD CONFERENCE August 2011 • Houston, Texas The Marketing in the Oilfield Conference provides an environment to learn new ideas and strategies, in addition to numerous opportunities to network with fellow upstream and downstream marketing peers. This conference focuses on industry hot topics related to marketing, social media and communication issues and includes featured keynote experts and presentations relevant to the topic in focus. www.GulfPub.com/MITO

WORLD OIL SHALEENERGY™ TECHNOLOGY CONFERENCE 24–25 August 2011 • Westin Memorial City, Houston, Texas With the discovery of numerous shale gas plays throughout the world over the last decade that have the potential to produce trillions of cubic feet of gas over the coming years, many industry professionals, leaders, academics and regulators have dubbed this abundant energy source the “world’s bridge fuel.” World Oil’s ShaleEnergy™ Technology Conference connects the public with up-to-the-minute information on the operations, regulations, technology and activity reports about the natural gas plays throughout the United States and Europe. www.GulfPub.com/ShaleEnergyConference

WORLD OIL HPHT DRILLING & COMPLETIONS CONFERENCE 28–29 Septmeber 2011 • Houston, Texas In pursuit of reservoirs more than 15,000 feet below the earth’s surface in conditions with temperatures reaching beyond 350° F and unprecedented pressure levels, operators are confronted with unforeseen drilling and completion challenges. The World Oil HPHT Drilling & Completions Conference will be a forum to discuss and share these experiences and case histories when drilling for gas in high temperatures and oil in high pressure. www.GulfPub.com/HPHT

WORLD OIL AWARDS 13 October 2011 • Houston, Texas The World Oil Awards recognizes and celebrates the industry’s best in categories covering the entire spectrum of the upstream oil and gas industry. Innovative technologies, companies and individuals are nominated in categories ranging from drilling to intervention to recognizing the next generation of leaders in the petroleum industry. Companies are given four months to submit nominations for innovative ideas over the previous year. www.Awards.WorldOil.com

WOMEN’S GLOBAL LEADERSHIP CONFERENCE IN ENERGY AND TECHNOLOGY November 2011 • Houston, Texas Hosted by both World Oil and Hydrocarbon Processing, the Women’s Global Leadership Conference in Energy and Technology is the largest women’s event in the industry, and the only one that focuses on discussing the industry’s key environmental, economic, professional development and human capital issues in one setting. Attendees leave the conference with an increased understanding of the full range of current issues pertinent to the industry today and an increased ability to be change agents in their careers. www.WGLNetwork.com For more information about Gulf Publishing Company events, or to work with us to create a new event, visit www.GulfPub.com/Events, e-mail [email protected] or call +1 (713) 520-4475. (Event topics and dates are subject to change.)

GULF P U B L I S H I N G C O M PA N Y

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