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MARCH 2011

HPIMPACT SPECIALREPORT BONUSREPORT

CORROSION CONTROLCORROSION CONTROL

Methods show Methods show howhowto detect andto detect andcontrol corrosioncontrol corrosion

US pipeline safety billUS pipeline safety bill

Global midstreamGlobal midstream M&A updateM&A update

PLANT SAFETYPLANT SAFETY

New technologies, New technologies, standards and systems standards and systems reduce plant risksreduce plant risks



MARCH 2011 • VOL. 90 NO. 3

SPECIAL REPORT: CORROSION CONTROL

29 Updates on improving refractory lining service life Tips help maintenance and operations care and maintain refractory products

in high-temperature operations M. Maity

39 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

43 Avoid brittle fracture in pressure vessels 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

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.

HPIMPACT17 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

COLUMNS9 HPIN RELIABILITY

Oil mist and electric motor windings

11 HPIN EUROPEChina enters and Russia deepens its influence in European refining

13 HPINTEGRATION STRATEGIESTerminal automation: More challenging than it looks

15 HPIN ASSOCIATIONSMaintenance, securing the cloud and a pep talk

94 HPIN WATER MANAGEMENTPassivation in cooling water circuits

TURNAROUND AND MAINTENANCE 2011—SUPPLEMENT 55 Turnaround and Maintenance 2010

Guide on how to successfully execute turnarounds and proper facility maintenance

BONUS REPORT: WATER MANAGEMENT 75 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

78 Consider new design criteria equipment modulesConstruction offers cost-effective protection of critical systems

D. Cole and D. Austin

83 Chemical Facility Anti-Terrorism Standard turns four: What’s next?An in-depth look at the standard

R. Loughin

INSTRUMENTATION 85 Avoid these top-10 instrumentation headaches

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

ENGINEERING CASE HISTORIES 89 Case 61: Pressure loss in a reactor

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

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HYDROCARBON PROCESSING MARCH 2011 I 7

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 busi-nesses 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 down-stream 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 inte-grated 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 manufactur-ing capability equivalent to approxi-mately 3% of US production.

During the last few years, over $1 billion has been invested in moderniz-ing and improving the Texas City plant. Much of that investment was driven by the requirements of federal regulators after the March 2005 fire and explo-sion at the refinery killed 15 workers and injured more than 170 others. Investigation of the accident revealed BP was to blame for subpar mainte-nance and safety procedures. HP

[email protected]

BILLY THINNES, NEWS EDITOR

HPIN BRIEF

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, produc-tion 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 produc-tion rates, higher product water quality levels and reduced scaling and fouling when com-pared 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 opera-tions 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 inductively-coupled 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

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HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR

HPIN RELIABILITY

[email protected]


We often get questions relating to oil mist and how it affects electric motor wind-ings. 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 elec-tric motors, we recommend you insist on having the vendor prove IP66 compliance. IP is the universally recognized Ingress Pro-tection 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.

History. There are other historical facts 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 lubri-cation. 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 dam-age to winding insulation, or cause over-heating until winding failure occurred. Ini-tial efforts were, therefore, directed toward developing lip seals or other barriers con-fining the oil mist to only the bearing areas. Those efforts date back to about 1975.

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-

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 sup-ply manifolds ranging from .005 to as little as .001 of the concentrations generally con-sidered 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.

New windings. With the introduction of epoxy motor-winding materials several decades ago, it was shown that these wind-ing coatings will not deteriorate in an oil-mist atmosphere. This has been conclu-sively proven in tests by users and motor manufacturers. Among them were Reliance Electric (Cleveland), Continental Electric (Newark), and an oil refinery in the Carib-bean 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 con-duit 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

LITERATURE CITED 1 Bloch, H. P. and A. Budris, Pump User’s Handbook: Life Extension, 3rd Edition, The Fairmont Press, Inc., Lilburn, Georgia, 2010, pp. 477-478

Oil mist and electric motor windings

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 mainte-nance cost-reduction opportunities. For more details, see his Practical Lubrication for Industrial Facilities, ISBN 0-88173-579-5.

A worn Vee-ring removed from an electric motor.

FIG. 1

Oil mist vent

Oil mist in

Overflow drain

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

FIG. 2

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TIM LLOYD WRIGHT, EUROPEAN EDITOR

HPIN EUROPE

[email protected]


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.

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

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 inter-nationally 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

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 indus-try, privatized and listed, from the majority of the OPEC–based NOCs (Rosneft is publicly listed but state-controlled). State-owned 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.

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

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.

China enters and Russia deepens its influence in European refining

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HPINTEGRATION STRATEGIES


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PAUL MILLER, CONTRIBUTING EDITOR

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 sys-tems. Due to the recent flood of mergers and acquisitions, many multi-terminal owner-operators also find themselves with differ-ent 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 offer-ings 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 (includ-ing some well-targeted acquisitions) to develop comprehensive ter-minal-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 else-where 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-prod-uct 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

ever-increasing number of different petroleum- and biofuel-related products and additives, deal with extreme price volatility, and com-ply with stringent and ever-changing governmental regulations.

Several highly publicized terminal explosions, fires and spills underscore the need for increased safety to protect people, equip-ment, property and the environment. The threat of terrorists or disgruntled employees targeting these relatively vulnerable facili-ties 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 paper-based 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 hard-ware, 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 interoper-ability, 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 suppli-ers with dedicated solutions for terminal automation, and more specialized TAS/TMS suppliers that largely focus on the terminal-automation 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.

Terminal automation: More challenging than it looksTABLE 1. Some terminal-automation solution providers

TAS suppliers Full-line TMS software (software-based, automation suppliers specialists with some (hardware/software (software only) specialized hardware) 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

Sulfur

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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 inten-sive 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 ses-sion 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 gate-way (PMDG) is based upon the Accen-ture plant performance solution (APPS). PMDG correlates transactional and real-time 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 effi-cient manner.

This software suite helps a company like GenOn look at its equipment via a life cycle, especially in procurement proce-dures 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 mainte-nance allows for: station personnel to be knowledgeable of roles; the personnel are fully trained in utilizing maintenance tech-nologies; 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 main-tenance efficiently and utilize root-cause analysis programs to complete the mainte-nance 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 Micro-soft’s initiative known as trustworthy com-puting. 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, detec-tion 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 know-how. Many customers are using Share-Point [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 retir-ees 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 down-stream support. Companies like Aspen-Tech, OSIsoft, Honeywell and Invensys all have offerings available that are built on Microsoft technology.

“We have a strong ecosystem of part-ners that is helping manage the refining and petrochemical process,” he said.

Looking to the future, Mr. Hodges said that business intelligence and better col-laboration will continue to be a big push. All facets of intelligence and collaboration are constantly being examined and reex-amined. The essence of all this is Micro-soft’s quest to help its customers find, use and share data in the most efficient man-ner, 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 quarter-back 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

Maintenance, securing the cloud and a pep talk

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

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HPIMPACT

Pipeline safety bill introduced in US Senate

Two US senators have introduced leg-islation 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 origi-nal 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 Transporta-tion’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 mil-lion 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 trans-portation than other options for moving gas and liquids.

Since 2006, there have been approxi-mately 40 pipeline incidents each year that resulted in a fatality or injury. Last Sep-tember, 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 oth-ers. 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 penal-ties 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 shut-off valves on new transmission pipelines; instructs the US Secretary of Transporta-tion to establish time limits on accident and leak notification by pipeline opera-tors to local and state government officials and emergency responders; requires the US Secretary of Transportation to evalu-ate 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

additional pipeline inspectors and pipe-line 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. Accord-ing to the report, nearly all (94%) of mid-stream 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 stream-lining 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


[email protected]

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.

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HPIMPACT

19

have seen MLPs streamlining operations through acquisition of their general part-ners, eliminating general partner distribu-tion requirements and using those funds for capital expenditures or to maintain distri-butions 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. Enter-prise Products Partners has geographically diverse gas-gathering and storage assets in Texas, Louisiana, Colorado and Ohio, pri-marily serving conventional gas plays.

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 lim-ited 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 mid-stream operations, cutting operating costs. Williams Pipeline Partners has diversified US midstream operations, with major pipe-lines, 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 con-solidation 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 geo-graphically, versus taking on extensive new construction. In particular, we have seen this in US shale plays, where we wit-nessed 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

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 Petrochemi-cal and Refiners Association (NPRA) said existing Chemical Facility Anti-Terrorism Standards (CFATS) are effective and should be made permanent. The association’s state-ment was given to the US House Commit-tee 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


HPIMPACT

20

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 pro-gram was created under the US Depart-ment of Homeland Security (DHS) to regulate security at chemical facilities deter-mined 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 con-sidered.”

The program is currently operating under a temporary extension granted by Congress. Legislative proposals both to modify the existing program and to make

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 testi-mony reiterated the association’s longstand-ing opposition to this change.

“IST is a conceptual and often complex framework that covers procedures, equip-ment, 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 under-standing chemical engineering and the sup-ply 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 leg-islation. IST and chemical engineering deci-sions 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 facil-ity security policy.”

US demand for activated carbon growing

US demand for activated carbon, including both virgin and reactivated products sold by activated carbon sup-pliers, 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 technol-ogy for industrial air purification applica-tions. 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 five-fold 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 emis-sions standards currently in draft form will represent a tremendous growth opportu-nity 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 two-thirds of US product demand in 2014 in volume terms. HP

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HPIN CONSTRUCTIONHELEN MECHE, ASSOCIATE EDITOR

[email protected]

North AmericaSasol plans to construct what is said to

be the world’s first commercial ethylene tetramerization unit, capable of produc-ing 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 con-vert ethylene to 1-octene and 1-hexene. This unique process selectively produces alpha olefins required for the high-growth polymer markets. Construction will com-mence 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 pro-prietary technology for producing high-purity G2 Clear biodiesel. KMTEX will host EBF as well as provide certain con-struction and operational services. Equity funding will come from Haddington Ven-tures, 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 exe-cution, including pre-planning and post turnaround activities, as well as delivery of small capital works at the site.

South AmericaAlbemarle 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 crack-ing (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 com-ing years. Albemarle will provide FCC SA with its leading technology for manu-

facturing HPC, enabling production of STARS catalysts.

EuropeAlfa 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 intel-lectual property center of Maire Tecnimont S.p.A., has acquired the Italian engineering company Noy Engineering from Tecni-mont. With this acquisition, Stamicarbon’s extensive licensing, innovation and cus-tomer-service experience are combined with Noy Engineering’s polyester and polymeriza-tion 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 technolo-gies. It has developed an extensive portfolio of polymer technologies and acrylic.

Middle EastQatar 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 mil-lion tons of finished products.

Süd-Chemie AG and Yara Interna-tional ASA have a five-year framework agreement on catalysts for fertilizer pro-duction. 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 front-end catalysts involved in producing ammo-nia, 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 cata-lytic 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 Proj-ect is managed by RasGas Co., Ltd., which is owned by Qatar Petroleum (70%) and an affiliate of ExxonMobil (30%).

Trend analysis forecastingHydrocarbon 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

[email protected]


HPIN CONSTRUCTION

23

The project, located in Ras Laffan Industrial City, 80 km north of Doha, calls for the engineering, procurement and con-struction (EPC) of the gas processing facili-ties. 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 dol-lar 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 engineer-ing procurement contractor, GS Engineer-ing & Construction Corp., Elliott will provide seven compressor trains, a power-recovery 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 com-pressors for the crude-oil distillation plant under contract with SK Engineering & Construction Co. Delivery is scheduled for mid-2013, with commissioning to fol-low in the first quarter of 2014.

Asia-PacificAir Liquide has signed a long-term con-

tract with Tongmei Guangfa Chemical Industry Co., Ltd., whose major share-holder is Datong Coal Mine Group Co. Under agreement terms, Air Liquide will invest around €60 million in a large air-separation unit (ASU) with production capacity of 2,000 tpd of oxygen to sup-ply oxygen and nitrogen to the customer’s methanol-production project in Datong, Shanxi Province, China. Industrial pro-duction 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, Gran-herne, 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, North-ern Territory, Australia. The project, being developed through a joint venture

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

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

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

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


24 I MARCH 2011 HydrocarbonProcessing.com

HPIN CONSTRUCTIONdeposits 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 rela-tive to steam cracking—due to the technol-ogy’s higher total olefins yields and increased propylene/ethylene ratios approaching 1.0. The startup is said to mark the first com-mercial demonstration of ACO.

The demonstration unit achieved design feed rate as scheduled in late Octo-ber 2010. The ACO process provides an attractive alternative to naphtha steam crackers and, in addition to offering higher olefins production, the process also pro-duces 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 pro-duction.

IndianOil and LanzaTech have an understanding to collaborate in a technol-ogy demonstration that will enable Indian-Oil to produce fuel-grade ethanol. As a part of the collaboration, IndianOil will evalu-ate LanzaTech’s proprietary gas-fermenta-tion 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 sim-ulator for an ethylene cracker and associ-ated units that form part of a polymer com-plex to be built in Dahej, India. The plant will manufacture 1.1 million tpy of ethyl-ene, 400,000 tpy of propylene, 150,000 tpy of benzene and 115,000 tpy of butadiene.

Together with consortium partner Sam-sung 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 report-edly 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


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26 I JANUARY 2011 HYDROCARBON PROCESSING

HPI CONSTRUCTION BOXSCORE UPDATE Company City Plant Site Project Capacity Unit Cost Status Yr Cmpl Licensor Engineering Constructor

AFRICA Algeria Sonatrach Algiers Algeries Refinery RE 60 Bcfd 908 M 2013 SONARA TechnipAngola Sonangol Lobito Lobito Refinery 200 Mbpd U 2015 KBR Morocco SAMIR Mohammedia Mohammedia Treater, Kerosine 600 t/a E 2012 UOP Tecnicas Reunidas

ASIA/PACIFIC Australia Santos\PETRONAS JV Queensland Bowen-Surat Basin LNG EX 1.5 Mtpy 750 U 2011 Total Fluor FluorChina Unocal Indonesia Ltd Sichuan Sichuan Sulfur 212 MMcfd 1300 E 2013 WorleyParsons India Mangalore Rfg & Petrochemicals Mangalore Mangalore Refinery EX 9.69 MMtpy 2400 U 2011 EIL|Toyo Japan EIL EILPapua New Guinea Esso Highlands PNG LNG Kutubu Kutubu LNG 6.6 MMtpy U 2014 JGC|Chiyoda CB&ISouth Korea Hyundai Oilbank Co., Ltd. Daesan Daesan Refinery, Heavy Ends (2) 510 bpd 2330 C 2011Vietnam Petrovietnam Dung Quat Dung Quat Refinery EX 6.5 MMtpy 3000 P 2016 Technip|JGC| Tecnicas Reunidas Tecnicas Reunidas JGC|Technip

CANADA Alberta Altagas Harmattan Harmattan Gas Plant 95 MMcfd 50 P 2012 Gas Liquids Eng British Columbia Murphy Oil Co Ltd West Tupper West Tupper Gas Plant 180 MMcfd 180 U 2011 Gas Liquids Eng TAHK Projects Ltd

EUROPE Belarus Mozyr Refinery Mozyr Mozyr Treater, Tail Gas 240 t/a E 2013 Siirtec Nigi Siirtec Nigi Belgium Eval Europe NV Antwerp Antwerp Polymer (2) EX t/a 470 M 2012 Kuraray Aker Kvaerner Aker Kvaerner Bulgaria Lukoil Neftochim Bourgas Burgas Burgas Hydrocrack, Resid 2.2 MMtpy 95 E 2013 Axens Technip Greece Hellenic Petroleum SA Elefsina Elefsina Amine Recovery 280 tpd U 2011 Haldor Topsøe Tecnicas Reunidas Italy Eni SpA Sannazzaro Raffineria di Sannazzaro Sour Water Stripper 3.5 Mcfd U 2012 Siirtec Nigi Kazakhstan AGIP KCO Kashagan Kashagan Field Gas Dehydration (1) 200 MMcfd U 2013 Siirtec Nigi Siirtec Nigi Netherlands Kuwait Petro Corp Rotterdam Rotterdam Sulfur Recovery Unit (2) None 100 C 2011Portugal Galp Energia Sines Sines Cracker, FCC RE None U 2011 UOP Tecnicas Reunidas Tecnicas ReunidasRussian Federation Rosneft Angarsk Angarsk Sulfur Recovery Unit 114 m-tpd E 2013 WorleyParsons WorleyParsons Spain Repsol YPF Cartagena Cartagena Coker, Gas Oil 920000 tpy U 2011 Axens Tecnicas Reunidas Tecnicas ReunidasUK Powerfuel Plc Hatfield Hatfield Sulfur Recovery Unit 50 m-tpd E 2014 WorleyParsons |Cryoplants WorleyParsons

LATIN AMERICA Brazil Agrenco Bio-Energia Parana Parana Biodiesel 135 Mtpy S 2013 Mexico Pemex Minatitlan Minatitlan Hydrotreater, Gasoil EX 50 bpd U 2011 Tecnicas Reunidas Rio San Juan Constr Constr N. OdebrechtPeru Petroperu Talara Talara Hydrotreater, Diesel 41 bpsd E 2014 Axens Tecnicas Reunidas Tecnicas Reunidas

MIDDLE EAST Bahrain BAPCO\Neste Oil Corp JV Bahrain City Bahrain City Lube Oil Refining 36 m-t 9300 C 2011 CLG|Neste Jacobs Samsung Eng Samsung EngOman Octal Holding & Co Salalah Salalah PET (2) 527 Mt 296 E 2012 Uhde Inventa-Fischer Qatar Qatar Petroleum Mesaieed Mesaieed Sulfur Recovery TO 308 m-tpd E 2012 WorleyParsons WorleyParsons PetrofacSaudi Arabia Saudi Aramco Yanbu Yanbu Refinery 400 bpd 580 U 2014 KBRTurkey TUPRAS Izmit Izmit Utilities None E 2014 Tecnicas Reunidas Tecnicas Reunidas

UNITED STATES Alaska Tesoro Corp Kenai Kenai Benzene Reduction EX None 90 A 2012 Mustang Texas Delek Refining Tyler Tyler Cracker, FCC Reactor RE None 10 C 2011 UOP Mustang AltairStricklandUtah Tesoro Corp Salt Lake City Salt Lake City Benzene Reduction EX None 55 C 2011 UOP Mustang

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CORROSION CONTROL SPECIALREPORT


Updates on improving refractory lining service lifeTips 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 indus-try (HPI) utilizes high-temperature conditions and relies on the perfor-

mance of refractory lining for various fur-naces 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 impor-tant 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-perfor-mances 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 second-ary reformers, cracking furnaces, incinera-tors, process gas boilers, catalytic crack-ing units, coke calciner, sulfur furnaces, utility boilers, air heaters, ducting, stacks, etc. Some of the listed equipment operate under high pressure, and operating tem-perature 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. Refrac-tories 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 con-tinuous operating mode and will run for several years before a scheduled shutdown for maintenance or turnaround. Therefore, the prime objective here is equipment reli-ability. 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, misunder-stood and abused, and the uncared for refractory can cause several problems dur-ing regular plant operations.

The unexpected problems can cause an emergency shutdown or require lon-ger 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 refrac-tory related problems and reduce unnec-essary expenses by introducing sound engineering practices, following proven guidelines and sharing practical experiences while designing the lining and selecting construction materials, installation meth-ods, etc. This article will discuss several common problems and failures of refrac-tory lining and highlight important consid-erations 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 fur-naces. Refractory lining problems and fail-ures are mainly due to thermo-mechanical stresses, erosion and chemical attack. The most common refractory problems as expe-rienced 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. There-fore, lining problems in critical pressure ves-sels 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

CORROSION CONTROLSPECIALREPORT


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 exam-ples 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

shell plate. Also, mechanical damage in the cyclones due to erosion of the lining and plate may disturb the unit operation. Fail-ure 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 uncon-trolled heating.

Differential movement of the shell and lining due to a mismatch in expansion behavior, uncontrolled heating-cooling,

mechanical stresses, etc., can cause vari-ous 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 effi-ciency, 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 perfor-mance of refractory. Therefore, in most of the cases, it may be very difficult to con-clude a single reason for nonperformance and premature failure of the lining. Also, there are numerous precommissioning fac-tors 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 refrac-tory may contribute to the problem. But it is also possible that a good quality refrac-tory 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 recom-mendations.

Identifying the actual reason of non-performance for the lining is a difficult task, and this involves systematic study and analysis of the problem. Reviews of back-ground information particularly design engineering, quality and source of mate-rial, 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 deg-radation mechanisms that can lead to fail-ure 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 lin-ing 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. Collect-ing samples and selective laboratory test-ing should be part of the failure analysis, if required. Important factors responsible for the performance of the lining are briefly explained here.

Typical refractory lining failures—Castable damage and anchors exposed.

FIG. 4

Typical refractory lining failures—Loose bricks hanging.

FIG. 5

Typical refractory lining failures—CF module fallen from roof.

FIG. 6Typical refractory lining failures—Roof lining collapse.

FIG. 3

Typical refractory lining failures—Castable wall detached.

FIG. 2

Typical refractory lining failures—Crack in castable lining.

FIG. 1

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CORROSION CONTROL

Important factors governing refractory lining performance. Whenever there are some problems in lin-ing, we mostly conclude that either the refractory material was bad or the installa-tion was poor. However, in reality, the prob-lems 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 proj-ect contractors, suppliers and others don’t always recognize that their actions and over-sights 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 contrib-ute refractory related problems. These fac-tors 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

• Operation practices• Inspection and maintenance

practices.It is important to give attention to these

listed factors to avoid and minimize unex-pected and premature failure or problems of lining.

Design of furnace/vessels. The per-formance and stability of the refractory lining depends on the structural design of the furnace and its configuration. Some-times adequate attention is not given to the refractory lining and its engineering related issues during early plant equip-ment 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 imple-mentation or during installation. This may lead to several compromises with refrac-tory-lining design and engineering prac-tices 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 vol-ume. 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, inacces-sibility 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 engi-neering of the lining for a furnace and ves-sel should be done on the basis of careful analysis of service conditions, availability of refractory materials, thickness require-ments, 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, mechani-cal 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, sul-furous gases, etc.; these acid gases can initi-ate various problems in the lining, which

Typical refractory lining fail-ures—Casing plate corrosion with perforation.

FIG. 7

Typical refractory lining failures—Acid condensation below lining.

FIG. 8

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are explained in the literature. All of the important operating factors and any other criteria specific to the process under consid-eration 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 lin-ing behavior.

Anchors are used for almost all types of refractory applications. These are mostly metallic type. Lining failures due to inad-equacies in the anchoring system are very common (Figs. 6, 9 and 10). Selecting the proper metallurgy, anchor dimensions, configurations, and spacing are very impor-tant 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 ves-sel 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, provi-sions for expansion allowances, support of brick-wall, etc., should be part of the detail engineering for each piece of equipment.

Finally, practical experiences and expe-rience-based judgments are very impor-tant 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

high alumina varieties—both insulating and dense types. Mainly bricks, monolith-ics, 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 suit-able for the specific application and operat-ing conditions. Most refractory materials react and change during service according to the principle of thermo-chemistry. It is important to know the furnace atmo-sphere, 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 lin-ing 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 draw-ings for the complicated brick shapes and laying details. In many cases, recommen-dations 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 mate-rials 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 appli-cations, purchasing of materials based on a comparison of product datasheet or cata-logue specifications or equivalent principles should be avoided. The actual performance references and records for specific products or brands should be verified against simi-lar applications. Reviews of manufacturing facilities and quality-control program, and random inspection and testing of impor-tant properties are essential.

Typical refractory lining failures—Brick wall bulged.

FIG. 11Typical refractory lining failures—Oxidation of anchor.

FIG. 9

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

FIG. 12Typical refractory lining failures—Surface spalling and exposed anchor.

FIG. 10

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Lining installation. Unlike other engi-neering subjects, there are very few well-established and recognized engineering standards, design and installation guide-lines for refractory jobs to ensure quality installation of the lining and its subsequent satisfactory performance. In many applica-tions and contracts, the only quality assur-ance 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 involve-ment 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) espe-cially for process industries. Prequalifica-tion 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 recom-mending 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 guide-lines 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 consider-ing 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 crack-ing 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 con-cern for monolithic lining in tropical and

subtropical weather conditions. Dry-out needs to be done at the earliest to prevent damage. When delays in dry out or com-plete dry-out are not practical, suitable seal-ants may be used on monolithic lining to reduce alkali hydrolysis reaction and dam-age. 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 fol-lowing general guidelines from the sup-plier. Burner size and location, exhaust location, air volume, velocity, temperature-control 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 pro-fessional manner.

Unit operation. Production and opera-tion personnel should be aware of the pro-cess 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. Oper-ating 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 ini-tiation of deterioration in lining due to operational issues may not become visible immediately. Therefore, it is important to gather information on operational infor-mation and records while studying the problem.

Inspection and maintenance. Regu-lar 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. Infra-red thermography is an important tool for online-temperature measurement, condi-tion monitoring of lining, predicting prob-lems, and maintaining equipment uptime during a problem.

Thermography is very useful for locat-ing and monitoring effected areas in case of any operational upset or localized prob-lem 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 con-ventional reactive systems. The probable reasons and mode of failure should be ascertained before redesigning or repair-ing 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 long-term 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 instal-lation is one of the last activities. With any delay in other pre-activities, there is always pressure on shortening and pos-sibly compromising the refractory instal-lation 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 con-ditions for workers have direct effects on the quality of the installation job. Imple-menting cost-cutting measures, purchas-ing 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 fur-naces and vessels. The properties of the refractories are tailored to specific applica-tions by varying the composition of raw materials. The technology of refractories is making remarkable progress recently.

37

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 variabil-ity in design and application, complexity of service conditions and material behav-ior. Awareness of the potential degrada-tion mechanisms of lining and operating parameters is essential to mitigate such problems. Implementing various quality control programs, advanced installation procedures and online inspection can con-tribute to satisfy results. HP

BIBLIOGRAPGHYAmerican 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.

Manabendra Maity is work-ing as a refractory specialist at the Materials & Corrosion Section of Sabic Technology Centre, Jubail, KSA. He holds B.Tech degree in ceramic engi-

neering 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 & non-metallics 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.

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Flare stack structure revamp: A case historyAn 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 installa-

tions such as oil and gas wells, oil rigs, refin-eries, chemical, petrochemical and natural gas plants, and other facilities (Fig. 1). On oil- production rigs and in refineries and petrochemical plants, the flare stacks primar-ily serve to protect vessels or pipes from over-pressuring 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 hydrocar-bons 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 resem-bles a pilot light, maintaining the system ready for its primary purpose as an over-pressure 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 dispos-ing 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 acetylene-rich gases.

At Reliance’s Nagothane facility, a large flare stack with a design load of 1,000 met-ric tph is located on the north-east side of a gas-cracker plant. Flare headers from individual plants—polypropylene, low-density 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 car-ried with the gases passing through relief valves. Liquid capture avoids the danger

Flare stack. FIG. 1

Flare stack

Watersealdrum

Knockoutdrum

WFdrum

ISBL

OSBL

LLD

CPP

LDB-1

PP

Water inlet

Flare system schematic at the Nagothane plant in India. FIG. 2



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 atten-dant risk of explosion. The flare stack at this facility is 100 m high and has a diam-eter 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.

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 origi-nal 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. Dam-age 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 flare stack at Nagothane was commis-sioned 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 shut-downs. 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 thick-ness was observed and measured at vari-ous locations, mainly under the support plates (Figs. 3 and 4). Fuel gas and steam

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 real-ized 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.

Repair approach. The conventional mode of replacing or repairing a flare structure, piping and subsequent paint-ing 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 pro-

tective 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

Damaged structure.FIG. 3

Extreme corrosion on a flare stack in India.

FIG. 4

Pre-shutdown scaffolding work.FIG. 5

Lift arrangement and protective metallic shields.

FIG. 6



structure. Their effectiveness was dem-onstrated 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 plant-wide 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 shut-down 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 struc-ture 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 sus-pended. 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-

shutdown part of the repair job in time.All repair work on the flare stack struc-

ture was successfully done without incident within the scheduled period—-85 days for non-shutdown work and 16 days for shut-down 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

ABBREVIATIONSNMD- Nagothane Manufacturing DivisionPP- Poly propyleneLDPE- Linear density polyethyleneLLDPE- Linear-low density polyethyleneGC- Gas crackerOSBL- Outside battery limitISBL- Inside battery limit

Water shield at 66 m.FIG. 7

Platform and clamps after replacement.

FIG. 8

Piping, insulation and cladding replacement.

FIG. 9

Massive flare stack at full usage.FIG. 10A

Flare stack structure after repair and painting.

FIG. 10B

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 indus-

try experience. At present, he is assigned as head of plant mechanical maintenance for the entire complex. He has had wide experience in plant downtime reduc-tion 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.

Bryan Research & Engineering, Inc.P.O. Box 4747 • Bryan, Texas USA • 77805979-776-5220 • www.bre.com • [email protected]

Selecting the Best Solvent for Gas TreatingPROCESS INSIGHT

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.

Primary AminesThe 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 AminesThe secondary amine DEA removes both CO2 and H2S but generally requires higher pressure than MEA to meet overhead specifi cations. 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.

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 benefi t 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 SolventsIn 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.

Choosing the Best AlternativeGiven 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 fl ow process or confi guration including multiple columns, liquid hydrocarbon treating, and split fl ow 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.

BR&E




Avoid brittle fracture in pressure vesselsKey points identify effects from auto-refrigeration on steel vessels

F. KHAZRAI, H. B. HAGHIGHI and H. KORDABADI, Chagalesh Consulting Engineers, Tehran, Iran

During an emergency, equipment failure or a planned main-tenance 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 simu-lation 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-refrig-eration 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 struc-tural integrity of a pressure vessel. However, proactive engineer-ing 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 ENGINEERINGThis 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 sepa-rators containing vapor, light-liquid hydrocarbons and heavy-liquid phase. The study focused on the simulation and design of three inter-connected 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 expan-sion 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 depressuriza-tion study was limited to the fluid inside the vessel, and the metal-wall 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 tem-

TABLE 1. Design basis parameter for simulation

V-100 V-101 V-102

Vessel volume, m3 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

Initial mass of liquid, kg 917.0 584.0 656.3

Vessel metal mass, kg 41,700 11,500 9,200

Initial operating pressure, bar-g 120 105 69

Initial operating temperature, ºC 30 4 –10

V-101

To condensatestabilization unit

V-100 V-102

Produceddry gas

Feed gasfrom

manifoldproduction

line

Feed heatexchanger

V-1003-phase

inletseparator

V-1011st stage3-phase

separator

V-1022nd stage3-phase

separator

Flow diagram of three vessels for the separation process of the gas plant.

FIG. 1



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 ENGINEERINGAll 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 hav-ing 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

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 tempera-ture 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 ves-sels 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 engineer-ing approach is recommended.

-110-100

-90

-80

-70

-60

-50

-40

-30

-20

-10

10

20

020406080100

Tem

pera

ture

, °C

Pressure, barg

0

LMT MAT

LMT curve for vessel, V-101, during depressurization event.FIG. 3

-60

-50

-40

-30

-20

-10

0

10

20

30

40

020406080100120Pressure, barg

LMT MAT

Tem

pera

ture

, °C

LMT curve for vessel, V-100, during depressurization event.FIG. 2TABLE 3. Simulation results, including metal-mass values

V-100 V-101 V-102

Final pressure (FP), barg 0.02 0.02 0.02

Mass of vapor at FP, kg 24.74 9.686 14.40

Mass of liquid at FP, kg 425.8 291.6 243.2

Inner-wall temperature at FP, ºC 11 –14 –28

TABLE 4. Design data for separation vessels

Vessels V-100 V-101 V-102

Design pressure, barg 128 113.4 76.4

Design temperature, °C 80 80 80

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

TABLE 5. MDMT calculations

Vessels V-100 V-101 V-102

MDMT, °C –20 –22 –22

TABLE 2. Final fluid temperatures in first-pass simulation

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



BRITTLE FRACTURE PHENOMENAThe major concern for low-temperature vessels is brittle-frac-

ture phenomenon, which can be a cause for vessel failure. Many metals loose their ductility and toughness; they become suscep-tible to brittle fracture as the metal temperature decreases. At nor-mal 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 mate-rial (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 semi-brittle 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.

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

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,

phosphorous (P) present in steels decreases the transition tempera-ture 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 tem-perature. Stainless steel 304 with 8% nickel can resist impact loads at –320°F. Furthermore, sufficiently low carbon equivalents con-tribute 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-tough-ness by numerous fracture toughness tests at different low tem-peratures. 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

TABLE 6. Final vessel conditions after depressurization

V-102 V-101 V-100

Final pressure (FP), barg 0.02 0.02 0.02

Inner-wall temperature at FP, °C 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

-20

-10

0

010203040506070

Tem

pera

ture

, °C

Pressure, barg

LMT MAT

LMT curve for vessel, V-102, during depressurization event.FIG. 4

Brittle fracturesquare

Susceptible steel

Low temperature

Load

ing

Crac

k/st

ress

rise

rs

Brittle fracture square affecting carbon and low-alloy steels at low temperatures.

FIG. 5



• 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.

There are various techniques to prevent hydrogen cracks, including appropriate heat treatments or slow cooling after forg-ing, 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 corro-sive fluids such as wet H2S, moist air or sea water are prone to premature fracture under tensile stresses, considerably below their “fracture toughness” threshold. Suit-able steel materials should be used when exposure to corrosive fluids is possible.

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 differen-tial 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, cor-ners or notches (as may be found in weld defects) as a result of design or fabrica-tion processes are all stress risers, which can cause stress intensification. The weak points are prone to brittle fracture when other susceptible conditions exist.

Perform auto-refrigeration simulation

Select (or reselect)materials, and design

vessel considering “PE”

Determine MAT andLMT envelope

Compare LMT with MAT

Is LMT<MAT ?

Examine/inspect materialsspecification/quality versus

required specifications

Are materialrequirements

satisfied ?

Fabricate vessel,applying relevant

PEs measures

Yes No

YesNo

Implement “Controlof Operation”

NomenclatureLMT Lowest metal temperatureMAT Metal allowable temperaturePE Proactive engineering

Order materials applyingrelevant PE's measures

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

FIG. 6



47

PROACTIVE ENGINEERINGBased 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 manufactur-ers. 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 weld-procedure 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

NOTES a 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 b 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 c 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

d 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. e 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. f 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 machin-ery. 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 special-izing in the area of static equipment engineering. He has par-ticipated in various hydrocarbon processing projects at Chag-alesh 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 techni-

cal 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.

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Improving pH control mitigates corrosion in crude unitsEquipment 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

For crude-unit overhead systems, pH is the main process parameter that impacts corrosion rates. To control corrosion conditions, many operators use various neutralizers at opti-

mum 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 weight-loss 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 investiga-tion 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 Chlo-rides 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 solu-tions 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 equa-tions 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 neutral-izer 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 cor-rosion 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 chem-ical 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 stress-corrosion cracking were also reported on the shells of the equip-ment, 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 cor-rosion 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



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 immedi-ately 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 sepa-rated 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.

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.

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

TABLE 2. Relationship between problems in desalination and corrosion rates in the overhead atmospheric tower system

Period analysis, Desalting stopped, Corrosion rate, (Year–2007) Time–hours 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

Corrosion inhibitor

Beforecondenser

Overheadcondenser

Accumulatordrum

Sour waterNaphtha

Aftercondenser

Atmospherictower

Neutralizer

CDU showing locations identified for thickness monitoring by ultrasonic testing.

FIG. 1

pH o

f atm

osph

eric

syst

em-R

efine

ry B

0

3

6

9

Jan/

08

Feb/

08

Mar

/08

Apr/

08

Jun/

08

Time

Jul/0

8

Aug/

08

Oct/0

8

Nov/

08

Dec/

08

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

FIG. 2



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 guar-anteed 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 cor-rosion 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 param-eters in the overhead system. Figs. 5 and 6 show the injection rates for neutralizers and inhibitors for Refinery B in 2008.

The mass balance at the tower overhead is shown in Fig. 7. It is known that the chloride content measured in the top accumu-lator 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 for-mation, 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 a =

K w

K b

=[N 2OH ]×[H + ]

[N 2+ ]=

[H + ]2

[N 2+ ]= 5.6×10−5

As Ka is very low, the salt concentration Cs = [N2+]:

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

Day Cl–, mean Flowrate N2, l/d pH, mean

D1 46 115.2 7.10

D2 48 43.2 6

D3 49 11.5 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

Chlo

ride

conc

entr

atio

nof

atm

osph

eric

sys

tem

Refin

ery

B, p

pm

0

50

100

150

200

Jan/

08

Feb/

08

Mar

/08

Apr/

08

Jun/

08

Jul/0

8

Aug/

08

Oct/0

8

Nov/

08

Dec/

08

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

FIG. 3

Iron

conc

entr

atio

nat

mos

pher

ic s

yste

mRe

finer

y B,

ppm

0

1

2

3

4

Jan/

08

Feb/

08

Mar

/08

Apr/

08

Jun/

08

Jul/0

8

Aug/

08

Oct/0

8

Nov/

08

Dec/

08

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

FIG. 4

Neut

raliz

er in

ject

ion,

l/d

0

30

60

90

120

150

Jan/

08

Feb/

08

Mar

/08

Apr/

08

May

/08

Jun/

08

Jul/0

8

Aug/

08

Sept

/08

Oct/0

8

Nov/

08

Dec/

08

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

FIG. 5

Jan/

08

Feb/

08

Mar

/08

Apr/

08

May

/08

Jun/

08

Jul/0

8

Aug/

08

Sept

/08

Oct/0

8

Nov/

08

Dec/

08

0

10

20

30

40

50

Inhi

bito

r inj

ectio

n, l/

d

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

FIG. 6



[H + ]2 = CS×K w

K b

⇔ 2 log[H + ]=

12× log K w −

12× log K b +

12× logCS ⇔

⇔ pH = 7− 12× pK b −

12

logCS

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

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).

Discussion. At the three refineries presented in this study, vari-ous 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 bench-mark 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 tempera-ture 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

HydrocarbonFG+LPG+Naphtha86.66%Aqueous solutionH2O+HCl+H2S (pH = 2.5)13.43%

Neutralizer, N2Solution pH = 110.01%InhibitorWater soluble0.002%

Overheadcondenser

HydrocarbonFG+LPG+Naphtha86.66%Aqueous solutionpH = 6.013.43%

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

FIG. 7

0.000.100.200.300.400.500.600.70

Nov-

04De

c-04

Jan-

05Fe

b-05

Mar

-05

Apr-

05M

ay-0

5Ju

n-05

Jul-0

5Au

g-05

Sept

-05

Oct-

05No

v-05

Dec-

05Ja

n-06

Feb-

06M

ar-0

6Ap

r-06

May

-06

Jun-

06Ju

l-06

Aug-

06Se

pt-0

6Oc

t-06

Nov-

06

Corr

osio

n ra

te, m

m/y

r

Atmospheric tower

Atmospheric tower

0.000.100.200.300.400.500.600.70

Apr/

07M

ay/0

7Ju

n/07

Jul/0

7Au

g/07

Sept

/07

Oct/0

7No

v/07

Dec/

07Ja

n/08

Feb/

08M

ar/0

8Ap

r/08

May

/08

Jun/

08Ju

l/08

Aug/

08Se

pt/0

8Oc

t/08

Nov/

08De

c/08

Jan/

09Fe

b/09

Mar

/09

Apr/

09M

ay/0

9Corr

osio

n ra

te, m

m/y

r

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

FIG. 8

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

Concentration, Concentration, Day Flowrate, l/d CS (molar) pH, mean CS (molar)

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

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 consump-tion 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 rea-sons, such as incorrect pH measurement, which interferes directly in injection flowrate. If the quality of the crude is kept almost con-stant, 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 consump-tion 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 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

Dec. 2008–June 2009 0.28 0.21

TABLE 5. Relationship between predicted consumption and the measured one

Chloride content, Predicted Measured Date, kg MCl/kg consumption, consumption, Measured/ 2008 solution l/d l/d 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

TABLE 6. Corrosion rate in June and July 2008 (overhead atmospheric system—Refinery B)

Initial date, Final date, Corrosion rate, coupon installation coupon removal mm/yr

06/16/2008 07/23/2008 0.049

07/23/2008 08/26/2008 0.071

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54

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. Accord-ingly, field monitoring uses weight-loss coupons to validate the quality of process parameters control. At Refinery B, measure-ments 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 measure-ment, we realized that the difference between the rates obtained with both techniques was short only at the second decimal num-ber, 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 pos-sible 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 treat-ment. There are pros and cons associated with each neutral-izer.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 inspec-tions 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 opti-mal pH control range for the CDU overhead system. The main process parameter, defined in terms of two main corrosion mecha-nisms 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 break-down 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 instru-mented injection control fed by online pH measurement. HP

LITERATURE CITED 1 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 H2S-CO2-H2O 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 AsCl3- HCl-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.


TURNAROUND AND2011Special Supplement to

MAINTENANCE

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

Corporate Profi lesCooper 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

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TURNAROUND AND MAINTENANCE 2011

T-56 I TURNAROUND AND MAINTENANCE 2011 SPONSORED CONTENT

CORPORATE PROFILE: COOPER CROUSE-HINDS GMBH

Servicing and maintenance in hazardous areas can be time-consuming and costly, particularly if engi-neers are not provided with the right tools to carry out the job quickly and safely

As industrial processing plants become more complex and safety require-ments 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.

Contact informationNeuer Weg-Nord 49D-69412 EberbachPhone: +49(0)6271 806 500Fax: +49(0)6271 806 476Email: [email protected]: www.coopercrouse-hinds.eu

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HYDROCARBON PROCESSING TURNAROUND AND MAINTENANCE 2011 I T-57

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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

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 over-come middle management resistance to change, stalling their recommendations and approvals before actual piloting.

Under director level leadership, a major engineering department (approximately 1,500 engineers) evaluated the engineering-lean potential to increase throughput at about 25% with corresponding project cost reduction. Under pressure from the team’s lean recommendation and client dissatisfaction, the VP of engineering said, “We recognize the value, but we have a lot of things on our plate right now. We think you are about a year ahead of when we can do this.”The VP of engineering had been personally responsible for most of the systems currently in use. In the face of overwhelming evidence presented by his team investigating lean, he could not deny the benefits, so, he did the next worst thing: admitted the need, but delayed implementation, after all, the clients keep paying the bills. Although resistance was natural, the lack of executive leadership was also evident and a profound disap-pointment to the team.

Under the author’s guidance, foremen and construction managers at a major engineering, procurement and construction (EPC) contractor site, quantified the impact of and opportunity for construction-lean (see partial results in Fig. 2). The EPC team proceeded to improve many things within their control; then, they solic-ited the client to achieve the really profound savings through improved planning during design. The issue involved the EPC aligning seven chemical plant operating divisions during FEL to improve reliability.

The Client declined involvement in the face of profound opportunity to improve the root cause of poor planning—i.e., late client information and changes. Client leadership-of-change among the seven divisions was lacking. Client middle man-agers resisted the necessary alignment—although senior management was crying from the profound losses.

Our recently published handbook1 presents many examples of substantial improvements and serious root causes in recent multi-bil-lion dollar losses and explains the processes that created the improvements and could have prevented the losses.

The authors’ bring the reader a rapid improvement discipline with the means for operational trust and meth-ods of profound leadership. To do so, we have integrated experience implementing lean, six sigma, theory-of-con-straint and quality-function-deployment, etc., to enhance value-improving practice and constructability principles and methods. The former are not yet formally deployed on most large facility delivery projects and programs.

Sustained, market excellence. Typi-cally, we have found improved standards are a good starting point and the foundation enabler of excel-

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 improv-ing 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.

Creating a foundation of sustained excellence. What separates a good project from a poorly executed one? Some factors include:

• Sub-task level work process standards depict engineering and management expectations regarding the specifics of what will be done, how, by whom and in what sequence to achieve desired measurable results during actual circumstances faced by employees.

• Lean work process standards are derived with performance measures estab-lished to provide just what is needed for those doing the job to consistently enable best practice. Subdividing tasks (e.g., sub-task size to a single deliverable) must be sufficient to assure each sub-task-lead has everything they need to start, execute and deliver what is needed without ever stopping. Sub-task sequencing extends the planning to include all active sub-tasks in the current week to four-week execution window.

• Lean management by standards requires both policy deployment (calling for commitment to the standards by the leadership responsible to execute them) and actual progress of each active task at the workface to be visible to manage-ment. If any standard does not cause the right things to happen, consistently and reliably, then it is not considered lean. The team must improve: the standard, and/or the standard’s deployment policy, and/or workface progress visibility, until the right things happen.

It is now evident that the team should perform nearly everything in engineering, construction and business according to the best work process standards or their equivalent by some other name (e.g., norms). Teams should define standards jointly, led by those who are responsible to manage and must include those who perform inside the company or within their supply and subcontracting chain.

Short of doing all the work themselves, standards are, in fact, the best way that engineering discipline leads or management at each level can effectively assure

Designbasis Project proposal

Detailed design

Bid

WRL

P

ERA

MC OS

ERA

MC OS

Detailed design

Procurement fabrication and delivery

Procurement fabrication and delivery

Construction Startup

Construction Startup

Traditional project

Designbasis

Systemcriteria

Componentcriteria

ConstructionPlanning

Lean project delivery

FIG. 1. Major oil company assessment of lean impact on traditional project delivery engineering release approval (ERA), mechanical completion (MC), onstream (OS), waste reduced lean procurement (WRLP).

T-58 I TURNAROUND AND MAINTENANCE 2011 HydrocarbonProcessing.com


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. Tradi-tional 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

for balanced progress of every available workface, management eliminates sub-stantial 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 transpar-ency 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 man-agement 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 perfor-mance 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, sharehold-ers 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

Effective setup 13.5%

Safety work, 3.8%Rigging and flagging, 1.3%Inspection and testing, 0.5%Material and equipmentloading, unloading andstorage, 1.6%Clean up, 3.2%Maintenance andrepair, 1.0%Personal time, 1.3%Move self, 8.9%Move tools andmaterials, 14.8%Locating andpositioning, 2.2%Holding materials orequipment, 0.4%

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

Dismantle, 1.9%Fabrication andpre-assembly, 5.8%Excavating andbackfilling, 2.8%Final assembly, 11.4%Placing, 0.4%

Directvalueaddedwork

35.8%

Direct value addedwork 35.8%

Direct value addedwork 35.8%

Contributory work 39%

Contributory work 39%

Cont

ribut

ory

wor

k 39

%

Non-contributory, waiting andnon-value added work 25.2%

Non-contributory, waiting andnon-value added work 25.2%

Non-

cont

ribut

ory,

wai

ting

and

non-

valu

e ad

ded

wor

k 25

.2%

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

HYDROCARBON PROCESSING TURNAROUND AND MAINTENANCE 2011 I T-59


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 cul-ture, 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 experi-ence 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 Shin-gijutsu 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, environ-mental 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 success-ful 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 contract-ing. 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.”

• 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

LITERATURE CITED 1 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. 2 Ibid. pp. 66–69 3 Ibid. pp. 14–26 4 Ibid. p. 479 5 Ibid. pp. 54–61 6 Ibid. Acknowledgements, pp ix–x 7 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 implementa-tions on major capital projects in the US, Canada, Venezuela and Nigeria. Reach by [email protected].

Michael A. Denton holds MS degrees in petroleum engineer-ing and economics. Currently, he is senior appraisal reservoir engi-neer 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 leader-

ship 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.

■ Profound leadership is required to achieve

profound rapid improvement

60 I TURNAROUND AND MAINTENANCE 2011 HydrocarbonProcessing.com

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What are the ‘magnificent seven’ elements 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

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 main-tenance 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.

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 cre-dentialing 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

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

3. Right equipment for the job. Often underestimated, the 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 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.

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.

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TURNAROUND AND MAINTENANCE 2011 I 61

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 moni-tored, 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, hazard-ous waste handling, Mine Safety and Health Administration procedures, and a confined-space program.

5. Access to spare parts and equipment for unfore-seen 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.

6. Constant communication with plant management. Upon completion of a project, few plant managers like surprises such as unex-pected, 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

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

Michael McMahon is president of Coating Systems, Inc. (CSI), Savannah, 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.

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TURNAROUND AND MAINTENANCE 2011CORPORATE PROFILE: ALTAIRSTRICKLAND

ALTAIRSTRICKLAND has been managing and executing turnarounds and revamps since its inception in 1976. Meanwhile, refineries have become more con-gested 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 workThe 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 brac-ing 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.

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 workFor this major equipment installation, the client envisioned installing the com-

bustor 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.

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.

Contact information1605 S. Battleground RoadLa Porte, TX 77571Phone: 281-478-6200Fax: 281-478-6206E-mail: [email protected]: www.altairstrickland.com

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.

Mastering FCCU constructability issues




CWFC offers comprehensive products and services for the oil and gas industry

CORPORATE PROFILE: CURTISS-WRIGHT FLOW CONTROL

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 associ-ated 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 com-plete 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 inte-grates 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 proj-ect, 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 engi-neering 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 Explo-ration 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 hydro-carbon processing, refinery, petrochemical, gas production and processing markets.

Farris Engineering Services provides patented, web-based iPRSM® software, a powerful engineering calculation and documentation repository tool, assists pro-cessing 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, petrochemi-cal, chemical and process industries.

Contact information16315 Market StreetChannelview, Texas 77530Website: www.cwfc.com

Dunn operates its own fleet of specially designed tractor-trailers 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.

Dunn’s licensed Bake-Out-Oven thermally decomposes 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.

Dunn is a fully certified ASME code facility offering both repair and new fabrication 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.

Thermal Cleaning & Wastewater Treatment Decommissioning and Disposal

New Fabrication ASME U Certified Repair Certified ASME R Stamp

Safe Transportation High Pressure Hydro Cleaning

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.

281-337-1222 409-948-1704

410 21st Street SouthP.O. Box 3028Texas City, TX 77592-3028Houston: (281) 337-1222 (24 Hrs) Texas City: (409) 948-1704 (24 Hrs)Fax: (409) 945-9873

l d k h ll dDunn’s licensed Bake-Out-Oven thermally decomposes

Thermal Cleaning & Wastewater Treatment

f ll fi d d f l ff b h d f bDunn is a fully certified ASME code facility offering both repair and new fabrication 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.

New Fabrication ASME U Certified Repair Certified ASME R Stamp

281-337-1222 409-948-1704




Critical Path Performance = Success

CORPORATE PROFILE: DUNN HEAT EXCHANGERS, INC.

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 plan-ning 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 treat-ment 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

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 stan-dards and guidelines for liquid and solid waste treatment and disposal.

For additional information contact Dunn Heat Exchangers.

Contact information410 21st Street SouthTexas City, TX 77590Phone: 409-948-1704281-337-1222Fax: 409-945-9873Email: [email protected]: www.dunnheat.com

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

Microtherm is THE choicefor low thermal conductivityinsulation in hightemperature applications.

www.microthermgroup.comMicrotherm Inc. +1 865 681 0155Microtherm NV +32 3 760 19 80Nippon Microtherm +81 3 3377 2821

0.000 0.020 0.040 0.060 0.080 0.100 0.120 0.140 0.160

Mineral Wool

Ceramic Fiber

Calcium Silicate

Aerogel

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

Microtherm - Truly the Best Performance at High Temperatures

MICROTHERM®

Data Per ASTMTesting Standards

C1676ASTM Standardfor Microporous

1450 °F

Internal

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

Equivalent Personnel Protection• 3” of Microtherm MPS over 6” NPS• 127 °F Cold Face (

228 BTU/ft•hr Heat Loss (51% less)•

11 °F lower)•

Save Space, Weight, & Energy!

Equivalent Volume• 3” of Microtherm MPS over 12” NPS• 132 °F Cold Face• 380 BTU/ft•hr Heat Loss (18% less)•

(6 °F lower)

Increased Production 400%!

Equivalent Heat Loss• 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!

Optimize Your Process with M MICROTHER®



TURNAROUND AND MAINTENANCE 2011CORPORATE PROFILE: MICROTHERM

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 insu-lation 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 radia-tion. 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 ther-mal 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. Micro-therm 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 (Micro-therm 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

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 petro-chemical 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 information3269 Regal DriveAlcoa, TN 37701Microtherm Inc. +1 865 681 0155Microtherm NV +32 3 760 19 80Nippon Microtherm +81 3 3377 2821E-mail: [email protected]: www.microthermgroup.com

Microtherm Slatted Panels installed on a vessel.

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.

O U R E N G I N E E R I N G A T R E N T E C H C R E A T E S

For more information, email us at [email protected] us online at WWW.RENTECHSERVICES.COM

or call us at 325.672.2900

Boiler Services, Inc.RENTECH



TURNAROUND AND MAINTENANCE 2011CORPORATE PROFILE: RENTECH BOILER SERVICES

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 controlSince 1997 RENTECH has provided quality products and services, including

superheaters, economizers, sulfur condensers, burner and CO/SCR system retro-fits, 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 ser-vice 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.

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 information5025-C Highway 80Abilene, TX 79601Phone: 325-672-2900E-mail: [email protected]: WWW.RENTECHSERVICES.COM

Not all boilers are rebuilt equally

SPX Flow TechnologyTel: | 800 | 344 | 2611Email: [email protected]

Filtering Everything

Since 1921 Dollinger has stood at the forefront of fi ltration technology, serving a vast range of industries around the world with a wide breadth of service and scope of products.

Air Intake Filter Systems - Multistage - Pulse Jet [self-cleaning]

- Inertial spin [maintenance free]

High Effi ciency Filter Panels & Cartridges

Oil Mist Eliminators

Lube Oil Filter Systems

that Flows through Industry



TURNAROUND AND MAINTENANCE 2011CORPORATE PROFILE: DOLLINGER FILTRATION

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 prod-ucts 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 exper-tise 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, Process-ing 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 special-izes 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 pro-ducing 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

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 information4647 SW 40th AvenueOcala, FL 34474-5788Phone: 800-344-2611Fax: 800-263-4788E-mail: [email protected]: www.dollinger-spx.com or www.spxft.com

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.

TURNAROUND AND MAINTENANCE 2011CORPORATE PROFILE: VOITH

T-74 I TURNAROUND AND MAINTENANCE 2011 SPONSORED CONTENT

World-class in turbo gears and serviceVoith 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 strin-gent 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 informationHans-Boeckler Strasse 7, 87527 Sonthofen, GermanyNew business +49 (0)8321 802-502Service +49 (0)8321 802-555Fax: New business +49 (0)8321 802-685Fax: Service +49 (0)8321 802-545E-mail: [email protected] or [email protected]: www.bhs-getriebe.com or www.bhs-gearbox-service.com

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

Service for Unparalleled Gearbox Performance

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

Voith Turbo BHS Getriebe GmbHSonthofen / Germany

www.bhs-getriebe.com

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Service Technician Herbert Kuisle


PLANT SAFETY BONUSREPORT


Process safety: Blind spots and red flagsImproving 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-84.00.01-2004 Part 1 (IEC 61511-1 Mod). Both pro-vide 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 inter-dependent 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 hid-den 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 high-lighted. “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 acci-dent. Those discussed here have hid-den or unforeseen mechanisms that can degrade an SIS or a safety management program. Independent protection layers (IPLs) applied to reduce risk are methodi-cally 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 asso-ciated hazard consequence and likelihood are unknown.

Project execution. Today’s typical large-scale engineering projects have major teams that interact with many organiza-tions and companies. In a relatively short time, they generate thousands of docu-ments 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. Sched-ule compression tends to increase error rates and challenge the quality-check pro-cess. 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 techni-cal 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 per-son 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.

Bypass,reset,

manualESD

Standardsdefinitions

SISarchitecture& interfaces

Valve failure modeProcess responsetime, trip settings

Validationresults

Make &model

SISarchitecture

& loopdesign

Equipment,diagnostics,

standardarchitecture

Approved vendor listproject design standards

Application software SRS,detailed design definition

Action list, validation statusSIF design & status, required

diagnostics minimum testfrequency, auto-generated

test procedures

SIL calculationstest & inspection

results

Target SIL & STRTarget test intervals

Vendor reliability data

SIFrequirements

SIL & STR targets

Test & diagnosticreq’mts, SIF change

to meet SIL

Fn safetyplan

SISschematicdiagrams

P&IDs,process

engr.

Validation

Reports

SRS

Designreq’mts.

Instr.data

sheets

SIS & SIFloop

design

SIL calcs.& studies

LOPAreport &

F/U

Safety requirements specification (SRS). FIG. 1

PLANT SAFETYBONUSREPORT


startup involves handoffs of many docu-ments and status reports—all opportunities for missed information.

Safety assessments. Safety assess-ments 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, exother-mal 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, instru-ment air or cooling water.

A safety related alarm applied as an IPL may be invalid. This can occur if an opera-tor cannot reliably respond to the alarm within the process response time (pref-erable 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 possibil-ity. Finally, if the alarm is invalid, then the SIL assigned to an associated safety instru-mented function may be insufficient.

Technology. New technology and new designs often create unforeseen “challenges.” When the industry embraced open sys-tems, the Microsoft Operating System became a standard component in many control systems. The unforeseen risk was an ongoing urgency to install frequent soft-ware “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

upgrades often have subtle and undocu-mented technical and performance differ-ences. Implementing a change before it is fully tested introduces an unknown risk.

If a facility’s software backup and recov-ery procedures are inadequate or not fol-lowed, then the wrong program or an out-dated version may be loaded in response to an unplanned emergency repair. Inad-equate physical and administrative control of an engineering work station connected to a safety system can compromise system integrity. Sensitive process control net-works, thought to be isolated, may, in fact, connect to a business network or unpro-tected Internet connection and become a tempting target for computer hackers worldwide. Cross-connection of a process-control system network to a business enter-prise network opens the opportunity for a control system interruption or upset that may be caused by a routine business net-work administrative change or update.

High-integrity pressure protective sys-tems (HIPPS) are increasingly being used to reduce project cost or increase produc-tion. A well-designed and managed HIPPS offers safety benefits, but is also a “high-tech” solution that replaces a low-tech solu-tion 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 high-consequence 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 inte-grates 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 reli-ably. 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 oper-ate.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 avail-able to mitigate or manage a hazard that was previously unknown and has no other safeguards.

Organization. High-performance organizations of the type needed to man-age 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 inter-acts 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 instru-mented 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 organiza-tional boundaries.

If the group charged with managing a PSM program operates like a regulatory organization, then the expected safety man-agement culture and practices are probably not being fully realized, although “full com-pliance” 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.



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 through-put. Others may operate a fired process heater when a forced draft fan has failed. A damper is opened and the heater is oper-ated in a natural draft mode that was not considered in its original design. An opera-tor 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-the-books repairs and undocumented soft-ware 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 pro-duction) 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 under-standing 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 fol-lows 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 assess-ment 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 investi-gations 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 common-place) are not aware of where the true weak-ness in their systems exists, so similar acci-dents may reoccur.

Management and leadership. All organizations, whether they are proj-ect teams or operating facilities, face the dichotomy of balancing process safety with production, cost and schedule demands. By words, actions and exam-ples, management and safety leaders demonstrate their expectations. Subordi-nates interpret this message and bias their actions and attitudes accordingly. Given the challenges of communications in large and complex organizations, a few misun-derstood words or an ambiguous or con-flicting 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 unit-shutdown 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 produc-tion. A downsizing that lays off a key tech-nical expert who provides maintenance support for a highly technical safety sys-tem, places that system at risk. Manage-ment 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 chal-lenge may be a serious blind spot.

Red flags. Several blind spot modes have been discussed. Many others exist, includ-ing training, standards and procedures, physical environment and regulatory envi-ronment, 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 accep-tance that blind spots exist are essential. Another important element in a safety management program should include an awareness of the red flags that often pre-cede 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 hap-pen (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 Disas-ters)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

LITERATURE CITED 1 Perrow, C., Normal Accidents: Living with High- Risk Technologies, New York, Basic Books Inc., 1999. 2 Shephard, T. and D. Hansen, “IEC 61511 Implementation—The Execution Challenge,” Control, May 2010. 3 Bullemer, P. and D. Metzger, “CCPS Process Safety Metric Review: Considerations from an ASM Perspective, ” ASM Consortium Metrics Work Group, May 23, 2008. 4 Bartels, N., “Worst Fears Realized,” Control Engineering, September 24, 2010. 5 Decker, S., The Field Guide to Understanding Human Error, Surrey UK, Ashgate Publishing Ltd., Reprint 2010. 6 Brigadier Gen. Duane W. Deal, USAF, “Beyond the Widget: Columbia Accidents Lesson Learned Affirmed,” Air & Space Power Journal, Summer 2004. 7 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 automa-tion project manager at Mustang Engineering. He has 28 years of con-trol 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.



Consider new design criteria equipment modulesConstruction offers cost-effective protection of critical systems

D. COLE and D. AUSTIN, Lectrus, Chattanooga, Tennessee

The January 2011 HP article, “Considerations for blast-resistant electrical equipment centers,” focused on the his-tory, background and key considerations of blast-resistant

modules (BRMs) and blast-resistant electrical equipment centers (BRECs), designed to protect personnel and vital electrical con-trols, respectively. The article outlined the benefits of utilizing pro-tective 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 occupa-tional 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 engi-neering of facilities, hazard assessments, management of change, inspection, testing and maintenance of equipment, effective alarms, effective process control, procedures, training of person-nel 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-resis-tant 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 impor-tant 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 equip-ment, 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 con-struction types—two being of interlocking steel-panel construc-tion and the third utilizing fully welded, crimped steel plate. Now a verifiable revolution in the industry, the use of interlocking steel-panel construction for BRECs addresses both cost-effectiveness and critical-protection factors.

First considerations. As discussed previously, the most desir-able location for electrical equipment centers at HPI plants is as close to the processing operation and maintenance personnel as

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

FIG. 1



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 equip-ment 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 side-on 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 construc-tion trailers positioned within the blast zone, and, in fact, trailers

nearly 1,000 feet from the blast-area center sustained damage to varying degrees.

Table 1 describes three levels of blast pressure damage on build-ings in HPI facilities subject to blast loads. As information, the terms damage level and response level are often used interchange-ably, 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 cen-ter 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 compo-nent 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

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.

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

FIG. 2



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 destruc-tive Texas City blast load). Validations were performed to com-pare the FEA results to the SDOF model’s results and verify the SDOF calculations.

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 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 pres-sures 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 speci-mens 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

TABLE 3. Shock tube test results

Peak applied Equivalent right Peak applied Peak dynamic test pressure triangular peak impulse Duration deflection ObservedSpecimen Test Panel type Screw size 1.2 (psi) pressure (psi) (psi-ms) (ms) (in.) damage level

A 1A 16 in. wide, 3 in. deep, 16Ga G90 #10 0.9 0.8 26 58 None visible Low

A 1B 16 in. wide, 3 in. deep, 16Ga G90 #10 2.8 2.4 97 69 5.5 High

B 1B 12 in. wide, 4 in. deep, 12Ga G90 #10 3.4 2.6 167 98 0.75 Low

B 2B 12 in. wide, 4 in. deep, 12Ga G90 #10 5.3 4.3 213 80 1.5 Low

B 3B 12 in. wide, 4 in. deep, 12Ga G90 #10 6.8 5.4 290 85 4 Medium

C 1C 12 in. wide, 4 in. deep, 11Ga G90 .25 in. 7.6 5.9 314 83 2 Low

C 2C 12 in. wide, 4 in. deep, 11Ga G90 .25 in. 8.5 6.2 462 109 4 Medium

D 1D .25 in. crimped plate N/A 6.8 5 277 81 2.5 Medium

D 2D .25 in. crimped plate N/A 12 8.7 755 126 7 High

E 1E 3 equipmet n doors N/A 4.4 4 114 52 N/A Doors remained attached

00 50 100 150 200 250 300 350 400 450 500

1

2

3

4

5

Side-on pressure-impulse diagram for 2.7-mm wall panels.FIG. 3

Half-symmetry building model.FIG. 4



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 set-up 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 con-structed 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 analy-ses 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-dura-tion 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 con-ducted 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-, medium- or 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.

Panel damage level. Support rotations were also used in determining the panel damage/response levels. The maximum dynamic deflection of each component was calculated provid-ing the ranges used in the three damage/response levels shown in Table 2.

Each component was also analyzed for various P-i combina-tions 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

3 in.

Interior wall

Exterior interlocking wall panels 3 in. fiberglass insulation

Typical interlocking wall panel section.FIG. 5

Interior panel2 in. x 1 in. formed channel

3 in. fiberglass insulationExterior crimpedplate wall panels

1 in. – 4 in. 21⁄8 in.315⁄16 in.

43⁄8 in.

10 in.7 in.

45° 3 in.

Typical crimped plate, seam-welded wall section.FIG. 6

TABLE 4. Effective side-on pressure ratings

Low response Low response Medium response Medium response High response High responseSpecimen/ limiting limiting limiting limiting limiting limitingConstruction applied load side-on load applied load side-on load applied load side-on loadtype Panel type (psi, psi-msec) (psi, psi-msec) (psi, psi-msec) (psi, psi-msec) (psi, psi-msec) (psi, psi-msec)

A/Type I 16 in. wide, 3 in. deep, 0.8, 26 0.4, 13 — — 2.4, 97 1.2, 47 16 Ga G90

B/Type II 12 in. wide, 4 in. deep, 4.3, 213 2.0, 101 5.4, 290 2.5, 136 — — 12 Ga G90

C/Type II 12 in. wide, 4 in. deep, 5.9, 314 2.8, 147 6.2, 462 2.9, 215 — — 11 Ga G90

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



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 pres-sures 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 penetra-tion 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 con-struction 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 half-symmetry 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 compo-nents. 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,

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 retrofit-ted 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

BIBLIOGRAPHYCole, D., R. H. Bennett and D. Austin, “Protecting Essential Refining Operations Using Blast-Resistant Electrical Equipment Shelters,” IEEE- PCIC-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. 01-1958-001- 07, 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.Interior and exterior wall panels used in physical test

phase.FIG. 7

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

FIG. 8

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 enclo-sures. Mr. Cole also represents Lectrus on various technical and

industry associations, including IEEE. He graduated from North Carolina State Uni-versity 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 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 Insti-tute of Electrical and Electronics Engineers and holds a BS degree in civil engineering from Bucknell University.



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 Home-land Security (DHS), the Chemical Facility Anti-Terrorism Standard (CFATS) was cre-ated 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 petrochemi-cal industries. It also includes sectors such as chemical manufacturing, storage and dis-tribution, 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 Mari-time 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 treat-ment 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 chemi-cals 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 han-dling 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 dis-close 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 obvi-ously change from site to site, but tier rat-ings 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 facil-ities. 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 man-date 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 authoriza-tion inspection by the DHS. This inspec-tion 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 person-nel to make sure that they are who they appear to be.

Theft and diversion gets a little murkier. Here we are talking about stealing chemi-cals to create chemical weapons including



homemade bombs, explosives, gas bombs and improvised explosive devices (IEDs). Again, stealing is pretty straightforward and that threat affects almost all CFATS facili-ties. 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 decep-tion. 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 com-pany operates until the credit runs out.

Co-opted customer—An existing cus-tomer 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, some-one pretending to be a professor at a uni-versity or college chemistry department places an order.

Cyber attack on business manage-ment system—The network or computer system is hacked into and a reoccurring delivery is scheduled and hidden.

Sabotage or contamination of materi-als is another concern driving the CFATS mandate. Chemicals that release toxic gases when exposed to water, fall into this cat-egory. So businesses have to not only be concerned about someone stealing or tak-ing 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 happen-ing. It takes a careful review of your facil-ity and its business processes, along with knowledge of the security options available.

CFATS just celebrated its fourth birth-day. Those four years have been a learn-ing process and, as the DHS has acknowl-edged, the department is learning with the industry. It has been a strong collaborative process with the usual snags and disagree-ments. 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 assign-ment 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 compa-nies by making preauthorization inspec-tions. 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 direc-tion 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 peo-ple. Another area is material modification. The DHS has acknowledged that com-panies 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 Sen-ate 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 amend-ment from Senator Susan Collins, Repub-lican-Maine.

HR 2868 was introduced by Repre-sentative Bennie Thompson, Democrat-Mississippi and was passed by the House in November. That version of the bill included an inherently safer technology (IST) provi-sion. The chemical industry is opposed to this provision because it is open to inter-pretation and it could be costly, especially

for smaller facilities and businesses. The Collins amendment removes this provi-sion from the bill and adds several other elements, including:

• Creating voluntary exercise and train-ing 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 Col-lins amendment included. The National Association of Chemical Distributors (NACD), the Society of Chemical Manu-facturers and Affiliates (SOCMA) and oth-ers have come out in its support.

Still, the bill has to make it to the Sen-ate 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 elec-tions 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 facili-ties 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 seri-ously. The CFATS mandate is not meant to be an additional burden to business, but to ensure that we are protecting our com-munities and our businesses. HP

Ryan Loughin is the director of Petrochemical and Energy Solutions for the Advanced Integration division of ADT (www.adtbusiness.com/petro-chem). 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 Associ-ates (SOCMA), American Chemistry Council (ACC), the Energy Security Council (ESC) and the American Society for Industrial Security (ASIS). Mr. Loughin has also com-pleted multiple levels of Chemical-Terrorism Vulnerability Information (CVI) which was authored by the US Depart-ment of Homeland Security.

INSTRUMENTATION


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 instru-ments 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 segregat-ing cables—are all too often dependent on manual, tabular data input, which is time-consuming, 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 technolo-gies fail to meet engineers’ and design-ers’ requirements. These are the top-10 headaches that the engineers and design-ers face on a daily basis. The good news is that companies can avoid these headaches entirely by deploying the “visual engineer-ing” approach—a field-proven instrumen-tation solution.

TOP-10 HEADACHES

No. 1.—Wasted time and lost pro-ductivity. 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 likeli-hood of human error—this is the way that

most instrumentation software systems cur-rently work. For too long, software ven-dors 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 prohibi-tive. Configuring them is a major spe-cialist undertaking, and their operation constrains engineers to work in ways that are counter-intuitive and labor-intensive. Wasted time and money, and lost produc-tivity, are the results.

This new program delivers simplicity, to fit closely with the way that engineers

and designers naturally work. As an exam-ple, Fig. 1 shows how a simple graphical user interface in a wiring manager module enables the user to route and reroute wir-ing—and manage all associated changes—in a few clicks of the mouse. Straightfor-ward customization enables configuration by users without any need for program-ming skills. In short, this is a complete change to the way in which instrumenta-tion 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

Avoid these top-10 instrumentation headachesVisual engineering program solves designer and engineer issues across the industry

D. GIBSON, AVEVA, Cambridge, England

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

FIG. 1

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 manage-ment. While the creation of data is abso-lutely key to the early momentum of a proj-ect, 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 con-nections are added to the plan than were originally envisaged, swelling the data considerably and producing a significantly altered design. This complicates the rela-tionships between existing and new infor-mation, forcing a time-consuming and costly estimate revision process.

The instrumentation program comprises three integrated modules that share a com-mon, multi-user database for both design and as-built data. This integrated data envi-ronment enables extensive validation pro-cesses, automatic cross-referencing and link-ing 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 termina-tions—yet many technologies currently available on the market are unable to inte-grate these procedures into one applica-

tion. The wiring designer has to coordinate design data manually between several dif-ferent 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 pro-gram, 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 dia-grams, 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 instrumenta-tion and control universe. Yet they are often an essential way of managing and reducing procurement costs, and so can heavily influ-ence the economic viability of a project.

For example, the purchasing depart-ment might decide on a different supplier for a particular component, causing a change in the nomenclature of that compo-nent and the associated vendor details. The problem comes when these changes are not

accurately reflected across the whole proj-ect—which they rarely are. This can neces-sitate 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 prod-uct from vendor Y, identified by a differ-ent 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, ter-mination diagrams, cable schedules, bill of materials, etc. Mismatches between cata-logue 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 spe-cially requested and produced—an unnec-essary 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 interre-lationships 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 report-ing 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 technology is key to effective instrumenta-tion design—the application’s scalability is directly related to the efficiency of the data-base. Unfortunately, some vendors have taken excessive advantage of this depen-dency. While their application upgrades are usually delivered at no further cost, the

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

FIG. 2

INSTRUMENTATION

87

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 scalabil-ity should deliver.

No. 7.—Vendor data breakdown. Like all engineering processes, instrumen-tation and control are dependent on com-ponents provided by a range of suppliers. Approaching vendors for datasheets on the components they provide is often a hit-and-miss process—the information returned can be incomplete and is typically sup-plied 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 adminis-trated, manually followed up when neces-sary, and manually linked to the data in the main design system. Any two or more indi-viduals, 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 instru-mentation 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 dif-ficult 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 dif-ferent 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 impossi-ble 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 protect-ing 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-

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 cre-ation of datasheet templates within the

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

FIG. 3

Quest Integrity Group is a dynamic company built on a founda-tion 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 com-panies in the refi ning and chemical, pipeline, syngas and power industries increase profi tability, reduce operational and safety risks and improve operational planning.

(888) 557-3363(888) 893-7030

[email protected]

Asset LongevityPlant & Pipeline Performance


INSTRUMENTATION

88 I MARCH 2011 HydrocarbonProcessing.com88

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 data-sheet 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 gener-ated instantaneously. Greater control, less rework and enhanced safety and compli-ance, 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 typi-cally 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 unsatisfac-tory 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 engi-neers need a different way of bringing authority to their requests for information.

The instrumentation program provides object-based navigation through hyper-links. Related items of data are linked together automatically, no matter what for-mat they are in or where they are physically

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 informa-tion (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 col-league 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 achiev-ing initial traction. However, the data typi-cally 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 pro-cess, 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 infor-mation at their fingertips in a way that is dynamically managed and updated across the life of the project. HP

The Planning Guide to Piping Design

By Richard Beale, Paul Bowers and Peter Smith

300 pages Hardcover Pub date: September 2010 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.

Advanced Piping Design

By Rutger Botermans and Peter Smith

250 pages Hardcover Pub date: May 2008 Price: $175

ISBN: 978-1-933762-18-0

An intermediate-level handbook covering guidelines and procedures on

process plants and interconnecting piping systems.

The Fundamentals of Piping Design

By Peter Smith

262 pages Hardcover Pub date: April 2007 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.

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

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 engineer-ing 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 manage-ment qualifications from the Open University.

ENGINEERING CASE HISTORIES


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 draw-ings for a pilot reactor were being reviewed. The design had been modified from an orig-inally 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 foul-ing 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 propel-ler 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 veri-fied the simple analysis. Computational fluid dynamics (CFD) is an analysis tool that can analyze laminar and turbulent flows. While three-dimensional analy-ses with swirl are possible, a simple two-dimensional analysis is applied here to add information not available from the analyti-cal 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 inter-esting results. In Fig. 2, the velocity is going up the reactor main tube (15 ft/sec) and dis-tribution 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 distrib-uted, 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

Case 61: Pressure loss in a reactorMuch information is available from a simple analysis

T. SOFRONAS, Consulting Engineer, Houston, Texas

Dr. Anthony (Tony) Sofro-nas , PE, was worldwide lead 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.

Dead space

Head

CFlowup

Maintube

Pump

D

Reactor flow with head installed. FIG. 1

Velocity in reactor 1-in. gap.FIG. 2

Velocity in reactor 3-in. gap. FIG. 3


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LORAINE A. HUCHLER, CONTRIBUTING EDITOR

HPIN WATER MANAGEMENT

[email protected]


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 tempera-ture 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 protec-tive against corrosion.

Passivation decisions. Passivation of newly fabricated car-bon steel heat exchangers is so important that it should be a non-negotiable part of start-up. Plants may choose to conduct passiv-ation 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 passiv-ation 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 solu-tions 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 re-deposition 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, tem-perature, foam and soluble iron concentration1

• Storage of new heat exchangers requires special consider-ations to minimize in-situ corrosion.

In summary. Proper pre-cleaning and passivation procedures 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 site-specific 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].

Passivation in cooling water circuits

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 proce-dures. The cooling water exceeded the recommended maxi-mum 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.

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