HP_2010_05 by androsov.info

MAY 2010

HPIMPACT

SPECIALREPORT

TECHNOLOGY

Underground gas storage

MAINTENANCE and RELIABILITY

Establishing effective safety representatives

Oil supply emergencies

Methods for greater equipment reliability

Implementing a suitable SIS

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MAY 2010 • VOL. 89 NO. 5 www.HydrocarbonProcessing.com

SPECIAL REPORT: MAINTENANCE/RELIABILITY

Flow-induced fatigue failure in tubular heat exchangers

Purging and inerting large-volume tankage and equipment—jet mixing concept—Part 1

Case histories describe a variety of failures and solutions A. Babakr, T. Ashiru and C. Westhuizen Cover Photo courtesy of Mieko Mahi, www.energyimages.com.

Here are the advantages and disadvantages of the various methods M. Gollin

Heat-exchanger failure analysis in a naphtha cracking unit This case history analyzed the failure and makes recommendations to prevent future failures M. Sababi, M. Mazuchi and S. A. Monemian

Oil-mist lubrication for fin-fan shafts Tests show it is superior to grease lubrication P. W. Duncan

PETROCHEMICAL DEVELOPMENTS

Fundamental changes coming in Asia’s petrochemical industry Massive new processing additions will impact operations in this region as well as in the global market P. Kumar and L. Zhang

HPIMPACT 15 Underground gas storage on the rise 15 Responding to oil supply emergencies 16 Refiners in a tough market 19 Medium voltage motor drives sales projected to decline in 2010

PLANT SAFETY AND ENVIRONMENT

Establishing safety representatives who are effective Follow these protocols for a safer workplace G. Alevizos

PROCESS DEVELOPMENTS

Consider CFD analysis to support critical separation operations This modeling method can help eliminate chronic problems caused by feed mal-distribution and poorly designed feed devices D. Remesat, Z. Riha and Koch-Glitsch Global Refining Application Team

PLANT DESIGN AND ENGINEERING

Strategize preshutdown work to enhance productivity Adopt these principles from a refinery revamp project A. Kumar

INSTRUMENTATION/SAFETY

Implementing a suitable safety instrumented system—Part 1 The analysis is the most important step for engineering and designing a suitable system R. Modi

SULFUR SOILUTIONS 2010—SUPPLEMENT

Sulfur Solutions 2010 Technological developments cost-effectively manage sulfur in various forms

ENGINEERING CASE HISTORIES

102

Case 56: Quick troubleshooting of shaft failures Some simple calculations can guide the way to improved performance T. Sofronas

DEPARTMENTS 7 HPIN BRIEF • 13 HPIN ASSOCIATIONS • 21 HPIN CONSTRUCTION • 24 HPI CONSTRUCTION BOXSCORE UPDATE• 98 HPI MARKETPLACE • 101 ADVERTISER INDEX •

COLUMNS 9 HPIN RELIABILITY Grounding-ring technology for variable-frequency drives 11 HPINTEGRATION STRATEGIES Procedural automation improves process plant performance 102 HPIN WATER MANAGEMENT What’s happening with the Legionella Standard?—Part 1

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www.HydrocarbonProcessing.com Houston Office: 2 Greenway Plaza, Suite 1020, Houston, Texas, 77046 USA Mailing Address: P. O. Box 2608, Houston, Texas 77252-2608, USA Phone: +1 (713) 529-4301, Fax: +1 (713) 520-4433 E-mail: editorial@HydrocarbonProcessing.com www.HydrocarbonProcessing.com Publisher Bill Wageneck bill.wageneck@gulfpub.com EDITORIAL Editor Les A. Kane Senior Process Editor Stephany Romanow Process Editor Tricia Crossey Reliability/Equipment Editor Heinz P. Bloch News Editor Billy Thinnes European Editor Tim Lloyd Wright Contributing Editor Loraine A. Huchler Contributing Editor William M. Goble Contributing Editor Y. Zak Friedman Contributing Editor ARC Advisory Group (various) MAGAZINE PRODUCTION Director—Editorial Production Sheryl Stone Manager—Editorial Production Angela Bathe Artist/Illustrator David Weeks Manager—Advertising Production Cheryl Willis ADVERTISING SALES See Sales Offices page 100. CIRCULATION +1 (713) 520-4440 Director—Circulation Suzanne McGehee E-mail: circulation@gulfpub.com SUBSCRIPTIONS

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If you would like to have a recent article reprinted for an upcoming conference or for use as a marketing tool, contact Foster Printing Company for a price quote. Articles are reprinted on quality stock with advertisements removed; options are available for covers and turnaround times. Our minimum order is a quantity of 100. For more information about article reprints, call Rhonda Brown with Foster Printing Company at +1 (866) 879-9144 ext 194 or e-mail rhondab@FosterPrinting.com. HYDROCARBON PROCESSING (ISSN 0018-8190) is published monthly by Gulf Publishing Co., 2 Greenway Plaza, Suite 1020, Houston, Texas 77046. Periodicals postage paid at Houston, Texas, and at additional mailing office. POSTMASTER: Send address changes to Hydrocarbon Processing, P.O. Box 2608, Houston, Texas 77252. Copyright © 2010 by Gulf Publishing Co. All rights reserved. Permission is granted by the copyright owner to libraries and others registered with the Copyright Clearance Center (CCC) to photocopy any articles herein for the base fee of $3 per copy per page. Payment should be sent directly to the CCC, 21 Congress St., Salem, Mass. 01970. Copying for other than personal or internal reference use without express permission is prohibited. Requests for special permission or bulk orders should be addressed to the Editor. ISSN 0018-8190/01. www.HydrocarbonProcessing.com

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HPIN BRIEF BILLY THINNES, NEWS EDITOR

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The International Electrotechnical Commission (IEC) has approved the WirelessHART specification as a full international standard (IEC 62591Ed. 1.0). The unanimous vote on March 26 by the IEC National Committees of 28 countries confirms the broad global support for WirelessHART technology as the international standard for wireless communication in process automation. “The overwhelming approval by IEC fulfills the request of users for a single international wireless communication standard that is supported by major automation suppliers,” said HART Communication Foundation Executive Director Ron Helson. “WirelessHART technology has been confirmed by both users and suppliers to be a technically sound, reliable and secure solution for wireless communication in process automation.” Released in September 2007, WirelessHART is an open and interoperable wireless communication standard designed to address the critical needs of industry for reliable, robust and secure wireless communication in realtime industrial process measurement and control applications.

The electric car revolution is upon us yet again. This time, the US federal government is leading the charge. The Obama Administration has announced plans to purchase the first 100 Chevrolet Volts produced by General Motors (GM). Last year, President Obama issued an executive order asking federal agencies to lead by example toward a clean energy economy. “Before the end of the year, we’ll purchase the first 100 plug-in electric vehicles to roll off American assembly lines,” a news release from the White House said. Since the US government is also the largest investor in GM, it makes sense for it to be the first customer. Other US federal agencies are also following the direction of Obama’s executive order by “purchasing hybrid instead of conventional cars and trucks that use more fuel; downsizing vehicle fleets overall; and requiring plugin electric charging stations for all new facilities and for major retrofits.”

Thailand’s efforts to bolster its energy production from biomass received a setback when it was revealed that AT Biopower is cancelling plans for a biomass-fired power plant project due to a shortage of feedstock. According to the company’s Website, its 22-MW biomass plant in Pichit, Thailand, needs at least 500 metric tpd of rice husks. Without enough supply to satiate the plant’s need, AT Biopower has had to call an audible and go in a different direction. Now it is looking to invest in small, solar projects that are capable of producing 2–3 MW each. Because of the biomass feedstock conundrum, Thailand may raise tariffs later this year on power generated from biomass to lessen the burden of high feedstock costs. Thailand is in the process of drafting an energy plan that would result in the country producing 3,000 MW of electricity from biomass by 2030. Current output is estimated between 700 MW and 1,000 MW.

Shell is reviewing ownership options for its downstream businesses in 21 countries in Africa. While a number of options are being considered, the preferred outcome is the sale of most businesses in scope as going concerns, subject to successful negotiations, and any necessary regulatory and final company approvals. Shell’s fuels, lubricants and refining activities in South Africa are not affected by the review. The company’s exploration and production businesses, liquefied natural gas interests and most international trading activities in Africa are also out of scope. “This decision is part of our drive to refocus our global downstream footprint into fewer, larger markets,” said Xavier le Mintier, executive vice-president for Shell Oil Products Africa.

CB&I’s ethylene cracker project in Singapore has been successfully started up, producing on-specification ethylene and propylene. The 800,000-tpy cracker increases Singapore’s ethylene capacity by 40% while also producing 450,000 tpy of propylene, 230,000 tpy of benzene and 155,000 tpy of butadiene. The ethylene cracker uses Lummus Technology proprietary ethylene cracking technology, and the butadiene extraction unit uses proprietary technology from BASF/Lummus Technology. HP

■ Fallout from Tesoro accident Tesoro Corp. has temporarily curtailed operations at its Anacortes, Washington, refinery by shutting down crude processing treating capacity involved in the recent explosion and fire at the refinery. Unit shutdowns began in mid-April. Six workers died as a result of the April 2 explosion. The early morning accident took place in the heat exchanger of the naphtha hydrotreater. The refinery has the capacity to process 115,000 bpd of oil, and, during the shutdown, Tesoro will meet supply obligations by relying on its other Western US refineries and possibly purchasing petroleum products on the spot market. Since the incident, the refinery has been producing primarily unfinished intermediate products that cannot be upgraded until the affected units have been returned to service or an alternate plan is developed. A four-member investigative team from the US Chemical Safety Board (CSB) was deployed to the scene of the explosion and fire at the refinery. The team said at the time that they may be able to construct a “chain of events” leading to the fatal explosion and fire within three to six weeks. As to how long a full investigation will take, CSB officials noted that it took the agency two years to fully investigate the 2005 explosion at the BP refinery in Texas City. Investigating this incident is likely to take just as long. “The CSB has 18 ongoing investigations,” said CSB Chairman and CEO John Bresland. “Of those, seven of these accidents occurred at refineries across the country. This is a significant and disturbing trend that the refining industry needs to address immediately.” Mr. Bresland said the large-scale deployment to Washington will further complicate efforts to complete other important cases, including the CSB’s investigations of the Caribbean Petroleum fuel terminal fire near San Juan, Puerto Rico; the CITGO refinery hydrogen fluoride release and fire in Corpus Christi, Texas; the Goodyear heat exchanger rupture and ammonia release in Houston, Texas; and the ExxonMobil refinery hydrogen fluoride release in Joliet, Illinois. HP HYDROCARBON PROCESSING MAY 2010

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

Repetitive pump seal failures can cause disasters Release No. 2004-08-I-NM (http://www.csb.gov), issued in October 2005 by the US Chemical Safety and Hazard Investigation Board, addresses an incident at an oil refinery with a history of repeated pump failures. Located in New Mexico, this facility’s total of three primary, electric and steam-driven spare iso-stripper recirculation pumps had 23 work orders submitted (Table 1) for repair of seal-related problems or pump seizures in the one-year period prior to a fire and explosion. The catastrophic incident occurred during disassembly on April 8, 2004 and caused over $13 million in damage. At least six people were injured and production at this alkylation unit was shut down for months. Lessons for those willing to learn. For many decades, truly reliability-focused organizations have avoided repeat seal failures by insisting on understanding and eliminating failure causes. They realize that collecting only the generalized failure descriptions of Table 1 would be analogous to a trucking company cataloguing repeated nonperformance as “engine problems.” More detail would be needed to implement sound remedial action. The reliability-focused also realize that when a seal failure combines with one or more other deviations from the norm, disasters result. More specifically, they make it their business to

TABLE 1. Pump work orders Sequence / date <> pump Problem 01. April 17, 2003 <> P-5A (Elec.) ..................................................... Seal leak 02. May 9, 2003 <> P-5B (Stm.)............................... Pump spraying from seal 03. May 23, 2003 <> P-5A (Elec.) ................................................. Repair seal 04. June 9, 2003 <> P-5B (Stm.) .................................................... Repair seal 05. June 9, 2003 <> P-5A (Elec.) .................................................... Repair seal 06. June 18, 2003 <> P-5A (Elec.) .................................................. Repair seal 07. June 20, 2003 <> P-5A (Elec.) .............................................Replaced seal 08. July 31, 2003 <> P-5A (Elec.) ...............................................Replaced seal 09. August 22, 2003 <> P-5B (Stm.) ................................................. Seal leak 10. August 25, 2003 <> P-5B (Stm.) ..........................................Replaced seal 11. September 26, 2003 <> P-5B (Stm.).....................................Replaced seal 12. September 26, 2003 <> P-5A (Elec.) ....................................Replaced seal 13. October 14, 2003 <> P-5A (Elec.) ............................................... Seal leak 14. December 6, 2003 <> P-5A (Elec.) .......................................Replaced seal 15. December 9, 2003 <> P-5B (Stm.)............................................... Seal leak 16. December 9, 2003 <> P-5A (Elec.) .............................................. Seal leak 17. December 15, 2003 <> P-5B (Stm.)......................................Replaced seal 18. December 15 2003 <> P-5A (Elec.) ............................................. Seal leak 19. January 28, 2004 <> P-5A (Elec.) ................................................ Seal leak 20. March 22, 2004 <> P-5A (Elec.) .................................................. Seal leak 21. April 1, 2004 <> P-5A (Elec.) ........................................ Pump seal leaking 22. April 3, 2004 <> P-5A (Elec.) ........................................ Pump seal leaking 23. April 7, 2004 <> P-5A (Elec.) ..........................................Repair pump seal

know what fit-for-service mechanical seals are available. But, of course, these components have to be properly installed and will usually require a pump-around circuit and dual seals, generically depicted in Fig. 1, that include a conservatively designed wideclearance pumping ring. We should remind ourselves of a key requirement of API 682/3rd Edition: Mechanical seals installed in refinery equipment should have a design life of 25,000 hours. Clearly, the mechanical seals in this particular installation fell far short of that requirement. It is hard to comprehend that an organization would tolerate 23 costly pump interventions without insisting on solid answers and remedies long before an inevitable catastrophic event occurs. Issues no doubt start with inadequate experience during the purchasing stage. After installation, it takes well-trained, motivated mechanical engineers to correctly diagnose seal failures and find the true root causes. Unless the root cause is determined, there will be repeat failures. Don’t employ the nonteachable and do develop an intense dislike for repeat failures. Be determined to reward managers and hourly employees who eradicate repeat pump failures. Finally, consider instituting a new regime by valuing, developing and promoting competent leaders instead of favoring those who can fabricate a profit margin in the next quarter. Understand that house-of-sand next-quarter profits are crumbling at random, whereas house-of-brick organizations have few surprises and will keep standing. HP The author is HP’s Equipment/Reliability Editor. A practicing consulting engineer with close to 50 years of applicable experience, he advises process plants worldwide on failure analysis, reliability improvement and maintenance cost-avoidance topics. Mr. Bloch has authored or co-authored 17 textbooks on machinery reliability improvement and over 470 papers or articles dealing with related subjects.

FIG. 1

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HPINTEGRATION STRATEGIES LARRY O’BRIEN, CONTRIBUTING EDITOR lobrien@arcweb.com

Procedural automation improves process plant performance Procedures govern the world of process automation. While we like to refer to the process industries as being largely “continuous,” in actuality, process manufacturing is constantly in flux. Whether you are doing a startup, shutdown, grade change, or are in the middle of a maintenance turnaround, your HPI plant is governed by procedures and transitional states that can either run smoothly and provide you with superior plant performance, and a safe and orderly startup/shutdown or they can cost you in terms of unplanned shutdowns, incidents, lost product and lost opportunities. Procedural automation enables human reliability. In

demand-limited industries, like refining, the overarching objective is to improve utilization. Plants cannot achieve this without reducing unplanned downtime. Research shows that the largest reason for unscheduled downtime is operational or human error, which accounts for approximately 42% of the unscheduled shutdowns in the process industries. Of that 42%, 16% is directly related to procedural error. When researching the role of operators in the future refinery, several major operating companies concluded that this can be addressed through a high-level perspective that enables flawless intervention by exception and relieves operators of manual tasks, freeing time for more value-added activities. The same research also identified procedure automation as one of the key process automation system functions (along with alarm management and an operational perspective) that can support this environment of flawless intervention. The expertise and operating level of experienced operators can be incorporated into automatic sequences and used to standardize operating methods and improve the efficiency of all operators. ARC has a vision for the collaborative process automation system (CPAS) of the 21st century. An important part of this vision is that in developing an overall automation strategy, humans should be allowed to do what they do best and automation should be allowed to do what it does best. Humans are good at ad-hoc intervention and nonlinear reasoning. They do best when empowered with an overall production cycle perspective. Machines and automation are good at repetitive functions, steady-state operation and transition management. Automation provides an environment for unbroken, precise execution, linear reasoning, and can consistently implement best practices through automated procedures. Manual, prompted or automated? Today, operational procedures can be lumped into three primary categories—manual, prompted and automated. In manual procedures, the operator performs the necessary actions required either through personal experience or by following standard operating procedure (SOP) manuals. The consistency with which manual procedures are performed can vary greatly depending upon the experience level of those carrying out the procedures. Manual procedures also call for manual record-

keeping, which can also vary in consistency and quality. Electronic records are preferable, but their quality can also vary depending upon the accuracy with which they were entered into the system. There is no way to verify that the manual procedures followed were in fact consistent with printed SOPs. Prompted operational procedures go one step further. Here, the procedures are implemented in the process automation system and the operator is prompted to acknowledge that each step has been successfully completed in order to continue. Prompted procedures make it easier to keep electronic records and verify that procedures were followed correctly. They can also decrease both transition times and product variability. Like prompted operational procedures, automated procedures are implemented in the process automation system. The difference is that automated procedures will go through the entire operational sequence before stopping, unless either the operator or the system intervenes on an exception basis. Automated procedures can further reduce transition times and variability. Many industries have been using prompted or automated procedures for some time. The batch-processing industries have used the ISA-88 standard for years. This defines a modular approach to batch automation and batch procedures. In the continuous process industries, however, prompted and automated procedures are not the established way of doing business. Here, there is no equivalent to the ISA-88 standard and many end users consider operations such as starting up and shutting down a refinery to be a craft or art form that relies heavily on experience and knowledge of the particular plant and its quirks. This is not to say that automated procedures are unknown in the continuous process industries. Many companies have implemented sequence logic that allows procedures to be automated. However, these have been done largely in an-ad hoc framework using custom-programming methodologies that can become cumbersome when it comes time to upgrade the automation infrastructure. This ad-hoc approach also carries a high ownership cost, since the procedures have to be maintained by the end user. Changes made to the code over time can create a tangled mass of “spaghetti code” that can be impossible to translate. Many end-user companies in the process industries today are also the result of mergers and acquisitions. Along with that come the many system platforms and unstructured code implementations that have accumulated over the years. Clearly, this is not a sustainable way to do business. As a result, more and more end users are Larry O’Brienapproaches is part of the automation teamalready at ARC covering the standardizing and manyconsulting have either adopted, process industries, and an HP contributing editor. He is responsible for tracking the or are considering adopting, procedural automation. HP market for process automation systems (PASs) and has authored the PAS market studies for ARC since 1998. Mr. O’Brien has also authored many other market research, strategy and custom research reports on topicsconsulting including process fieldbus, collaborative The author is part of the automation team at ARC covering the partnerships, total automation market trendseditor. and others. He has beenfor with ARC since process industries, and an HP contributing He is responsible tracking the January and started his career with market the field the instrumentation market 1993, for process automation systems (PASs) research and has in authored PAS market markets. studies for ARC since 1998. HYDROCARBON PROCESSING MAY 2010

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HPIN ASSOCIATIONS BILLY THINNES, NEWS EDITOR

BT@HydrocarbonProcessing.com

Fossil fuels still meet energy needs of the world Out in the Arizona desert during the waning days of March, the National Petrochemical and Refiners Association (NPRA) gathered its members for its 108th annual meeting. The assembled representatives came together in downtown Phoenix, sharing knowledge during technical sessions and parsing the meaning of various legislative and economic developments. Some of the meeting highlights are discussed in this space. State of the HPI. NPRA Chairman

Bill Klesse of Valero joined NPRA President Charlie Drevna before an assemblage of media members to discuss issues of the day. “We are an industry of innovators and optimists,” Mr. Drevna said. “We support sound, rational energy and environmental policies that promote American business and jobs. Whether it is the 2 million direct jobs or the 9 million indirect jobs that this industry contributes to America, we are a vital cog in this nation’s economy and the sooner that this current Administration and Congress realizes that the better off the American consumer will be.” Mr. Klesse believes that there is 1–2 million bpd of excess refining capacity in the US. Economic activity is still slow now, but when looking to the future, even if the economy picks up, there will be CAFE standards coming into play and low carbon fuel issues. According to Mr. Klesse, any growth that the refining industry could see in consumption is going to be absorbed by ethanol . “I find that ethanol is part of the fuel mix. While I don’t dispute the issues raised by NPRA on sound science [in relation to ethanol], I understand that it is a farm program and also a domestic program,” Mr. Klesse said. “Actually, today ethanol is economically in the fuel mix. Valero has stepped into this business because we believe that many of these alternatives are going to be a part of the fuel mix going forward.” The Obama Administration’s new budget proposal includes language that

Claiborne Deming, executive director and chairman of the Executive Committee for Murphy Oil, was a featured speaker during the NPRA’s 108th annual meeting.

would significantly increase the tax burden on the refining industry. Mr. Drevna was particularly critical of aspects of the budget that would repeal “Last In, First Out” (LIFO) accounting practices and Section 199 manufacturing incentives for oil and gas companies. “Folks like Bill [Valero] have made investments on what they thought was the tax policy and now the game is being changed,” Mr. Drevna said. Regarding LIFO, he said that would be a “very difficult one time cash hit for refiners. This is not applicable to all manufacturing but solely to the refining industry.” Mr. Klesse concurred. “If we are going to raise the tax burdens on this industry, it will be passed through to the consumer. It will not be absorbed by the industry because there is no place to absorb it.” Fossil fuels still relevant. During the annual meeting’s industry leadership breakfast, Claiborne Deming, who is the executive director and chairman of the Executive Committee for Murphy Oil, offered remarks focused on the energy challenge facing the world today. “The world’s population will rise from 6 billion in 2010 to 8 billion on the planet by 2030,” Mr. Deming said. “What this will cause is a dramatic increase of energy use.” But while energy use will continue to grow, Mr. Deming does not think that the energy mix in 2030 will change that much from today. His projections show

that, in 2030, 85% of energy will still be produced by fossil fuels. The exact breakdown he sees is: 11% hydro and renewable; 6% nuclear; 28% coal; 23% natural gas; and 32% oil. While there are those out there who champion alternatives to fossil fuels and prophesize that they could overtake them, one must remember that the difference between fossil fuels and alternatives is scalability. “Fossil fuels are the only fuels that can scale to meet the energy needs of the world,” Mr. Deming said. Along with the rise in global energy consumption, a rise in CO 2 emissions will, of course, occur. “CO2 emissions will rise in the future and any issue to address it has to include the whole world,” he said. “Doing something unilaterally in the US shoots ourselves in the foot and doesn’t solve the problem.” Bringing alternatives to scale.

Can the US scale up alternative energy sources to replace fossil fuels? What would happen if the country were going 100% to solar, wind and nuclear? Well, Mr. Deming leaned on some figures and research from Wood MacKenzie to offer this example. If the US’ energy sources were 60% nuclear 20% solar and 20% wind, the total cost to get there would be $15.5 trillion. “Let me offer you some perspective on this cost,” Mr. Deming said. “If you look at the New Deal and you take all the money spent in the 1930s on it against the average GDP during this period, it was only 60 percent of one year’s GDP. This [scaling up solar, wind and nuclear] is 150% of one year’s average GDP in present day. What it tells you is that the wealthiest country on the planet with a manageable-sized population can’t afford it.” Mr. Deming also pointed out that bringing alternatives to scale would double the US’ national debt. “This tells you again that fossil fuels are going to be the baseload to supply fuel for the future,” he said. HP HYDROCARBON PROCESSING MAY 2010

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HPIMPACT BILLY THINNES, NEWS EDITOR

BT@HydrocarbonProcessing.com

Underground gas storage on the rise C E D I G A Z ( w w w. c e d i g a z . c o m ) recently released a report on global underground gas storage (UGS). The report provides an overview on the development of UGS markets on a country-by-country basis. A specific focus is on the legal framework and storage tariffs in European countries, as well as on their future storage needs by 2020. As of February 2010, CEDIGAZ identified 207 underground gas storage projects in the world, representing an additional working capacity of 131.3 bcm compared to a current available volume of 333.3 bcm. The majority of the projects are located in Europe with 127 sites (68 new facilities and 59 expansions of existing sites). The report was particularly taken with the strong dynamics of the storage market in the US, which has 27 projects for new facilities and 22 expansions of existing sites. During the storage filling season in 2009, the low prices on natural gas markets pushed the gas players to inject gas in order to profit from future price increases. According to the Energy Information Administration (EIA), UGS sites in the US were close to being completely full, with 108 bcm stored in November 2009, even though the effective maximum storage capacity is not precisely known. New storage projects could bring an additional 19.2 bcm by 2020, including 11.8 bcm in salt cavern storages. This growing capacity increase will reduce the tensions on storage markets in the US and facilitate price arbitrages for gas players. CEDIGAZ sees Europe leading the way on UGS issues, though. The continent could almost double its storage capacity by 2020, with 75.7 bcm of planned additional working capacity compared to the 85.6 bcm at the beginning of 2010. Liberalization of European gas markets and the security of supply issue are the key factors of this development, the report said. New countries expected to develop their own storage facilities in the future include Mexico, Albania, Bosnia and Herzegovina, Lithuania, Georgia, New Zealand, Pakistan and Iran. In these coun-

tries, UGS projects are designed mainly to balance seasonal demand and meet winter demand peaks.

these events has the potential to cause oil supply disruptions. In order to cope with such scenarios, the International Energy Agency (IEA) has developed a coordinated response system to oil supply emergencies. According to a recent report issued by the IEA, these “collective response actions are designed to mitigate the negative impacts of sudden oil supply shortages by making additional oil available to the global market through a combination of emergency response measures,

Responding to oil supply emergencies We live in an uncertain world. Natural disasters, terrorist attacks and unforeseen economic collapses all lurk somewhere in the nebulous future, possibly near term or possibly long term. Each of September 2005 March–December 2003 December 2002–March 2003 June–July 2001 August 1990–January 1991 October 1980–January 1981 November 1978–April 1979 October 1973–March 1974 June–August 1967 November 1956–March 1957

Hurricanes Katrina\Rita

1.5 2.3

War in Iraq

2.6

Venezuelan strike

2.1

Iraqi oil export suspension

4.3

Iraqi invasion of Kuwait

4.1

Outbreak of Iran–Iraq war

5.6

Iranian revolution

4.3

Arab–Israeli war and Arab oil embargo Six–Day War

2.0

Suez crisis

2.0

0.0

1.0

2.0 3.0 4.0 Gross peak supply loss, million bpd

5.0

6.0

Source: IEA

FIG. 1

War and natural disaster can cause major global oil supply disruptions.

North America 727 673 592

Europe 546 371

2 Public

176 Industry

238

Public

389

Industry

Asia–Paciﬁc

20 Public

Source: IEA

FIG. 2

Crude, NGL and feedstocks Finished product

222

161

Industry

Data as of end of December 2009 in million barrels.

IEA member countries’ oil stocks, as of December 2009.

HYDROCARBON PROCESSING MAY 2010

I 15

HPIMPACT which include both increasing supply and reducing demand.” Since its creation, the IEA has acted on two occasions to bring additional oil to the market via coordinated actions. The first was the 1991 Gulf War and the second was in the aftermath of Hurricane Katrina in 2005. For a perspective on what the IEA considers a major oil supply disruption, see Fig. 1. However, the IEA considers multiple factors beyond the gross peak supply

loss caused by an event before initiating a collective response. “The decision depends on the expected duration and severity of the oil supply disruption and also takes into account any additional oil which may be put on the market by producer countries,” the report said. In the case of the response to Hurricane Katrina in 2005, all 26 IEA member countries agreed to make available to the market the equivalent of 60 million barrels

Pfl j\\ jk\\c% N\ j\\ jX]\kp% ?lek\i 9l`c[è^j `j k_\ nfic[ c\X[\i è k_\ gif[lZk`fe f] hlXc`kp$\e^è\\i\[# YcXjk$ [ ] c [ Yc i\j`jkXek df[lcXi Yl`c[è^j% Gligfj\ Yl`ck ]ifd k_\ îfle[ lg# \m\ip ?lek\i Yl`c[è^ d\\kj Xe[ \oZ\\[j èk\ej\ jX]\kp Xe[ YcXjk jkXe[Xi[j kf \ejli\ k_\ gifk\Zk`fe c\m\cj pfl èj`jk fe ]fi g\ijfee\c# Zi`k`ZXc \hl`gd\ek Xe[ gif[lZk`m`kp% :ljkfd ;\j`ê J_fik$ fi Cfe^$K\id C\Xjè^ G\idXe\ek K\dgfiXip 8ggc`ZXk`fej Dlck`gc\ 9cXjk Fm\igi\jjli\ ;liXk`fe ;\j`êj Cfn# D\[`ld Xe[ ?`^_ I\jgfej\ ;\j`êj Gfj`k`m\ Gi\jjli`qXk`fe :cXjj @ ;`m`j`fe ) <c\Zki`ZXc >Xj =ì\ ;\k\Zk`fe JX]\ ?Xm\e :XgXYc\ KiXejgfikXYc\ n`k_ Hl`Zb J\klg 8G@ IG .,)&.,* :fdgc`Xek 9cXjk K\jk\[

Refiners in a tough market

J\\ jX]\kp ]ifd fli j`[\ Ç ?lek\i 9l`c[`e^j b\\gj pfl gifk\Zk\[ ]ifd k_\ flkj`[\ `e%

_lek\iYl`c[`e^j%Zfd 16

of oil through a combination of measures, including the use of emergency stocks, increased indigenous production and demand restraint. The end result was that almost 29 million barrels were drawn from public stocks and an additional 23 million barrels of oil were made available through the lowering of stockholding obligations on industry. The IEA concluded that this collective action “successfully reinforced market functions by providing real barrels to relax tightness and offset interruption in supply.” How is all of this orchestrated? Well, once a coordinated action has been agreed upon, each member country participates by making oil available to the market. “An individual member country’s share of the total response is generally proportionate to its share of the IEA member countries’ total consumption,” the report said. Each IEA member country is required to maintain total oil stock levels equivalent to at least 90 days of net imports. Countries may guarantee this minimum obligation by holding stocks as government emergency reserves, through specialized stockholding agencies or by placing minimum stockholding obligations on industry. Stocks held by agencies or owned directly by member country governments are referred to as public stocks. Public stocks, held exclusively for emergency purposes, accounted for 1.6 billion barrels of the total stocks by the end of 2009 (Fig. 2). The 2.6 billion barrels of industry stocks include both stocks held to meet government stockholding obligations and stocks held for commercial purposes. At the end of 2009, total oil stocks in IEA member countries were approximately 4.2 billion barrels.

)/(%+,)%0/''

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A recent paper from Wood MacKenzie suggests the current global and US market environment for refiners is very challenging, with the industry suffering low utilizations (due to the economic crisis reducing demand) and margin compression (from the surplus capacity and also from weak light/heavy differentials). “Our preliminary estimates suggest that one-quarter of the North American refining industry was cash negative during 2009,” the paper said. Regarding the idea that rebounding economic growth in 2010 will support an improvement in margins, Wood MacKenzie begs to differ. “For the US, we expect ethanol to supply the projected recovery and growth

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HPIMPACT in gasoline demand, so there is limited demand for refinery-based gasoline,” the paper said. “Depending upon refinery configuration, 2010 margins could be weaker than 2009. Longer term, margins are anticipated to recover, making near term survival imperative.”

Medium voltage motor drives sales projected to decline in 2010 The worldwide medium voltage motor drives market was estimated to be worth $2.17 billion in 2008 according to IMS Research (www.imsresearch.com). This value represents an increase of more than 35% over 2007 levels, with much of the growth attributed to the thriving Chinese market. The economic downturn that began in the second half of 2008 and lasted well into 2009 has had a substantial impact on the market. IMS Research believes that total market revenues grew by only 0.7% in 2009, resulting in an estimated market size of $2.19 billion during the year. Unit shipments were affected to a lesser extent, managing to increase by 3.2% over 2008 levels. The full effects of the downturn are expected to impact the market in 2010, when revenues are projected to fall by 16.2% and unit shipments are forecast to decline by 10.9%. The delayed effects are attributed to significant lag between bookings and billings, which resulted from order backlogs prior to the recession and long production times for these complex and technically advanced drives. The market contraction forecast for 2010 is caused by severe order declines in 2009, particularly in the metals, mining, marine and cement industries. Together, these four sectors accounted for more than half of all medium voltage drive revenues in 2008. Sales to the power generation and water and wastewater industries are the only ones forecast to grow in 2009 and 2010, driven by population growth, increased urbanization and infrastructure expansion in developing regions. China is now the largest regional market for medium voltage drives, accounting for an estimated 43% of total revenues and 58% of total unit shipments in 2009. Growth of the Chinese market has been remarkable over the past few years, and while it is expected to slow substantially in the future, the market is still pro-

jected to grow by an average annual rate of more than 13% from 2008 to 2013. The average selling prices of medium voltage drives in China are much lower than the global average because of intense price competition and the prevalence of drives with lower power ratings. The US and Western European medium voltage motor drive markets respectively represent approximately 14% and 9% of total revenues in 2009. These regional markets

are projected to contract by more than 35% in 2010, as heavy declines in the regions’ industrial sectors result in much lower demand for medium voltage drives. Although the markets are expected to return to double-digit growth by 2011, they are not expected to recover to their 2008 levels until after 2013. Average selling prices are projected to decline by approximately 3% per year in the US and 3.8% in Western Europe. HP

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

North America Saipem has a contract from PEMEX for two desulfurization units and two amine regeneration units to be built at two of PEMEX’s refineries. The scope of work will consist of the engineering, procurement and construction, along with commissioning and testing, of two desulfurization units and two amine regeneration units and relative auxiliary systems. The facilities will be built in Mexico at the Miguel Hidalgo refinery near the town of Tula de Allende, and at the Antonio M. Amor refinery, near the town of Salamanca. The work is expected to be completed within a period of 38 months. KBR has a contract with BP-Husky to provide engineering, procurement and other project-related services for BP-Husky Refining LLC’s $400 million equipment upgrade of its Toledo refinery in Oregon, Ohio. KBR will provide design and support services needed for the project, replacing two existing naphtha reformers and a hydrogen plant with a single reformer. The new equipment is expected to reduce air emissions at the plant by 5%. Jacobs Engineering Group Inc. has a two-year contract from Canaport LNG for the provision of maintenance and related services at the company’s LNG terminal in St. John, New Brunswick, Canada. Jacobs will perform preventive, predictive, corrective and regulatory maintenance activities at the site. Canaport LNG has maximum send-out capacity of 1.2 billion cf/d.

South America CB&I has a contract to supply a cryogenic natural gas processing plant in Malvinas, Peru, as part of an expansion of the Camisea gas project. CB&I’s $45 million contract is with Pluspetrol Peru Corp. SA as operator and contract administrator, acting on behalf of the licensees. CB&I will be responsible for the engineering, procurement and modular fabrication of a cryogenic unit designed to process 520 million scf/d of gas. The unit, which is scheduled for completion later this year, will treat gas extracted from the Pagoreni field, separating the natural gas liquids out of the gas stream.

Skanska has a contract with Petrobras to construct the first phase of a new refinery for crude oil in Brazil. The total contract value is $623 million, of which Skanska’s share is 40% ($250 million). The contract is for the first processing unit of a new oil refinery at Petrobras’ petrochemical complex in the state of Rio de Janeiro. The project relates to a distillation unit for crude oil entering the refinery. The unit will have the capacity to process about 150, 000 bpd and is expected to be operational during 2013.

Europe Bayer MaterialScience plans to invest €150 million in a new production plant for toluene diisocyanate (TDI) at Chempark Dormagen in Germany. The new plant will have a capacity of 300,000 tpy and will replace the existing plants in Dormagen and Brunsbüttel. The new plant is currently scheduled to go onstream in 2014. Emerson Process Management and LUKOIL Group have an agreement to modernize 13 refining and petrochemical faciliTREND ANALYSIS FORECASTING ties in Russia and Eastern Europe. Under the Hydrocarbon Processing maintains an agreement, which extends through 2014, extensive database of historical HPI projEmerson will provide equipment, ect information. Current project software activity is published times a year in the HPI and services asthree part of LUKOIL’s enterpriseConstruction a automaproject wide strategy toBoxscore. modernizeWhen process is completed, it is removed from current tion at its oil and gas refineries, petrochemilistings and retained in a database. The caldatabase plants, isand relatedcompilation facilities. LUKOIL a 35-year of projects by type, company, licenoperations to be operating upgraded include Stavrolen sor,Saratovorgsintez engineering/constructor, location, etc. and in Russia, Neftochim Many companies use the historical data for Bourgas in Bulgaria, ZAO Lukor in Ukraine trending or sales forecasting. and Vars in Latvia, as well as additional facilThe historical information is available in ities in Romania; in and comma-delimited or Ukraine’s Excel® and Odessa; can be cusintom Russia’s Perm, theyour Volgograd region, sorted to suit needs. The cost and of the sort depends on the size and complexthe Komi Republic. ity of the sort you request and whether a customized program must be written. You Middle can focusEast on a narrow request such as the Saudiof Aramco Shell Refinery Co. (SAShistory a particular type of project or you can obtain the entire 35-year Boxscore REF) recently inaugurated an ultra-low-suldatabase, or portions thereof.

fur diesel unit at its Jubail refinery in Saudi SimplyAccording send a cleartodescription of the data Arabia. SASREF officials, the you need and you will receive a prompt unit started commercial production of costhas quotation. Contact: around 100,000 Lee bpdNichols of diesel with less than 10 parts-per-million sulfur. P. O. Box 2608 Houston, Texas, 77252-2608

SABIC hasFax: an 713-525-4626 agreement with Celanese e-mail: Lee.Nichols@gulfpub.com. Corp. for the construction of a 50,000

ton polyacetal production facility at the National Methanol Co. complex in Jubail Industrial City, Saudi Arabia. The engineering and construction of the facility is expected to begin by 2011. The facility is expected to go onstream by 2013, using methanol already being produced by National Methanol.

Asia-Pacific Kentz Corp. Ltd. has a site-wide specialist instrumentation contract for the Pluto LNG project on the Burrup Peninsula in Western Australia. This brings Kentz’s combined value of work secured on the project to in excess of AUD$120 million. The project will be developed across two sites—the storage and export site and the LNG processing site. The storage and loading site consists of LNG and condensate storage tanks along with the jetty. The LNG liquefaction train and gas turbines/power distribution facilities will be on the LNG processing site. Kentz’s scope of work includes instrument calibrations, testing of instrument loops, TREND ANALYSIS FORECASTING Hydrocarbon Processing maintains an extensive database of historical HPI project information. Current project activity is published three times a year in the HPI Construction Boxscore. When a project is completed, it is removed from current listings and retained in a database. The database is a 35-year compilation of projects by type, operating company, licensor, engineering/constructor, location, etc. Many companies use the historical data for trending or sales forecasting. The historical information is available in comma-delimited or Excel® and can be custom sorted to suit your needs. The cost of the sort depends on the size and complexity of the sort you request and whether a customized program must be written. You can focus on a narrow request such as the history of a particular type of project or you can obtain the entire 35-year Boxscore database, or portions thereof. Simply send a clear description of the data you need and you will receive a prompt cost quotation. Contact: Lee Nichols P. O. Box 2608 Houston, Texas, 77252-2608 Fax: 713-525-4626 e-mail: Lee.Nichols@gulfpub.com. HYDROCARBON PROCESSING MAY 2010

I 21

HPIN CONSTRUCTION and testing the electrical network monitoring and control system including all serial loops across both sites. Fluor Corp. has an engineering and related management services contract with Samsung C&T Corp. for the Singapore LNG terminal project at Singapore’s Jurong Island. Work is underway with the project being performed from Fluor’s Singapore, Manila and Houston operations centers.

Foster Wheeler AG’s Global Power Group has a contract with Sinopec Jiujiang Co. for the design and supply of two circulating fluidized-bed (CFB) steam generators for the Sinopec Jiujiang fuel alteration project located in Jiangxi Province, China. Commercial operation of the new steam generators is scheduled for first quarter 2012. Foster Wheeler will design and supply the two 50-gros- megawatt electric CFB steam generators and auxil-

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iary equipment and provide site advisory services for the project. The CFB steam generators will be designed to burn coal and petcoke in a manner that will meet China’s environmental requirements. Shell recently signed two contracts with the Technip and Samsung Heavy Industries consortium for the Prelude floating liquefied natural gas (LNG) project off the coast of Western Australia. These contracts formalize the announcement made by Shell in October 2009 that Prelude is in the engineering and design phase of development. The first contract covers the front-end engineering design (FEED) elements specific to the Prelude project, taking into account the composition of the gas, local weather conditions and other site specific factors. The second contract details the terms under which the floating LNG facility would be built, if the final investment decision for the Prelude project is made. Larsen & Toubro Ltd. has an order valued at Rs. 2035 crore from ONGC Mangalore Petrochemicals Ltd. for an aromatics complex, to be set up at the Mangalore SEZ in India. The complex will produce products like paraxylene, benzene, hydrogen, heavy aromatics and LPG. This project involves nine process units including a naphtha hydrotreating unit, a continuous catalytic regeneration and platforming unit, a Parex unit and an Isomar unit. The project is expected to be ready for commissioning by December 2012. Shell Eastern Petroleum Pte Ltd. has selected Merichem Chemicals & Refinery Services’ technologies for a revamp project at its refinery in Pulau Bukom, Singapore. Merichem will supply technologies to treat propane/propylene, butane/butylene and light cat-cracked gasoline streams in order to meet final product specifications. Bharat Petroleum Corp. Ltd. has selected Axens to provide the technology licenses for a naphtha hydrotreater and a continuous catalytic regeneration reformer (CCR) at its refinery in Mumbai, India. The 900,000 tpy CCR reformer is being designed to operate on mixed mode to produce benzene and toluene or reformate destined for gasoline conforming to Euro III/ IV specifications. Besides meeting the additional requirements of Euro IV fuels, this project will pave the way for further quality upgrading to meet Euro V standards. HP

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HPI CONSTRUCTION BOXSCORE UPDATE Company

City

Plant Site

Project

Capacity Unit Cost Status Yr Cmpl Licensor

Madison, Illinois Mt. Vernon, Indiana Port Arthur Port Arthur Madison Evanston

Ethanol Ethanol Sulfur Sulfur (2) Biogas NGL Recovery

Rio de Janeiro Poza Rica Malvinas !New Pointe-a-Pierre

Distillation, Crude NGL Recovery NGL Recovery Diesel, ULSD CCR/NHT Platformer

Porvoo Dunkirk Krefeld-Uerdingen Krefeld-Uerdingen Amsterdam

Porvoo Dunkirk Krefeld-Uerdingen Krefeld-Uerdingen Port of Amsterdam

Maintenance Turnaround BTL (Biomass to Liquid Fuel) Chlorine Formalin Terminal

None None 20 Mtpy None 1.2 MMm3

Heze Jiaxing Nanjing Nanjing Ningbo Ningbo Ningbo Ningbo Ningbo Ningbo Ningbo Ningbo Panjin Panjin Qianjiang Shang Qiu Tengzhou Wuhan Wuhan Dahej Mumbai

Heze Jiaxing Nanjing Nanjing Zhenhai Zhenhai Zhenhai Zhenhai Zhenhai Zhenhai Zhenhai Zhenhai Panjin Panjin Qianjiang Shang Qiu Tengzhou Wuhan Wuhan Dahej Mumbai

Ethanol to EO Ethylene Oxide Ethylene Oxide Ethylene Oxide Aromatics Extraction Butadiene CFB Boiler (5) Ethylbenzene generator, gas turbine (4) Hydrogen Generation MTBE/butylene-1 Polypropylene Ethanolamine Ethylene Oxide/MEG Ethanol to EO Ethanol to EO Ethanol to EO Ethylene Oxide MEG Pyrolysis Gasoline CCR/NHT Platformer

63 53 63 63 600 160 410 650 50 700 130 300 50 100 42 63 63 150 280 360 900

Engineering

Constructor

UNITED STATES Illinois Indiana Texas Texas Wisconsin Wyoming

Abengoa Bioenergy Abengoa Bioenergy Total Petrochem US Total Petrochem US Shell/Virent Energy JV Questar Gas Mangement

100 100 225 225 10 350

MMgpy MMgpy tpd tpd Mgpy MMcfd

200 200

150 200 520 40000 28

Mbpd MMcfd MMcfd bpd Mbpsd

623

C C U U C U

2009 2009 2010 2011

2010

U U U E C

2013 2011 2011 2012 2009

M P U E U

2010 2012 2011 2011 2012

U U U U U U U U U U C U U C U U U U U U E

2011 2012 2012 2012 2009 2010 2010 2010 2010 2010 2010 2010 2010 2010 2011 2010 2010 2012 2011 2012 2012

Vogelbusch Vogelbusch Ortloff|Shell|Amoco Ortloff|Shell|Amoco

Fluor Fluor

Ortloff

OPD

Ortloff Ortloff CB&I Lummus Samsung Eng

ICA Fluor|Linde CB&I Samsung Eng Samsung Eng

LATIN AMERICA Brazil Mexico Peru Trinidad Trinidad

Petrobras Questar Gas Mangement PlusPetrol Peru !New Petrotrin

Skanska Linde|ICA Fluor CB&I Samsung Eng

EUROPE Finland France Germany Germany Netherlands

Neste Oil BioTfueL JV Bayer MaterialScience AG Lanxess Vopak

155 24

Uhde Uhde|Bayer MaterialScience AG Uhde

ASIA/PACIFIC China China China China China China Chin China China China China China China China China China China China China India India

Shandong Yuhuang Chemical Jiaxing Yongming Petrochemical Nanjing Chem Ind Co Taixing Dantian Zhenhai Rfg & Chemical Zhenhai Rfg & Chemical Zhenhai Rfg & Chemical Zhenhai Rfg & Chemical Zhenhai Rfg & Chemical Zhenhai Rfg & Chemical Zhenhai Rfg & Chemical Zhenhai Rfg & Chemical Liaoning Huajin Chemicals Liaoning Huajin Chemicals Yongan Pharmaceutical Sanhe Chemical Co Shandong Yuhuang Chemical Sinopec Sinopec ONGC Ltd BPCL

kty kty kty kty Mtpy Mtpy tph Mtpy MW Mtpy Mtpy Mtpy kty kty kty kty kty kty kty Mm-tpy Mtpy

3207 3207 3207 3207 3207 3207 3208 3207

981

SD SD SD SD Sinopec Sinopec

CPENE CPENE CPENE CPENE

Sinopec Sinopec Sinopec Sinopec SD SD SD SD SD SD SD

HQCEC HQCEC CPENE Ningbo Design Institute SEI SEI Samsung Eng

Samsung Eng

Axens

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

BOXSCORE DATABASE

ONLINE

THE GLOBAL SOURCE FOR TRACKING HPI CONSTRUCTION ACTIVITY For more than 50 years, Hydrocarbon Processing magazine remains the only source that collects and maintains data specifically for the HPI community, publishing up-to-the-minute construction projects from around the globe with our online product, Boxscore Database. Updated weekly, our database helps engineers, contractors and marketing personnel identify active HPI construction projects around the world to: • Generate leads • Market research • Track trend analysis • And, decide future budget planning. Now, we’ve made our best product even better! Enhancements include: • Exporting your search results to Excel so you can compile your research • Delivering the latest updated projects directly to your inbox each week • Designing customized construction reports for your company using our 50 years of archived projects. For a Free 2 -Week Trial, contact Lee Nichols at +1 (713) 525-4626, Lee.Nichols@GulfPub.com, or visit www.ConstructionBoxscore.com

I MAY 2010 HYDROCARBON PROCESSING

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MAINTENANCE/RELIABILITY

SPECIALREPORT

Flow-induced fatigue failure in tubular heat exchangers Case histories describe a variety of failures and solutions A. BABAKR, T. ASHIRU and C. WESTHUIZEN, SABIC R & T, Jubail, Saudi Arabia

ue to the combined actions of vibration with pitting corrosion tube failure occurred by a mechanism known as corrosion fatigue. Vibration on its own should not cause any mechanical problems provided it is below the material fatigue limit. Case histories are presented that describe a variety of flowinduced vibration-related failures in tubular heat exchangers. Introduction. Many types of heat exchanger failures are ran-

domly faced in the petrochemical, chemical, utility, engergy and petroleum industries.1 Some common failures in heat exchangers are: assembly errors, manufacturing defects, improper design, pipe and tubing imperfections, welding,2 fabrication,3 improper materials, improper operating conditions, pitting, stress-corrosion cracking,4 corrosion fatigue, thermal fatigue,5 general corrosion, crevice corrosion,6 design errors, fouling,7 selective leaching/ dealloying8 and erosion corrosion.9 This article will constrict the readers to one failure phenomenon in heat exchangers that is flow-induced fatigue.

were found to be leaking. The tube sections that had separated were used to perform fractography. The tubes were also split longitudinally in halves to view the inside surfaces and to determine the extent of pitting damage (Fig. 1). Visual observation of the broken piece revealed small pits on the inside surface. Some pits were visible on the outside surface as well. The tube exterior also had indicated baffle marks as can be clearly seen in Fig. 2. A spark emission spectrometer was used to identify the tube alloy composition and it was found to conform to the SA 214 tube specification. An optical macrograph of the inner surface revealed corrosion in progress. Pits were clearly visible after cleaning the surface as can be seen in Fig. 3. Further observation of the fracture surface revealed two pits that were found at the origin of a fatigue crack. Fig. 4 clearly shows two macrographs showing two pits and the fracture beach TABLE 1. Heat-exchanger data Shell side

Tube side

Operating pressure, bar

4.5

37.7

Operating temp., 째C

38/44

90/45

Material

SA516-60

SA214 ERW tube

Service fluid

Fresh cooling water

Hydrocarbons

Tube O.D., mm

19.05

Tube length, m

6.0

HE and tube configuration

Horizontal and straight tubes

Case 1. The cooler has been in service for at least six years.

The earliest leak was recorded after only two years in service and was plugged. The tube side did not reveal any signs of corrosion. Shell-side inspection could not be performed due to the fact that this is a fixed-head heat exchanger. Tube leakage was again suspected within three weeks after the repairs. Recently, it was noticed that there was a considerable rise in the cooling water pipeline skin temperature connected to the cooler. Skin temperatures of both the inlet and outlet pipeline surfaces were found to be the same. In addition, it was also observed that cooling water flow was blocked by increased hydrocarbon leakage into the shell side. During shutdown, the heat-exchanger tubes were replaced with seamless SA 179 and baffle material remained typical carbon steel. The inspection team managed to perform magnetic flux leakage (MFL) on the heat-exchanger tubing. Major affected tubes were located immediately at the hydrocarbon inlet as can be seen from MFL results (Fig. 1). The heat-exchanger operating parameters and relevant tube information are provided in Table 1. Investigation. Two tubes were received (each six meters long)

in addition to two small sections that broke off while being pulled out of the tube bundle. Because of the length, the tubes were cut to three meters. The tubes were tested for leaks by means of pressurizing with air while submerging them in a water bath. None

FIG. 1

Photo macrographs of received tube sections showing where they broke off while being pulled out. Also, adjacent photo (b) shows the broken section inner surfaces with slight indication of corrosion pits. HYDROCARBON PROCESSING MAY 2010

I 27

SPECIALREPORT

MAINTENANCE/RELIABILITY marks indicating fatigue. The pits did not appear to be deep. Fig. 5 shows optical micrographs in the etched condition. No transgranular, intergranular or grain abnormality can be observed. Discussion. From what had been presented, it is possible to say

FIG. 2

Photo macrograph of the as-received tube showing rub marks caused by movement against the baffle. The tube location is immediately in front of the hydrocarbon inlet just before the failure site.

FIG. 3

Optical micrograph showing fracture and inner surfaces. Many pits and corrosion are shown on the inner surface after cleaning.

that the failure occurred due to the combination of fatigue and pitting corrosion. The synergistic action of both can be rationalized as follows: Fatigue. The problem of fatigue seemed to develop from the design. By looking at the tube/baffle interface, we noticed that there is increasing evidence of rub marks as we move toward the hydrocarbon inlet/water outlet. This is due to the baffle fit-up. Toward the hydrocarbon inlet the tube has a longer unsupported length. During normal operation, this region is susceptible to the highest vibration amplitude. Tubes are very well fixed into the tube sheet where it does not move. Hence, the highest fatigue-induced stresses will be at the tube/tube sheet interface.

FIG. 4

Two pits at the origin of the failure, 75 X.

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FIG. 5

MAINTENANCE/RELIABILITY

Optical micrograph showing a pit filed with iron oxide and with no cracks, 200X.

Pitting. Pitting was observed at both the tube and shell sides of the tubes. However, the pitting corrosion seems difficult to comprehend because the factors that will normally initiate pitting are not present in the media or, indeed, on the tube surface. It is possible that pits had been initiated by factors or situations that occurred during the past shutdown and consequently not available for us to analyze. Corrosion fatigue. Due to the presence of pits in the region of the fatigue fracture face and also pits at one of the origins of a

fatigue crack, the mechanism that caused the failure is corrosion fatigue. For this mechanism the time to failure will be far shorter than fatigue or pitting by itself. In corrosion fatigue, there is always a corrosive environment present during the fatigue cycles and this combination makes the component fail earlier than it would have if only fatigue was the cause. There may even be combinations of the above-mentioned mechanisms at work. If the pits were not present then the heat exchanger would have lasted longer. On the other hand, if vibration was not present, then the pits would have taken far longer to cause tube perforation. Depending on the root cause of pitting, these pits may self-heal and may not even propagate further. Regular IRIS/MFL checks will clarify this issue. By using the finite-element (FE) method, we were able to predict the cause of the fatigue. Because of the tube length between the hydrocarbon inlet tube sheet and the baffle at the water outlet, high vibration was experienced due to the natural frequency of the tubes. These vibration waves were magnified as they approached the tube sheet. Continuous repetition of this action produced the rubbing marks observed and the tubes failed later due to fatigue. Now that a pit is present, it will act as a stress raiser that will reduce fatigue life. The tubes on the top (12 o’clock position) of the heat exchanger suffered more fatigue failure due to the described motion, while the tubes that are located at the lower part of the heat exchanger did not suffer similar failure because they were likely not subjected to vibrationinduced forces and the effect had subsided before reaching them. The plausible explanation of this is that the tubes in the lower position are “held down” by the weight of tubes at the top loca-

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FIG. 6

SPECIALREPORT

Finite-element analysis results showing baffle fit-ups and the last section of the tube having the highest displacment due to higher natural frequency.

tion; while the tubes at the upper location are not prevented from vibration like the lower tubes. Fig. 6 shows a 3D image and FE analysis to establish a rationale of the situation. These findings presented were supported by the IRIS test performed. Their conclusive finding was that the upper tubes had suffered the most (Fig. 7). This, in itself, had supported the proposed finding of the failed tube locations. This investigation instigated plant personnel to review the heat exchanger and ones of similar design. Case 2. The heat exchanger in this case (Fig. 8) has gone through

design changes since its commissioning 20 years ago, this is because of plant expansion and increased process demands. Only six years ago, the heat exchanger was vertical with cupper nickel tubes.

FIG. 7

IRIS results showing the affected tube locations.

Due to process requirements, other than materials, the design was changed to being horizontal with duplex stainless-steel tube. Since the process is not corrosive, its inspection was set to low. Still, for the first time one of them was inspected and cleaned. The original standby was placed in service in its place. After being in

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I 31

SPECIALREPORT

H2O

MAINTENANCE/RELIABILITY

Failed tube and H2O location of failure

Cycle gas

Cycle gas 16.756 m FIG. 8

Schematics of the heat exchanger in question showing the location of failure.

service for about two years to date, it was taken out and cleaned using a novel method of hydrokinetic hydrojetting. While performing the cleaning, the top row (fifth tube from the north) at the gas inlet had leaked. Almost at the same time, other coolers installed in other parts of the plant had also leaked. Cooler inspection indicated a leak from one tube, again in the top row, but this time the fifth tube from the right in the top row. This tube was plugged and seal welded at both ends and the cooler was placed back in service. The phenomenon is that both units failed in the same locations; right beneath the second baffle plate. Material: Tube: duplex (2205) SS-SA-789-S31803 Shell-baffels: Carbon steel Process medium: Shell-water Tube-cycle gas Time-in-service: 20 yearsâ&#x20AC;&#x201D;HE setup was vertical and the tube material was cupper nickel. From 2000 to present, HE setup horizontal and tube material is duplex SS-2205. Shell: Carbon steel. Setup/number of tubes/length: horizontal-one pass / 2.040 tubes, Âą1.6764 mm. Investigation. The sample tube that was received did not reveal any form of corrosion. In addition, there was no apparent deposit. Internally, it was very clean when viewed from one end. Baffle-plate markings were apparent, decreasing as we moved to inspect the tube length working our way back from the gas outlet to inlet. It was noticed that the failure location was precisely under the regions where the cooling water entered. Thinning was clearly

FIG. 9

IRIS back-end view of the heat exchanger showing the location of the failed tube in the top row, fifth tube from right.

FIG. 10

Tube showing failure in the second baffle plate from the cycle gas outlet.

FIG. 12 FIG. 11

Photograph showing clear space between the baffle plate and tubes.

I MAY 2010 HYDROCARBON PROCESSING

Photograph of the severed section of the tube below the baffle plate showing severity of flow-induced vibration. Also, from the inside showing no sign of corrosion or any damage.

MAINTENANCE/RELIABILITY apparent in the region exactly under the second baffle plate. Figs. 9, 10 and 11 clearly show the phenomena. Fig. 12 shows photos of the affected section and a view of the inner surface indicating no sign of corrosion. Discussion. There is no doubt that the failure was the result

of thinning induced by movement/vibration. The movement/ vibration was the result of the water inlet flow. A failure scenario can be proposed: Excessive inlet flow created movement of the upper-right tubes. Tube movement was excited by the space that already exists between the tubes and the baffle plate. The tube movement action resulted in localized tube thinning. The reason why this particular location was the most affected was because water was directed first to these locations by the impingement plate. This was not evident while in operation. The failure took place when hydrokinetic hydrojetting was performed, that particular location under the baffle plate was so thinned that it could not handle the pressure during cleaning. Indicative of that is the failure shape. The burst is to the outside rather than inside. Since this is a flow-induced failure, the most affected tube sites will be around the upper-right and left locations. It seems that the plant(s) demand had increased accumulating the load on these. The most evident approach to minimizing this problem is by reducing cooling water flowrate. This in turn will jeopardize plant demand. Hence, it is empirical to accommodate this problem by unit redesign to minimize the effect of cooling water inlet. It would be impractical to only address the space preset in the baffle plate. To eliminate flow-induced vibration, a reduction in the flow is vital for the current situation. In addition, it would not be feasible to change tube metallurgy since the failure is not related to material compatibility.

SPECIALREPORT

Al-Anizi, â&#x20AC;&#x153;Erosion in the tube entrance region of an air-cooled heat exchanger,â&#x20AC;? International Journal of Impact Engineering, V. 32, n. 9, September 2006, p. 1440.

Dr. Ali Babakr has served as a Senior Corrosion Engineer cum Failure Analysis Advisor for Saudi Basic Industries Corporation (SABIC), Jubail, Saudi Arabia since 2008. Currently, he serves as a Consultant for an Engineering firm in the USA. He holds PhD and MS degrees in Metallurgy from the University of Idaho, and B.S. Materials Chemistry from the Huston-Tillotson University, Austin, Texas. He also has interest in semiconductors and magnetic materials manufacture and applications. He has authored several papers to address the mitigation of corrosion and other materials degradation problems. Email: alibabakr@yahoo.com

Toyin Ashiru obtained his Ph.D. in industrial metallurgy from the University of Birmingham, UK; and B.Sc. (honors) in materials science from the University of Sussex, UK. He has about 25 years of teaching, research and industrial experiences in corrosion and metallurgy. Currently, Dr. Ashiru is senior staff engineer in the material and corrosion section of SABIC Technology Center, Jubail. Dr. Ashiru has patents on processes he developed for mitigating corrosion-related problems. He published more than 100 papers in learned journals and conference proceedings. Dr. Ashiru is a member of various professional associations and has served as the editor-in-chief or as an editorial board member of some technical journals. Christian van der Westhuizen has more than 26 years of industrial experience mainly focused in the petrochemical industry. He managed his own metallurgical consulting company in South Africa and afterwards worked for companies in Saudi Arabia as well as the United Kingdom. Mr. van der Westhuizenâ&#x20AC;&#x2122;s experience lies mainly in failure analysis, welding, corrosion mitigation and material selection. At present he is the company metallurgist for Davy Process Technology in London and is a professionally registered chartered engineer as well as chartered scientist in the UK. Mr. van der Westhuizen has written over 15 papers and presented them at various international conferences and has been involved as chairman is several technology exchange meetings.

Tentative conclusions:

â&#x20AC;˘ Thinning was the result of increased flowrates. â&#x20AC;˘ The failures were due to flow-induced vibration that led to mechanical wear. â&#x20AC;˘ Review the design of the heat exchanger in relation to tubes / baffle distribution. â&#x20AC;˘ A redesign of the unit is a must to accommodate the increased cooling water demand. HP 1 2

3 4

5 6

LITERATURE CITED Metals handbok. Fatigue Failures, vol. 10, 8th ed., ASM International. 1975, p. 95. Otegui, J. L. and P. G. Fazzini, â&#x20AC;&#x153;Failure analysis of tubeâ&#x20AC;&#x201C;tubesheet welds in cracked gas heat exchangers,â&#x20AC;? Engineering Failure Analysis V. 11, n. 6, December 2004, p. 903. Naumann, F. K. and F. Spies, â&#x20AC;&#x153;Boiler tube cracked during bending,â&#x20AC;? ASM failure analysis library, ASM International, Materials Park, Ohio (1996). Pola, A., Gelfi, M., Depero, L. E. and R. Roberti, â&#x20AC;&#x153;Study of annealing temperature effect on stress-corrosion cracking of aluminum brass heat-exchangers tubes by microdiffraction experiments,â&#x20AC;? Engineering Failure Analysis, V. 15, n. 1, January-March 2008, p. 54. Becker, W. T., â&#x20AC;&#x153;Thermal fatigue in a vaporizer handbook of case histories,â&#x20AC;? Failure Analysis, vol. 2, ASM International, USA (1996), p. 111. Rakesh Kaul, N. G., et al., â&#x20AC;&#x153;Failure analysis of carbonate reboiler heat exchangers,â&#x20AC;? Engineering Failure Analysis, V. 2, n. 3, September 1995, p. 165. Radhakrishnan, V. R., et al., â&#x20AC;&#x153;Heat exchanger fouling model and preventive maintenance scheduling tool,â&#x20AC;? Applied Thermal Engineering, v. 27, 17-18, December 2007, p. 2791. Malik, A. U., Kutty, P. C., Andijani, I. N. and S. A. Al-Fozan, â&#x20AC;&#x153;Materials performance and failure evaluation in SWCC MSF plants,â&#x20AC;? Desalination, V. 97, n. 1-3, August 1994, p. 171. Badr, H. M., Habib, M. A., Ben-Mansour, R., Said, S. A. M. and S. S.

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MAINTENANCE/RELIABILITY

SPECIALREPORT

Purging and inerting large-volume tankage and equipment— jet mixing concept—Part 1 Here are the advantages and disadvantages of the various methods M. GOLLIN, Carmagen Engineering, Inc., Rockaway, New Jersey

his two-part article discusses the issues involved with inerting vapor spaces and, in particular, the use of jet mixing. Part 1 discusses the reasons that inerting is required and examines the current options that are usually used for purging or inerting large volumes such as those found in the vapor spaces of tanks, reactors, etc. Part 2 discusses the use of jet mixing for inerting and mixing large vapor volumes. Inerting and purging by nitrogen injection has been discussed previously,1,2 but the methods described generally rely on diffusional processes within the volume being inerted. In some situations this may be a satisfactory solution, but where very large volumes are concerned, or where the volume geometry is not favorable, reliance upon bulk diffusional mixing may not be fully effective. The concept of using nitrogen jets for inerting and mixing is described in detail in Part 2 of this article, and equations that can be used in the design process are presented together with recommended testing and implementation issues. The use of such a nitrogen injection system, when implemented correctly, guarantees bulk mixing of the volume and minimizes nitrogen usage and the time required for the inerting process. The use of jet mixing to ensure an adequate oxygen level before entry is also discussed in Part 2.

to a greater or lesser extent. However, Figs. 1 and 2 are adequate to describe the basic principles involved with inerting a system. In Figs. 1 and 2 the flammable regions (i.e., the range of mixtures of nitrogen, oxygen and methane that will ignite if provided with a suitable ignition source) are shown within the pink region. Compositions outside of this flammable region will not ignite no matter what type of ignition source is provided. However, if the composition is changed by adding or removing one or more components and the composition is then within the flammable region, ignition is then possible. The intent of inerting is to ensure that the mixture is always in the nonflammable region. While the lower and upper explosive limits (LEL) and (UEL) are published for many materials and certainly can be used to assess the mixture flammability characteristics, reducing the oxygen level below the point where ignition is possible provides an alternative and direct approach to managing the risk associated with handling flammable materials. Referring to Fig. 1, it can be seen that as the oxygen concentration is lowered, the methane concentration range within which the mixture is flammable also is reduced. Thus at 100% oxygen 100

Requirement for inerting and/or purging. Generat-

70 Fuel 60 (methane) 50

Air li

ing flammable mixtures inside process equipment vapor spaces has been a primary cause of numerous fires and explosions when an ignition source has been present. In some instances leakage from inadequately inerted vapor spaces has also resulted in fires outside of the contained volume. Eliminating all ignition sources at all times is not possible and so the general approach taken throughout the process industries is to attempt to eliminate the potential for forming a flammable mixture while also attempting to minimize ignition sources. This usually involves injecting an inert gas so that the oxygen level in the system is below the minimum oxygen concentration (MOC) or limiting oxidant concentration (LOC)—these terms are used interchangeably. In addition, it is usual to ensure that an adequate safety margin is applied to the MOC/LOC. Fig. 1 shows the three-component flammability diagram for the methane/oxygen/nitrogen system. Fig. 2 shows a portion of Fig. 1 in the region of particular interest in relation to the inerting process. Each material, or material mixture, will have a specific flammability diagram, and temperature will alter the boundaries

Nitrogen 50 60

Stoic

hiom

etric

line

UEL

Flammable mixtures

80 90

LEL

0 100 FIG. 1

50 40 Oxygen

100

20 10 0 LOC = 12 vol% O2

Flammability diagram for methane/oxygen/nitrogen— volume% (Source: Wikipedia). HYDROCARBON PROCESSING MAY 2010

I 35

SPECIALREPORT

MAINTENANCE/RELIABILITY

and 0% nitrogen the flammability limits for methane are approximately 5% vol. methane (LEL) – 61% vol. methane (UEL). As the oxygen concentration is reduced (i.e., as nitrogen is added) the flammability limits narrow. The blue line in Figs. 1 and 2 show the air composition—i.e., at 0 % vol. methane the oxygen concentraAir line UEL Stoichiometric 90 Region of ﬂammable mixture LEL 100 10

LOC = 12 vol% 02

Oxygen FIG. 2

LOC for methane/oxygen/nitrogen—volume % (Source: Wikipedia).

TABLE 1. Selected LOC values for various flammable chemicals Gas or vapor

LOC N2/air

LOC CO2/air

Methane

14.5

Ethane

13.5

Propane

11.5

14.5

n-Butane

14.5

Isobutane

n-Pentane

14.5

11.5

Ethylene Propylene

11.5

Benzene

11.4

Toluene

9.5

–

Styrene

9.0

–

Ethyl benzene

9.0

–

Gasoline (73/100)

Gasoline (100/130)

Gasoline (115/145)

14.5

Isobutylene

Kerosene (150°C)

Natural gas

14.5

Acetone Carbon disulfide Carbon monoxide Ethanol Hydrogen

11.5

7.5

5.5

10.5

5.2

7.5

11.5

Methanol

Propylene oxide

7.8

–

Methyl ether

10.5

Vinyl chloride

13.4

–

Hydrogen sulfide

Vinylidiene chloride

(Source: NFPA 69) Note—NFPA 69 also contains tables providing LOC values for dusts (agricultural, chemical, metal, plastic and miscellaneous substances).

I MAY 2010 HYDROCARBON PROCESSING

tion is approximately 21% vol. As the air composition line crosses the flammability envelope it can be seen that the LEL is 5% vol. methane and the UEL is 15% vol. methane, which are the figures used when assessing flammability in air at ambient temperatures. The stoichiometric composition line (i.e., the line representing the exact amount of air to provide the required oxygen to fully react with the methane) is shown in red in Figs. 1 and 2 and runs through the approximate center of the flammability range. As the oxygen concentration is decreased below approximately 21% vol. in air the flammability range decreases still further until, at approximately 12% vol. oxygen, the mixture becomes nonflammable or inert. Thus if the oxygen level in a nitrogen/ oxygen/methane system can be maintained below 12 % vol. then no ignition is possible. However, just maintaining 12 % vol. would leave no margin for error and would also assume that the instrumentation was completely accurate and that it was reading the highest oxygen level in the system. To provide an adequate safety margin to account for instrumentation error and the possibility that the sample read by the instrumentation is not fully representative of the complete volume, NFPA 69 (Reference 10) provides the following recommendations concerning the LOC at which the system should be operated: • Where the oxygen concentration is continuously monitored, a safety margin of at least 2 vol.% below the LOC shall be maintained unless the LOC is less than 3 vol %, in which case the equipment shall be operated at no more than 60% of the LOC. • Where the oxygen concentration is not continuously monitored, the oxygen concentration shall be designed to operate at no more than 60% of the LOC, or 40% of the LOC if the LOC is below 5vol.%. If the oxygen concentration is not continuously monitored, the oxygen concentration shall be checked on a regular basis. In addition, NFPA 69 contains recommendations concerning the instrumentation required to ensure that the desired oxidant concentration reduction has been achieved and is maintained during all phases of operation. Instrumentation details required to meet these recommendations are outside of the scope of this article. However, providing a purging system without providing and maintaining an adequate instrumentation system will not result in an acceptable risk management level. Table 1 presents MOC/LOC values for a range of chemicals with the inerting gas being either nitrogen or carbon dioxide and is excerpted from NFPA 69. NFPA 69 also includes additional tabulations of MOC/LOC values for other materials and for dusts of various types. Additional discussion of the use of the MOC/LOC concept together with a calculation method for estimating values for materials for which data are not published is provided in reference 3 (Note that a correction to the article is also referenced). In some situations, inert gas injection is used only for a short time to ensure that a tank or vessel is fully purged and inerted before operations start. In other cases where oxygen or another oxidant is, or could be, generated, a continuous inert gas stream may be used to ensure that a flammable mixture does not occur within the tank vapor space or in the vapor stream passing to downstream equipment. Such an approach may be employed where oxygen generation occurs constantly or during upset conditions within a tank or vessel. Tank system purging with air may be employed when it is necessary to ensure that there is an adequate oxygen level to support life before inspection or maintenance activities are performed. Numerous fatalities have occurred where personnel have entered enclosed

MAINTENANCE/RELIABILITY O2

Nitrogen purge Full-pipe ID injection

Purge outlet Localized mixing

Minimal bulk mixing Stagnant zone

FIG. 3

Example of inadequate bulk mixing in a large tank.

Minimal bulk mixing

N2 outlet

Localized bulk mixing

N2 outlet

Localized bulk mixing

Minimal bulk mixing

FIG. 4

Plan at roof seam.

spaces where there was an inadequate oxygen level. However, it is critically important to ensure that introducing air to protect human activity within the vessel will not generate a flammable mixture. Implicit vapor phase mixing assumptions. Several

excellent articles have been published describing inerting or purging procedures for equipment.1,2 However, an implicit assumption in these discussions is that the vapor spaces will be well mixed (by inerting-gas injection or by repeated emptying and filling). In some situations, particularly for large volumes, this may not be an appropriate assumption. The reason is that an inerting or purging gas stream is usually introduced into the tank via a full-diameter nozzle. Even a small pipe has a cross-sectional area that will generally result in a “low” injection velocity. By “low” it is meant that the injected gas jet does not have a velocity high enough to allow it to maintain coherence for a significant distance, let alone for the full vapor space depth in the tank. Since the inlet nozzle is usually placed in the tank upper section, the inerting or purging gas flow will tend to penetrate only into a localized tank volume. The inerting gas velocity will stagnate and then move slowly toward the outlet nozzle (Figs. 3 and 4). In such situations, only localized tank sections will experience adequate mixing, i.e., the Select 159 at www.HydrocarbonProcessing.com/RS 37

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MAINTENANCE/RELIABILITY upper tank volume around the inlet and outlet nozzles. The bulk of the tank only experiences a limited diffusional process. If the tank is “small” this situation may result in adequate purging or inerting. However, if the tank is “large” inerting or purging may not be achieved throughout the whole vapor volume. A similar concern may arise where an oxygen analyzer is used to monitor the outlet vapor stream for a “large” tank. The analyzer may indicate that there is little oxygen present; however, the inherent assumption in using an analyzer for such a purpose is that the outlet vapor stream composition is representative of the entire tank vapor space. In large tanks that are being purged or inerted, or where the geometry is complex, this may not be true if mixing within the tank or system is inadequate. The erroneous assumption that an oxygen analyzer on a vapor purge stream from a large tank was reporting an accurate measurement of the bulk tank vapor space oxygen content was a contributory factor in at least one major incident that resulted in multiple fatalities. Even when using purging only during the preparation for startup, the effectiveness of the purging is usually assessed by monitoring the oxygen concentration in the vapor exiting the system being purged. Thus, again, the assumption is made that the oxygen analyzer is providing a representative measurement and, if the mixing is inadequate, this assumption may be erroneous. It is possible to assess the degree of mixing occurring within a tank during purging or inerting activities by monitoring the outlet concentration of a gas (e.g., oxygen) during a step change in operating conditions. How closely the outlet concentration change corresponds with that predicted, assuming that the tank is fully mixed (i.e., it is acting as a CSTR), is indicative of the effectiveness of the bulk mixing process. Such a step change in conditions might involve injecting a tracer gas, starting/stopping inerting gas flow, etc. If the outlet gas concentration change differs significantly from that predicted, then the tank is inadequately mixed and some method of mixing the vapor space should be employed. It is also possible to use three-dimensional computer flow modeling to examine such situations. This approach requires sophisticated software and adequate expertise and is not normally employed.

SPECIALREPORT

another inerting gas, and then vented. This procedure is repeated until the vessel or system is considered to be inerted. The system inerting effectiveness is usually assessed by measuring the exit oxygen concentration during the vent and complex geometries may require multiple exits. However, there is no direct assurance that full mixing of the volume to be inerted has occurred. In addition, a slight positive pressure must be maintained after purging has been completed to ensure that air (and thus oxygen) does not re-enter the system before or during operations where a flammable mixture could be generated. • Air displacement. In this method the inert gas is often introduced at a low point in the vessel or system (via a nozzle

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“Conventional” inerting methods.

Several methods of inerting vessels have been developed and generally rely on repeated equipment filling and emptying, which requires time and increases purge gas usage. These methods are discussed briefly below and more detailed discussions are provided in references 1 and 2. • Pressurize and vent. In this method the vessel is pressurized using nitrogen or Select 160 at www.HydrocarbonProcessing.com/RS 39

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CHAS. S. LEWIS & CO., INC.ÊUÊnÈÓxÊ À> ÌÊ, >`ÊUÊ-Ì°Ê Õ Ã]Ê ÃÃ ÕÀ ÊÈÎ£ÓÎÊ1°-° ° /i i« i\ÊÎ£{®Ên{Î {{ÎÇÊUÊ/i iv>Ý\ÊÎ£{®Ên{Î Ç È{ÊUÊ > \ÊÃ> iÃJ iÜ Ã«Õ «Ã°V Ê

MAINTENANCE/RELIABILITY or a dip-pipe). The inert gas is introduced continuously until the system is considered to be inert. A number of vessel volume equivalents of inert gas are usually required. The precise minimum number must be determined and demonstrated when the vessel or system is first commissioned and revalidated regularly. Where the system comprises of complex geometries, multiple vent locations may be required. The vessel vent(s) must remain open during purging and the displaced gases/vapors must be discharged to a safe location considering potential flammability issues and environmental concerns. • Vacuum and inert gas. In this method a vacuum is generated inside the equipment and then the inert gas is introduced to break the vacuum. The vacuum inside the vessel assists the inerting as the inert gas fills the whole system. However, this method requires additional equipment and the system components must be designed to withstand the lowest pressure that could be generated and this may increase the capital costs. When utilizing this system, it is essential to ensure that only the inert gas can pass into the vessel when it is under vacuum. If air leakage occurs then adequate inerting will not be achieved and a false sense of security would exist as to the condition of the vapor space within the vessel or system. Therefore, this system requires particular care when it is employed. The number of cycles required for full inerting must be determined and demonstrated when the vessel is first commissioned and revalidated regularly. • Siphon purging. This method is similar to vacuum purging, but in this case the inert gas is induced to flow by emptying liquid from the vessel or system. Thus, the system must first be filled with liquid and then allowed to empty for this process to be effective. However, as for the vacuum process, there cannot be any significant leakage into or out of the system as, otherwise, the effectiveness of the inerting process could be rendered ineffective. An expanded discussion on vacuum, pressure and suction purging is presented in references 1 and 2 together with equations to estimate the number of cycles required. Guidance is also provided as to how the effectiveness of these processes can be assessed. However, the effect of the equipment or system geometry is not discussed in detail in these references and, hence, no differentiation is made between a tall narrow tank, a short wide tank or a complex interconnected system.

SPECIALREPORT

Jet mixing. In jet mixing the inerting gas is introduced via an orifice, or series of orifices, so that the gas jet velocity is high so that it penetrates deeply into the vapor space to be inerted. This also allows the jet energy to be utilized to entrain the vapor in the vapor space and provide high mixing levels as well as providing the inerting associated with introducing the inerting gas. The mixing and inerting combination provided by the jet concept allows for rapid inerting and a high confidence level that the inerting process has been effective and can be reproduced. While diffusional methods may be effective, the jet mixing has the advantage of significantly increased confidence in achieving the required mixing and the reduced time and nitrogen usage required to achieve full equipment purging. The jet mixing concept is discussed in more detail in Part 2 of this article, which will be published in our June issue, together with design equations and recommendations for installing, commissioning and testing the system. HP

1 2 3

LITERATURE CITED Kinsley, Jr., G. R., “Properly purge and inert storage vessls,” CEP, February 2001. Blakey, P. and G. Orlano, “Using inert gases for purging, blanketing and transfer,” Chemical Engineering, May 26, 1994. “Predict Safe Oxygen in Combustible Gases”, T. K. Subramaniam and J. V. Cangelosi, Chemical Engineering, December 1989 and Correction in Chemical Engineering January 1990 Page 8.

Martin Gollin is a consulting engineer associated with Carmagen Engineering, Inc. He has been involved in numerous projects as a consultant, and has been a member of several National Academy of Science Committees dealing with the destruction of chemical weapons. Prior to his consulting career, Mr. Gollin was with ARCO Chemical Company where his responsibilities included process design, process safety, EH&S and heat transfer equipment. He was the EH&S Manager for a $1billion grassroots project in the Netherlands and was involved in numerous engineering, design and troubleshooting activities. Prior to joining ARCO Chemical, Mr. Gollin worked for an R&D Company and for an engineering contractor for 10 years. He has extensive process engineering experience in numerous technologies. Mr. Gollin was part of the group that wrote the CCPS book Layer of Protection Analysis (LOPA) and has presented courses for AIChE/ASME (“LOPA” and “Process Design for Safe Operations”), and other courses on process design, heat exchangers and various process safety topics. He received his B.Sc. and his M.Sc. degrees in Chemical Engineering from Loughborough University of Technology in England.

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MAINTENANCE/RELIABILITY

SPECIALREPORT

Heat-exchanger failure analysis in a naphtha cracking unit This case history analyzed the failure and makes recommendations to prevent future failures M. SABABI, Shahid Chamran University, Ahwaz, Iran; and M. MAZUCHI and S. A. MONEMIAN,* University of Tehran, Tehran, Iran

orrosive components in feed streams, as well as in complete refinery processes, are a major cause of heat-exchanger tube failure. These types of failures are usually related to a complex deposition mechanism formation and growth. Deposit layer thickening hinders heat transfer and obstructs pipe. In this article, a special failure case study is investigated in which corrosion products formed in the condenser, then transferred and piled up in the next heat exchanger. The failure was analyzed from different viewpoints and some methods are recommended to prevent this type of failure.

65째C. Then the stream enters a shell-and-tube heat exchanger (E-2003) and exits it at 45째C. Shell-and-tube heat exchanger E-2003 has experienced corrosion and fouling since startup, leading to unscheduled shut-

AE-2001

PV-20041B D-2002

Introduction. The problems associated with heat-exchanger

TK-2003

T-2001

fouling have been known since the invention of the heat exchanger. Despite the best efforts of engineers and technologists to reduce or eliminate heat-exchanger fouling, the deposit growth still occurs in some cases. Periodic heat-exchanger cleaning is necessary to restore the heat exchanger to efficient operation. Scheduled and unscheduled shutdowns for cleaning can be very expensive because the startup may be very time consuming. Thus, anything that can be done to reduce these shutdowns along with the cleaning procedure will be of great benefit. When corrosion combines with fouling, the problem will be more serious and complicated. Handling such a system requires more experiments and gathering data from the system. Material selection for process equipment construction has a significant impact on plant efficiency. Among available metals and alloys, a few can be used for process equipment and piping construction. Carbon steel is used for most components in refineries because they are inexpensive and readily available while it can cause a lot of corrosion problems.1

N2 for startup

PV-20041A

E-2003 FV-20020

LV-20011

P-2003A/B

PV-20007 P-2002A/B H-2001 FIG. 1

Schematic diagram of the studied system.

FIG. 2

Deposit obstruction in shell-and-tube heat exchanger.

Failure description. A schematic diagram of this system

(which is a part of unit 200 of Bou Ali Sina Petrochemical Co.) is illustrated in Fig. 1. Distillation column T-2001 separates the feed stream into fractions of different boiling point ranges at about 5 bar. The most important fraction is the light end (C7 -) that is introduced to the overhead system. Air cooler AE-2001 condenses the naphtha stream where a part goes to product and the other is used for reflux stream D-2002. Inlet temperature to the cooler is 120째C and outlet temperature is *Corresponding author

HYDROCARBON PROCESSING MAY 2010

I 43

SPECIALREPORT

MAINTENANCE/RELIABILITY Thermogravimetric curve

120

Deposit residue, %

100 80 60 40 20 0 0

200

400

600 800 Temperature, °C

1,000

1,200

Deposit residue thermogram.

FIG. 4

2003 in 2003 out Feed 2001 in Benzene

Cyclopentane, methyl

Hexane

Pentane, 2-methyl

Pentan

2,2-Dimethylbutane

Butane

Propane

Propane, 2-methyl

Butane, 2-methyl

Pentane, 3-methyl-

-5 0

FIG. 5

FIG. 3

Tube bundle after cleaning (above) – before cleaning (below).

TABLE 1. Data obtained from thermogravimetry analysis Light hc and humidity

Weight loss at 105°C

13.1%

Organic share

Weight loss at 600°C

21.2%

Carbon residue

Weight loss at 1,000°C

Inorganic share

Residue at 1,000°C

1.7% 64.0%

TABLE 2. Feed special components traces Feed special component H2S Cl– Water

Concentration, ppm 100 3 160

downs for maintenance and cleaning. The fouling problem occurs seriously every month and the unit shuts down for 5–7 days because of deposit obstruction as shown in Fig. 2.

10 11 12 13 14 15

Stream composition analysis.

corrosion particle surface or corrosion under the deposit. It is possible that the deposit accelerates heat-exchanger corrosion. Some corrosion fouling is initiated by surface particles subjected to corrosion. To understand the mechanism exactly, several experiments should be done. Streams, deposits and also tubes were analyzed to precisely reveal the failure mechanism. Internal deposit quantitative analysis. The deposits examined visually have a spongy, brittle, easily divided powder structure at the shell side (Fig. 3). Fig. 4 shows the deposit residue thermogram. Detailed data are presented in Table 1. Charred residue was analyzed and found to have 66.5 iron element (Fe) wt%. This high iron amount suggests that corrosion products are more than expected. As can be seen in Fig. 3, the clean tubes are observable. Therefore, it is difficult to consider that all these products come from the tube bundle itself. A new hypothesis suggests that the products come from other places, especially the air cooler. The organic share contains heavier hydrocarbons, oligomers and macromolecules derived from epoxyethane (ethylene oxide) as indicated by GCMS analysis. However, solvent analysis does not show any further information. The aim of this work is not to study organic share in detail. Streams analysis. No evidence is found about column abnor-

Failure mechanism analysis. Two hypotheses may be

proposed: local corrosion followed by organic deposition on the 44

I MAY 2010 HYDROCARBON PROCESSING

mal observation in which heavy hydrocarbons are seen at the column top. Although H2S concentration is high, H2S cannot cor-

MAINTENANCE/RELIABILITY

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SEM micrographs of corroded regions.

rode surfaces since a protected sulfide layer is formed. However, a small amount of chlorides (about 1.4 wt% of water concentrated at dew point) can corrode the air cooler surface. Analysis of four streams, i.e., before feed, air cooler inlet, and heat-exchanger inlet and outlet were done by GCMS to determine whether the organic deposition can happen before corrosion or not. As shown in Fig. 5, there is no special reaction evidence in the heat exchanger. Select 162 at www.HydrocarbonProcessing.com/RS 45 vwe1002_AZ_85x255_US.indd 2

19.02.2010 13:39:16 Uhr

SPECIALREPORT

MAINTENANCE/RELIABILITY esis of local corrosion and organic deposition cannot be reliable because the tube bundle would be disordered by so much corrosion products. The corrosion products settle due to high residence time in the heat exchanger. The drum water drainage experiment showed the amount of chlorides to be in the range of 120-440 ppm supporting the mechanism discussed previously. Inspecting the air cooler (Fig. 7) demonstrates the serious corrosion problem. The chloride content is composed of sodium, calcium and magnesium chloride. Magnesium and calcium chloride start to hydrolyze at 120 and 220°C, respectively. Sodium chloride does not hydrolyze at such normal temperatures in the reboiler. CaCl 2 + 2 H 2 O Ca (OH)2 + 2HCl MgCl 2 + 2 H2 O Mg (OH)2 + 2HCl

FIG. 7

Air cooler corrosion product accumulation.

Tube. The morphological pictures of corroded regions are shown in Fig. 6. These SEM micrographs demonstrate corrosion product deposition and metallurgical defects in base steel alloys. Corrosion mechanism. As discussed previously, the most probable mechanism is overhead acid corrosion and the hypoth-

Reboiler tower outlet temperature is around 230°C and, therefore, the evolved hydrochloric acid is distilled up to the overhead system. The initial condensate forms after the vapor leaves the column containing a high percentage of HCl. Due to the high acid concentration dissolved in the water, the pH of the first condensate is quite low. Therefore, at dew point water condensate corrodes the low-carbon-steel air cooler. Corrosion by acidic chloride condensates is driven by the hydrogen ion concentration (pH) via the reaction: Fe + 2 HCl FeCl 2 (soluble) + H2

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SPECIALREPORT

MAINTENANCE/RELIABILITY

Although the corrosive attack source is HCl, the corrosion product is iron sulfide, not iron chloride. Iron sulfide is precipitated by the reaction between H2S and soluble iron chlorides from the corrosion reaction between HCl and iron.

sible since no desalter exists. Secondly, corrosion inhibition and remaining foulant dispersment should be tackled directly in the overhead system. The most efficient method to determine the inhibitor amount is monitoring.5 HP

FeCl 2 + H 2 FeS2 + 2HCl 1

HCl does not consume and react as a catalyst in the system. Iron sulfides can be seen in Fig. 7—by its black color. Since the feedstock composition introduced to the column, and also column operating conditions have a lot of fluctuations, the dew point, and also the corroded regions, are displaced to another region. Therefore, the air cooler tubes are not fractured.

2 3

Conclusion. Desalting to 1 ptb can keep lower overhead con-

densates below 50 ppm of hydrochloric acid. A 50-ppm concentration of hydrochloric acid in the overhead system is completely corrosive to carbon steel. The overhead condensates should have HCl lower than 10 ppm.2 Solutions to the problem are categorized as: • Neutralizer injection • Chemical or electrical desalters before the column • Temperature control in the overhead system to control the water dew point • Organic corrosion inhibitor injection4 • Coalescer usage to free the feed from the water. Material selection is important when design is considered, but there is no way to change the material. First, the free-water, and thus, feed salt content should be reduced as much as pos-

LITERATURE CITED Gutzeit, J., Merrick, R. D., Scharfstein, L. K., “Corrosion in Petroleum Refining and Petrochemical Operations,” ASM Metals Handbook, vol. 13, p. 1262. Kenneth, W. Warren, “Reduction of corrosion through improvements in desalting,” Benelux refinery symposium, Lanaken (Belgium), 1995, p. 1–11. Jenabali Jahromi, S. A., and Janghorban, A., “Assessment of corrosion in low carbon steel tubes of shiraz refinery air coolers, “Engineering Failure Analysis” 12 (2005) 569–577. French, E. C., and Fahey, W. F., “Water soluble filming inhibitor system for corrosion control in crude unit overheads,” Materials Performance, September 1983. Miller, R. G., et. al. “Corrosion monitoring in refinery overheads,” CORROSION/90, paper #211, NACE, Houston, Texas, 1990.

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MAINTENANCE/RELIABILITY

SPECIALREPORT

Oil-mist lubrication for fin-fan shafts Tests show it is superior to grease lubrication P. W. DUNCAN, Colfax Corporation, Monroe, North Carolina

ir-cooled heat exchangers (ACHEs) are used in refineries and petrochemical plants to remove heat from process fluids by rejecting it to ambient air. Until recently, traditional grease-lubricated bearing technology handled the bulk of bearing lubrication in the system’s machinery, but recent research suggests that oil-mist alternatives can actually add years of performance to the bearings. An ACHE usually consists of a variety of components: a fan, a fan ring, a plenum, inlet and outlet nozzles, a header, a tube bundle and a drive assembly. Traditionally, the drive assembly bearings have been grease-lubricated, a solution that has led to a number of challenges. Independent studies and numerous user interviews have shown that grease-lubricated bearing life is typically just two years or less because of several factors: • Grease degradation at elevated temperatures • Contaminants from the environment • Improper grease amounts applied to the bearings • Bearing misalignment at initial setup • Drive belt overtightening • Shaft thermal expansion beyond the upper-bearing axial-free movement. With those issues in mind, a recent research project sought to test a solution that could add years to the bearing lives by utilizing an oil-mist-lubricated bearing and seal system (Fig. 1).

Advantages of oil-mist lubrication. Oil mist is already

a time-tested lubrication means that typically requires less maintenance than a grease system and produces much longer bearing life. Those built-in benefits are largely due to constant replenishment with clean, cool lubricant. Additionally, oil mist maintains positive pressure in the bearing housing, which prevents ingress of ambient contaminants. With grease-lubricated bearings a finite amount of oil is contained in a suitable soap matrix. Temperature gradients and capillary action allow oil to move out of the surrounding soap matrix and cause this oil to coat bearing elements. However, should wear occur, the wear particles would likely be retained in the bearing and could induce abrasive failure. An oil-mist system, in contrast, keeps the bearing flushed of any wear particles. Perhaps the greatest challenge in using oil-mist-lubricated bearings in ACHE applications is oil-mist containment within the bearing housing. This is largely because of issues with the close runout tolerances required on rotary seals. Any stray mist can potentially be blown onto the ACHE tubes and fins and this could cause dust or debris to stick to it. A reduction in the unit’s efficiency might result.

It is acknowledged that the major bearing manufacturers have at their disposal special spherical roller bearings intended for vertical shafts.1 The same can be said for special rotating labyrinth-style bearing protector seals that incorporate swivel action and have significant axial movement capability.2 Nevertheless, some of the more traditional low-cost bearing designs and installation practices do not always maintain the precise alignment required between the shaft and the seal, which is conventionally pressed into the bearing housing and seals against the shaft. When alignment between the shaft and seal is not precisely maintained, seal life and performance are compromised, because those designs do not accommodate any misalignment between the housing and the shaft bearing. A new design (Figs. 2 and 3) for the oil-mist-lubricated bearing assembly was developed and tested for the research project; it addresses a number of critical issues: • Maintaining seal, shaft and bearing alignment, regardless of shaft orientation (since the seals travel with the shaft and seal holder simultaneously) • Developing slight positive pressure in the bearing housing to prevent ambient contaminant ingress • Maintaining a constant flow of cool, clean oil mist to prevent lubricant breakdown • Utilizing a shaft-locking device that centers the shaft in the bearing, to ensure the shaft runs true • Allowing up to 20° of misalignment between upper and lower bearings eliminating any need to shim bearings at installation • Accommodating shaft axial thermal expansion to prevent bearing overloading. Four-pronged performance testing. The research proj-

ect—designed to test oil-mist lubrication system performance—

FIG. 1

Two ACHEs employed to test oil-mist and greaselubrication at the facility in North Carolina. HYDROCARBON PROCESSING MAY 2010

I 49

SPECIALREPORT

FIG. 2

FIG. 3

MAINTENANCE/RELIABILITY

A new patent-pending design for an oil-mist-lubricated bearing assembly solves the lubrication problems previously encountered with grease systems.

The oil-mist-lubricated bearing assembly can accommodate up to 20º of misalignment.

consisted of four distinct categories: “accelerated bearing life,” “normal belt loading,” “fan testing” and “stand-alone seal testing.” Tests for the first two categories were performed on test stands designed to simulate fan loads. The third was performed on actual ACHE units. The final category was tested on seal test rigs that assessed only the seal’s performance, not that of the bearing. In all tests, greaselubricated bearings were lubricated per the manufacturer’s recommendations. Following is a synopsis of the testing procedures: Accelerated bearing life. Four sets of oil-mist-lubricated bearing assemblies and three sets of grease-lubricated bearing assemblies were placed onto an accelerated test rig. The alignment between the top and bottom assemblies was adjusted to be between 0 and 1½°. A side load of approximately 8,100 lbs was applied to the shaft, just below the bottom bearing, to simulate 4½-times baseline belt loading on the lower bearing and 2-times baseline radial load conditions on the upper bearing. An axial load of approximately 5,200 lbs was applied to the top of the shaft to simulate 3½-times baseline fan loading on the lower bearing. The bearings were arranged so that the lower bearing carried all thrust loads and a large portion of the radial load. The shaft was then spun at 300 rpm. Normal belt loading. In this segment, three sets of oil-mistlubricated bearing assemblies were placed onto a test rig, with the alignments between the top and bottom bearings set at 0°. A 50

I MAY 2010 HYDROCARBON PROCESSING

FIG. 4

The grease-lubricated bearings exhibit pitting after 2,000 hrs.

side load of approximately 2,700 lbs was applied to the shaft, just below the bottom bearing, to simulate 1½-times normal radial bottom-bearing belt loading. The decreased loading was done to verify that excessive belt loading can influence seal performance. A heavier axial load of approximately 5,200 lbs was still applied to the top of the shaft to simulate 3½-times normal fan loading and to expedite failure. Fan testing. A set of both oil-mist and grease-lubricated bearings was placed onto actual fans. The bearing loading was estimated to be 646 lbs radial load on the lower bearing and 112 lbs radial load on the upper bearing. The axial force on the lower bearing was approximately 643 lbs, based on fan calculations. The shafts were then spun at 280 rpm for the testing duration. For all three of the above categories, vibration levels, temperature and shaft speeds were constantly monitored for all bearings. Seal performance was monitored daily. Stand-alone seal testing. Three different seal types (one mechanical-face seal and two lip-seal variations) were placed onto a stand-alone seal-test stand that consisted of 10 vertically mounted shafts spinning at 300 rpm. A single set of seals was mounted on each shaft and individually lubricated with ISO Viscosity Grade 68 synthetic oil mist. The seals ran for a minimum of 350 hrs. Seal leakage was monitored daily, and at the completion of testing, the initial seals were removed and replaced with a new set. Oil-mist results. Results of the multifaceted testing clearly demonstrated the advantages of oil-mist-lubricated bearing technology. All of the oil-mist-lubricated bearings survived more than 2,000 hrs of continuous run time under simulated overload conditions; the bearing races, balls and cages showed no signs of any damage at the completion of the tests. Additionally, the monitored changes in temperature and vibration levels were insignificant for all the oil-mist-lubricated bearings tested. In contrast, some of the grease-lubricated bearings showed signs of extreme vibration after only 24 hours. Upon disassembly after the 2,000-hr run time, these bearings exhibited extreme pitting (Fig. 4). In addition to successfully surviving accelerated bearing-life tests, the oil-mist-lubricated bearings appeared pristine after the normal-belt-loading testing. After 2,000 hrs, the bearings were disassembled and showed no signs of wear (Fig. 5). And just as important, there were no seal leaks on any of the bearing assemblies. Both the oil-mist and grease-lubricated bearings were allowed to run for almost 5,000 hrs as part of the fan-testing research segment. Again, the oil-mist-lubricated bearings did not show any sign of increased vibration or wear. The grease-lubricated bearings,

MAINTENANCE/RELIABILITY

SPECIALREPORT

deflection or excessive runout. Testing also demonstrated that the most reliable and robust seal designs for bearing assemblies are cartridge-lip seals. In essence, accelerated wear tests confirmed that continuous oil-mist lubrication is superior to traditional grease-lubrication methods. The newly designed oil-mist-lubricated bearing assembly both accommodates misalignment conditions existing in ACHE applications and effectively seals all oil mist within the bearing cartridge and closed-loop oil-mist system. Additionally, bearing overloading due to shaft thermal growth has been eliminated, making the newly designed oil-mist-lubricated bearing uniquely suited for the reliability challenges of ACHE applications. HP LITERATURE CITED 1 2

FIG. 5

The oil-mist-lubricated bearing shows no signs of wear after 2,000 hrs.

however, did exhibit evidence of overall vibration-level increases during the test. Upon disassembly, researchers discovered the outer race on the bottom grease-lubricated bearing had slight signs of brinelling, while the inner race of the top grease-lubricated bearing had significant pitting and fretting. Stand-alone seal testing demonstrated that mechanical-face seals perform at acceptable levels, as long as there is no shaft

SKF USA Marketing Literature, “Spherical Bearings for Vertical Shafts,” Marketing Communications Department, Kulpsville, Pennsylvania. AESSEAL Marketing Literature, “Angular Shaft Misalignment,” also “LabTecta AX Bearing Protector Seals,” Rotherham, UK, and Rockford, Tennessee.

Patrick W. Duncan is a senior design engineer for the Imo Pump division of Colfax Corporation (NYSE: CFX), a global leader in critical fluid-handling products and technologies. Through its global operating subsidiaries, Colfax manufactures positive-displacement industrial pumps, lubrication systems and valves used in oil and gas, power generation, commercial marine, defense and general industrial markets. Located in Monroe, North Carolina, USA, he is responsible for developing, designing and supporting rotating equipment and lubrication systems, including positivedisplacement pumps and pumping systems. Mr. Duncan is a 1998 graduate of North Carolina State University in Raleigh, North Carolina, USA, a member of the American Society of Mechanical Engineers and has nine years of service with Colfax.

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PETROCHEMICAL DEVELOPMENTS

Fundamental changes coming in Asia’s petrochemical industry Massive new processing additions will impact operations in this region as well as in the global market P. KUMAR and L. ZHANG, FACTS Global Energy, Inc., Honolulu, Hawaii

25 Firm and likely additions 2H 2009–2015 Capacity in July 2009

20 15 10 5

FIG. 1

Thailand

Taiwan

S Korea

Singapore

Malaysia

Japan

Indonesia

India

China

0 Australia

Ethylene production capacity, million tpy

Trends in the Asian ethylene industry. Asia, already a significant player in the global ethylene market, is adding capacity at a fast rate. With about 40 million tpy (MMtpy) of ethylene capacity in place in 2009, Asia is adding a further 20.2 MMtpy by 2016. Figs. 1 and 2 indicate that around 50% will be added to the current capacity over the next 6.5 years with strong peaks until Q1 2010. These peaks are mainly due to China and India. China will be responsible for 59% of the new capacity. In 2005, China surpassed Japan to rank second globally in terms of ethylene production capacity. It is currently behind the US by a whopping 25 MMtpy, but this gap is narrowing fast. China has 10.8 MMtpy of ethylene capacity in place. Of the further 11.8 MMtpy capacity that the country will add through 2015, 50% will be achieved before 2012. By 2016, China will have more ethylene production capacity than Japan, South Korea and Taiwan combined. Recently, the Sinopec/ExxonMobil/ Saudi Aramco joint venture began production from an 800,000 tpy (800 Mtpy) ethylene plant at Fujian. Meanwhile, in early November, the Sinopec/SABIC Tianjin JV started trial runs at their 1 Mtpy ethylene plant. PetroChina has also started trial runs at its 1 MMtpy Dushanzi ethylene plant. Sinopec’s Zhenhai ethylene plants began trial runs in early February 2010 , and PetroChina’s Qinzhou will start trial runs soon. Both facilities will each add 1 MMtpy of new ethylene capacity. At the present, China’s demand for ethylene equivalent far exceeds domestic supplies. It produced slightly more than 10

million tons of ethylene equivalent in 2008, while import needs stood at 12 million tons. For 2009, China’s ethylene equivalent demand increased by more than 20%, thanks to the 4 trillion yuan (US$ 586 billion) stimulus plan and other policies to boost domestic consumption. Almost all of the increases in basic petrochemicals demand this year was met by imports. Table 1 indicates

Asia-Pacific ethylene production capacity by nations.

6 Ethylene capacity, million tpy

he Asian petrochemical sector is witnessing rapid fundamental changes as indicted by: • Emergence of China as the largest petrochemical producer in Asia • Rise in Middle East production capacity that is based on cheap gas • Huge potential Chinese demand for basic chemicals as its economy grows • Advent of the KG-D6 natural gas development project in India that will substitute naphtha as a feedstock in the petrochemical sector and emerge as exports within the region. So what are the fundamental changes that are presently under way and what are the possible implications for Asia-Pacific naphtha demand? This article will discuss both questions and highlight growing trends in Asia.

Thailand Taiwan S. Korea

Singapore India China

4 3 2 1 0 1H 2009

FIG. 2

2H 2009

2010

2011

2012

2013

2014

2015

Asia-Pacific ethylene production capacity additions—2009 to 2015 by nations. HYDROCARBON PROCESSING MAY 2010

I 53

120 Aromatics capacity additions, 2008–2015, million tpy

110 100 90 80 70 60 50 Q1 2008

Q2 2008

Q3 2008

China

Q1 2009

S Korea

Q2 2009

Q3 2009

Taiwan

Q4 2009

35 Firm and likely additions 2H 2009–2015 Current aromatics capacity in July 2009

30 25 20 15 10 5

Thailand

Taiwan

S. Korea

Singapore

Malaysia

Indonesia

India

FIG. 4

Asia-Pacific aromatics production capacity by nations.

TABLE 1. China net import of ethylene derivatives— thousand tpy Styrene PE

PVC

monomer

2007

4,473

551

4,800

3,101

2008

4,411

481

5,187

2,809

2009

7,383

1,680

5,821

3,638

249

y-o-y growth rate, %

that the Chinese net imports of polyethylene in 2009 increased by a staggering 67% year-over-year (y-o-y). In the longer term, backed by strong economic growth, we expect robust demand but do not anticipate a repeat of the staggering growth that was experienced in 2009. High import requirements by the Chinese have benefited Korean, Taiwanese and Japanese firms since early 2009. The Chinese demand surge came at the right time for firms in these countries as the market nose dived in October 2008 (Fig. 3). Aside from China, India will add 4 MMtpy of ethylene capacity by 2015. The key projects in the near term are: 54

I MAY 2010 HYDROCARBON PROCESSING

5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0

Japan Thailand Taiwan S. Korea

2008

Japan

East Asian ethylene plant utilizations rates—2008 to 2009.

China

Aromatics production capacity, million tpy

FIG. 3

Q4 2008

Japan

Ethylene plants utilization rate, %

PETROCHEMICAL DEVELOPMENTS

FIG. 5

Singapore Indonesia India China

1H 2H 2010 2011 2012 2013 2014 2015 2009 2009

Asia-Pacific aromatics production capacity additions—2009 to 2015 by nations.

• Haldia Petrochemicals Ltd. (HPL) has expanded its ethylene production capacity from 523 Mtpy to 670 Mtpy at its plant in West Bengal in January 2010. “Project Supermax,” as the expansion project has been dubbed, increased ethylene production capacity by about 30%. • Reliance Industries Ltd. (RIL) will complete the debottlenecking of its ethylene cracker at its Hazira plant from 840 Mtpy to 1 MMtpy in Q2 2010. This project started in 2006 and is being executed in stages. • Indian Oil Corporation Ltd. (IOCL) will commission its naphtha cracker unit at its refinery in Panipat, Haryana. This will produce 857 Mtpy of ethylene and is expected to be commissioned by Q3 2010. Longer-term key projects include: • RIL has plans to integrate its new 580,000 bpd (580 Mbpd) refinery with a petrochemical complex. The proposed ethylene production capacity is 1.4 MMtpy. The cracker is expected to come onstream by 2014; the petrochemical plant will not run on naphtha but will use refinery offgases and liquefied petroleum gas (LPG). • ONGC PetroAddition Ltd. (OPAL), a joint venture of India’s state-owned upstream major ONGC (26%); GSPC (5%); and a few financial institutions is setting up a petrochemical complex at Dahej in Gujarat State. This will consist of a cracker unit with an ethylene production capacity of 1.1 MMtpy that will run on dual feed. The complex should be completed by Q3 2013 but with significant cost overruns. India is not boosting its ethylene capacity as fast as China, and the government expects a shortfall of 5 MMtpy in ethylene by 2012. Will Asian petrochemical players continue to do well? We believe that the near-term significant capacity addi-

tions in the Middle East and China will definitely impact the global market. By September 2010, ethylene capacity in China and the Middle East will increase by 5.1 MMtpy and 6.5 Mtpy, respectively (Tables 2 and 3). We maintain a positive outlook in the long term for the East Asian petrochemical players. This will, however, depend entirely on the pace at which economies grow and especially on the robustness of the Chinese demand. Trends in the Asian aromatics industry. The Asian

aromatics—benzene, toluene and xylene (BTX)—production

PETROCHEMICAL DEVELOPMENTS capacity is growing slower than its ethylene counterpart. We expect the Asian aromatics production capacity to increase by about 26% by 2016 with China alone accounting for 59% of those additions. Two large Chinese aromatics plants came online this year: • Locally owned Fujia Dahua Petrochemicals started commercial production from its 1.1 MMtpy aromatics plant (300 Mtpy benzene and 800 Mtpy xylene) • Along with its 240,000 bpd (240 Mbpd) Huizhou refinery, CNOOC started its 1.56 MMtpy aromatics plant—360 Mtpy benzene, 200 Mtpy toluene and 1 MMtpy paraxylene (PX). More aromatics plants are expected to come online in China in the next few years. With the Jurong Aromatics Corp. and the ExxonMobil expansions, Singapore will nearly double its aromatics capacity. In South Korea, the Hyundai/Cepsa and S-Oil developments will add to the country’s aromatics capacity. KuoKuang Petrochemical Technology Co (KPTC), Taiwan plans to add a 1.45 MMtpy aromatics plant to the planned refinery to create a refinery and petrochemical complex. This greenfield project is expected to be completed by 2017. These projects will target growing markets such as China. Japan has added 580 Mtpy of aromatics capacity (410 Mtpy PX and 170 Mtpy benzene production capacity) through the Kashima condensate splitter-based project. Japan also started trial operation of the 34 Mbpd Mizushima condensate splitter in August 2009. Projects in Japan, unlike some other countries in the Asia Pacific, are targeted specifically toward integration with refineries. Japan has adopted this rationale in order to meet the challenge poised by declining fuel demand. India’s current aromatics production capacity stands a little over 3.6 MMtpy with plans to add another 2.6 MMtpy of capacity by 2015. The government is aware that healthy growth in the population combined with rising robust demand for textiles, plastics, vehicles and other consumer goods will help drive growth in India. Therefore, its petrochemical policies are focused on supporting demand and capacity growth. The government has allowed 100% FDI in petrochemical projects and has established a number of petroleum, chemicals and petrochemical investment regions (PCPIRs) and special eco-

Feedstock ﬂexibility of ethylene plants in Asia by country, %

100 90 80 70

nomic zones (SEZs) to promote investments and make India a petrochemical hub. Naphtha demand in Asia. In Asia, most of the ethylene

production is naphtha based (Figs. 6 and 7); thus, changes in the petrochemical sector will impact naphtha demand. Most of the new Chinese ethylene plants will be naphtha based. We expect naphtha’s share as an ethylene feedstock to increase from 61% to 71%. This takes into account China’s intention to maximize the usage of chemical feeds from existing refineries rather than from naphtha imports, thus allowing other heavier oil products to be used as petrochemical feedstock. In the next TABLE 2. Chinese additional ethylene capacity 2H 2009–1H 2010 Site Fujian

Ethylene, Yr Q thousand tpy

Company

Sinopec/EOM/SA 09 04

Note

800

Commercial production started in November 2009

Liaoning Huajin (Local)

09 04

300

Trial production started in September 2009

Dushanzi PetroChina

09 04

1,000

Trial production started in September 2009

Tianjin

09 04

1,000

Trial production started in October 2009

Qinzhou PetroChina

10 01

1,000

Trial production started in February 2010

Zhenhai Sinopec

10 01

1,000

Mechanical construction completed

Sinopec/SABIC

TABLE 3. Middle East additional ethylene capacity 2H 2009–1H 2010

Location

Ethylene capacity, thousand tpy

Country

Company

Saudi Arabia

Petro Rabigh

Rabigh

1,300

Saudi Arabia

Yansab

Yanbu

1,300

Kuwait

Equate 2

Shuaiba

850

Saudi Arabia

Sharq

Al Jubail

1,300

Iran

NPC#5, Moravid

Assaluyeh

500

Qatar

Ras Laffan

1,300

60 50 Hydrocracking resid. 3% Light diesel 4%

40 30 20

Others 5%

Light hydrocarbon 21% Naphtha 67%

10 0 China

India

Japan

Korea

Others Hydrocracking resid Light diesel FIG. 6

Taiwan Singapore Thailand Naphtha Light hydrocarbon

Feedstock flexibility of ethylene plants in Asia by country.

FIG. 7

Present Asian ethylene feedstocks composition.

HYDROCARBON PROCESSING MAY 2010

I 55

PETROCHEMICAL DEVELOPMENTS 4.5

Naphtha demand in AsiaPaciﬁc, million bpd

80 70 60 50 40 30 10 0 2006

2007

Others Hydrocracking resid Light diesel

2010

2015

2020

Naphtha Light hydrocarbon

Note: 2010–2020 data are projections

FIG. 8

Major naphtha-consuming countries in Asia-Paciﬁc, thousand bpd

3.5 3.0 2.5 2.0 1.5 1.0 .50 0

2005

Outlook for the structure of ethylene feedstocks in China.

1,600 1,400 1,200 1,00 800

Taiwan Thailand Korea Japan India China

FIG. 10

Naphtha demand in Asia-Pacific.

feedstock for Asian petrochemical plants. However, with massive capacities coming onstream within the next year in China and the Middle East, we expect that the Taiwanese, South Korean and Japanese crackers will be forced to run at a lower rate in the near term. Based on these observations, we forecast little change in naphtha demand in 2010 on a y-o-y basis. However, between 2011 and 2015, we expect Asia-Pacific naphtha demand to pick up and grow at an averaged annual growth rate (AAGR) of 4.6%, with China leading the way. Country focus. In 2008, South Korea overtook Japan as the

600 400

1970 1972 1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014

200 0

FIG. 9

Major naphtha-consuming countries in Asia-Pacific.

decade, as the planned ethylene plants come online, there is no doubt that the Chinese demand will drive the Asia-Pacific naphtha demand. Between 1995 and 2008, Asian naphtha consumption exhibited remarkable growth with an increase of 112%. The dominant use of naphtha in Asia is as a petrochemical feedstock. Paraffinic naphtha is used mostly for olefins and heavy (N+A) naphtha for aromatics production. After 25 straight years of growth, Asian naphtha consumption became negative (–1.4%) in 2008. This was due to the dramatic slowdown of the petrochemical sector in Q4 2008, associated with the global financial crisis. The petrochemical sector bounced back strongly in 2009, especially in Q2. Naphtha crackers in South Korea, as well as FPCC crackers in Taiwan were running at full capacity in Q2 2009. This turnaround can be attributed to: • Ethylene capacity that came online in 1H 2009 was much lower than initially expected • Slow startup and ramp-up of the new ethylene plants in the Middle East • China’s stimulus package that lifted domestic polymer demand. Looking ahead, naphtha will continue to remain the primary 56

Other Taiwan Korea Singapore Japan India China

4.0

1970 1972 1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014

Outlook for the structure of ethylene feedstocks in China, %

100

I MAY 2010 HYDROCARBON PROCESSING

largest naphtha consumer in Asia. With the development of the petrochemical sector in South Korea, domestic naphtha consumption climbed steeply and is now leveling off. South Korea’s total naphtha demand was 844 Mbpd in 2008, and we expect it to increase to 871 Mbpd in 2009. However, we anticipate a drop in demand of around 5% to 825 Mbpd in 2010. From 2011 to 2015, we expect South Korea’s naphtha demand to grow at a 2.9% AAGR to reach 954 Mbpd in 2015. Japan is a large but declining consumer. Its naphtha demand was 779 Mbpd in 2008, down by 8.3% y-o-y. We forecast Japan’s naphtha demand to decline at 2.8% between 2008 and 2015. China will drive the naphtha demand in the Asia-Pacific region. In 2008, its naphtha demand was 605 Mbpd. It was a net exporter at 17 Mbpd. In 2009, we estimate China’s naphtha demand to increase by 10% to 665 Mbpd, and the country will switch from a net exporter to a net importer. Between January– September 2009, China’s net naphtha imports totaled about 40 Mbpd. We anticipate China’s naphtha demand to grow at 14% AAGR from 2009–2015. China will overtake South Korea to become Asia’s largest naphtha consumer by the end of 2011. China’s net imports will rise from 18 Mbpd to 240 Mbpd by the end of 2012, rising further to 370 Mbpd by the end of 2015. Taiwan’s naphtha consumption pattern is similar to that of South Korea from 2001 but the growth rate has not been as pronounced. The Taiwanese demand is also leveling off. In 2008, Taiwanese naphtha demand was 350 Mbpd. We expect its demand will decrease by 5% in 2009 and further decline by 8% in 2010. From 2011 to 2015, naphtha demand will grow at an AAGR of 4%. India is not a big naphtha consumer (317 Mbpd in 2008) and neither does the country import huge quantities (125 Mbpd.) However, India is a key player in the region because of its exports.

PETROCHEMICAL DEVELOPMENTS India exported 188 Mbpd of naphtha in 2008. The country is also unique because naphtha is used as a swing fuel by the power and fertilizer producers to run their units at times when natural gas is not available and liquefied natural gas (LNG) is expensive. This is changing with the arrival of RIL’s KG-D6 gas, which is mainly directed to the power sector. India will thus emerge as a key naphtha exporter. We expect India’s naphtha demand to decline at 1.8% between 2008 and 2015 largely due to substitution by natural gas in the power and fertilizer sectors. During this period, India’s exports will rise 7.6% annually, thus reaching 314 Mbpd, and imports will drop to 45 Mbpd by 2015. A drop in demand coupled with rise in naphtha production due to increasing refining capacity, drives this trend. Overall, naphtha imports into the Asia-Pacific region are expected to increase from 995 Mbpd in 2008 to around 1.05 MMbpd in 2012 and 1.3 MMbpd in 2015. China will be the front-runner. China, Japan, South Korea and Taiwan, due to their huge dependency on naphtha, will remain exposed to the volatilities associated with this product. To protect themselves from high naphtha prices, Japan, South Korea and Taiwan have tried to revamp their naphtha crackers so that they have flexibility to use more LPG as feedstock. There is little doubt that the petrochemical sector is undergoing profound change led by massive growth in Chinese and Middle East capacity and the prospect of intense competition for Asian markets from the Middle East producers. The growth in Asian capacity could give support to naphtha pricing, while

competition from the Middle East will place margins and naphtha prices under pressure. It is possible that low-cost exports from the Middle East may force some ethylene plants in Asia to close (especially those in Japan). However, consumer countries may retaliate by imposing tariffs and dumping regulations to protect their own industries. The petrochemical sector will definitely be an interesting and dynamic space to watch in the next few years.

Dr. Praveen Kumar is the senior consultant and head of the South Asia Oil and Gas Team for FACTS Global Energy (FGE). Dr. Kumar completed his PhD and MSc from Queen Mary University of London in 2007. He also holds a BS degree in chemical engineering from the Institute of Chemical Technology, Mumbai (formerly known as UDCT). Prior to joining FGE, Dr. Kumar worked briefly as a consultant engineer specializing in modeling packages. He is a member of the Society of Chemical Industry (SOCI) and the Institute of Materials, Minerals and Mining (IOM3). At FGE, Dr. Kumar has participated in projects dealing with refinery investment, LNG sourcing, strategic planning, market feasibility studies, storage and product quality issues. His research focuses mainly on the downstream oil and gas industry pertaining to the Indian subcontinent that includes demand forecasting and pricing projections as well as in-depth refinery analysis. His articles have been cited in popular publications such as Oil and Gas Journal, Petroleum Intelligence Weekly and World Gas Intelligence, and he is often quoted by Reuters, Argus, Platts and Dow Jones.

Liutong Zhang is a senior analyst, East Asia Information and Analysis Group, for FGE. Mr. Zhang holds a bachelor’s degree in chemical engineering with First Class honors. Prior to joining FGE, he worked briefly as a market and strategy analyst with Standard Chartered. At FGE, he covers the downstream Asia-Pacific oil and gas sector, focusing on Taiwan and China. In addition, Mr. Zhang conducts in-depth research and analysis on the refining and petrochemical sectors.

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PLANT SAFETY AND ENVIRONMENT

Establishing safety representatives who are effective Follow these protocols for a safer workplace G. ALEVIZOS, Proconsul Services Ltd., United Kingdom

etting workplace safety representatives up and running in a refinery environment can be a daunting prospect for both workers and management alike. There are a number of barriers that have to be confronted and overcome to ensure that an effective system is established. This actually contributes to improved safety performance and is more than a token effort. From the workplace perspective, management is often seen as being uninterested in improving safety since there is no obvious link to the bottom line. Even if there is some interest in doing so, management usually expects that only changed workplace behaviors will improve safety and are unwilling to commit to any tangible resources to the effort. From the management perspective, the workplace is often seen as assuming that all safety issues can be solved by spending money alone and that there is no onus on the workplace to change attitudes and behaviors. The workers often think that managers aren’t interested or are too tight-fisted even if they are; managers think that workers aren’t prepared to put in any of their own effort and that they only expect money to be thrown at their problems. Building a bridge between these two opposing viewpoints is the way to establish independently functioning safety reps that do actually improve the plant’s safety performance. There are a number of barriers that must be overcome so that this bridge can be built to both groups’ satisfaction.

just doing a brief “tour of duty” in the role—getting a taste of front-line supervision by senior management before being promoted on to a more senior role. If some of them wanted to make lasting changes, they had little more than a year to influence the area—barely enough time to learn how things work, let alone make any profound improvements. In either case, don’t blame the individuals—blame the system that gave them such little chance of success. With so little time, plus maybe the promise of greater things to come, the temptation to maintain a “status quo” management philosophy would prove too much for some. Even worse, what if some were told to make impressively quick changes before their role ended, so as to leave their mark? There is little chance of building mutual respect and

trust with the workforce if you’re not going to be there for very long either way. There is no incentive for your workers to invest the time and effort (including the emotional commitment) if you’re just going to be replaced in less than a year’s time. They will bring in their own “flavor of the month” management programs that will inevitably include a different take on safety. It’s not just that the actual safety priorities may change, but the entire management attitude to safety will be different with a new person in charge—especially in the absence of proper knowledge management systems (e.g., targets, work lists, goals, strategies) that provide some degree of continuity. A common phrase used when new management is cynically welcomed by the workers is “seagull managers” (Fig. 1)—the type who

Excessive management turnover

is usually the first hurdle. People in the management role don’t stay in that role for long. The reasons may be that some struggle with little management support and failed at the role and have to go. Or perhaps some were high flyers who were

FIG. 1

“Seagull managers” won’t help your safety reps.

HYDROCARBON PROCESSING MAY 2010

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PLANT SAFETY AND ENVIRONMENT quickly fly into the workplace, leave a giant mess and then, just as quickly, fly out again, leaving everyone else to clean up. Management needs to understand that improving safety culture while maintaining a rapid-fire turnover of managers is almost impossible, especially if you have poor knowledge management systems in place. Slow down, at least once, to establish the trust and put the right systems in place that will then allow you to increase circulation again later. Don’t punish poor safety. Whether

you are in a management role or non-

FIG. 2

Don’t hide poor safety.

management role, if you’re interested in improving safety, chances are that you’re not happy with your current safety performance (measured by the number of near misses, lost-time accident frequency rate or other safety metrics). Since you already know safety needs to be improved, there’s no point promoting a culture that punishes people for poor safety results. If your Human Resources (HR) systems of incident investigation are seen as fundamentally unfair and are perceived as always out to get a scalp every time there’s an incident, then there’s little hope in improving your safety culture with or without safety reps (Fig. 2). Everything will be driven underground and plant personnel may resist: • Making basic accident reports (orderof-magnitude, higher number of near misses) • Cooperating with incident investigations • Telling the truth • Revealing physical evidence • Volunteering as safety reps. Your incident investigation systems must be driven by one factor—preventing recurrence. Management must be able to manage and to discipline individually where there

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has been real neglect, willful sabotage, laziness or deception. But more often than not, the failing is a systemic issue like insufficient training, poor work practices or poor communication, etc. It is unfair to blame the individual in these cases. As managers, you can’t shoot the messenger for bringing bad safety news to you. Bad safety news should warrant improvement opportunities—welcome it. Without it, you will drive the real safety picture underground and incidents will go unreported and will not be investigated. Safety reps will not want to be seen in roles that are perceived as management stooges sent in to do the dirty work among their peers. The reps will come up against brick walls if the fundamental culture is seen as unfair. This is a moral failing on everyone’s part—the near-miss of today that gets covered up will reappear in the future again sometime—next time as an accident that may injure someone. That injury will be on everyone’s conscious—the workers for the earlier cover-up and the management for having created the environment that encouraged it. Don’t turn a blind eye to poor safety. There is nothing more demor-

alizing for your safety reps than having a supervisor who (inadvertently or not) turns a blind eye to poor safety behaviors (Fig. 3). As a supervisor, you should be asking what happened when, after a day-shift team would not progress work it thought was unsafe without first reviewing the risk assessment or work permits, the work mysteriously and effortlessly progressed overnight on a different shift. By not questioning more rigorously what happened on night shifts, or over the weekends, a manager is potentially endorsing safety shortcuts. This severely undermines your safety reps who’ve been patiently trying to build up an improved safety culture among their peers over a long time—in one fell swoop, this could set them back by months. That’s not to say that all work done on nights and weekends is unsafe—simply asking to see the revised risk assessment or work permit would have been enough to alleviate any concern. Teach the need to prioritize. Many

excuses or reasons are given as to why little or no progress on safety issues is achieved. Excuses may range from “we couldn’t get released from shift work” to “company policy doesn’t allow us to do this.” It’s necessary to establish safety up front, as with any other business objective. However, it cannot be improved on overnight, and dis-

PLANT SAFETY AND ENVIRONMENT cipline in prioritizing the many separate items should be implemented. It’s suggested that a simple urgency/impact matrix be adopted by the reps—the kind that plots urgency along one axis, i.e., how urgently the issue needs to be resolved and potential impact such as, how many people’s safety could be jeopardized. Once the total list of current items is scattered across the new matrix, a new pattern emerges, and those that fell in the high impact/high-urgency quadrant are worked first, while those at the other end of the scale are last. The point is that safety issues are like any other business objective and they need to be prioritized. Management doesn’t have infinite resources and the workplace reps need to acknowledge this and prioritize their own issues. Teaching the reps this discipline gives them ownership of the matrix and they will defend their own work list when challenged by peers. Safety is a two-way street. Get both management and staff to accept the uncomfortable truth that improved safety requires the tangible commitment of both groups. It isn’t enough for management to simply approve spending money and it isn’t enough for the workers to continuously supply a shopping list of issues to spend it all on. Staff members have to accept their part in identifying and prioritizing safety issues and then actually doing something about them—taking short-term actions that will minimize the risk until a longterm solution is implemented. Likewise, management has to accept that a shortterm solution is not sufficient and that a long-term answer would be necessary. This requires commitment in terms of money or other resources (time, contractors, knowledge management, training, physical site improvements, etc.). The maturity required is in the ability to find the root cause, analyze each near miss and accident honestly and openly, identify the best short- and long-term responses to prevent reoccurrence. The brutal truth for staff members is that in the short-term, they will be required to change their peers’ behaviors (“can’t fix it all just by spending money”), while the corresponding stark reality for management is that sustained and improved safety requires resource allocation (“can’t get something for nothing”). The most effective collaboration is when there is agreement upfront on the generation and prioritization process so that an agreed matrix can be jointly created and tackled. Workers are best placed to

change behaviors among their peers, while management is best placed to efficiently commit the right resources. Usually, what’s required is a combination of both—workers for the short-term risk mitigation, and management for longer-term risk minimization or elimination. Mutually respect idea generation.

Both management and staff will have their own ideas of what constitutes relevant safety issues. The safety reps will usually bring to

the table a list of historically based safety issues from their peers. Management usually brings a statistical/data-based approach showing patterns of safety issues rather than specifics that may include: • The proportion of individual vs. process safety incidents (e.g. loss of containment incidents) • Actual incidents vs. near misses • Injuries sustained to various parts of the body • Industry stats from other sites, etc.

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PLANT SAFETY AND ENVIRONMENT In generating an agreed-upon list, the trick is to combine both specific items with generic trends. As an example, an employee may bring to the table that three years ago someone badly twisted his ankle while turning a valve at a specific incident. It’s concluded that some type of improvement program on correct footing and valve access is required immediately

across the entire site. Management may counter with stats showing that all valverelated incidents involve back injuries—a more prominent injury. The combined agreement now shifts to taking a broader view and tackling the root cause of why there are so many stiff valves that need manual intervention in the first place. A transient awareness program may only

identify the correct stance one should take when turning a valve or littering the site with improved footing structures that are never used. A brainstorming session may bring up different and more effective solutions. Short-term solutions may range from increased valve basic-care routines, while long-term solutions may involve replacements, upgrades or automation. The point is that, with collaboration, a better definition of the problem will be attained and, with it, a better range of solutions will emerge. Workers know what has happened onsite through their peer networks. Management knows what could happen onsite through their industry networks. Mutually respect the fact that neither management nor staff has a monopoly on good safety ideas. Review historical safety performance for ideas. Ground your idea

FIG. 3

Typical safety meeting without a priority setting.

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generation in reality rather than fiction. Create matrix items based on actual historical incidents instead of personal favorites or “what-if ” scenarios. There is a tendency to generate work-list items based on a myriad of personal preferences and perceptions of hazards and risks. People love to unleash their fantasies and propose incredibly complex doomsday scenarios that all of a sudden are the highest priority risk onsite. The trouble is that one person’s risk may often be another person’s opportunity. Instead, a review of the plant’s historical safety performance and a look at trends that this identifies will help establish key vulnerabilities. Think of process as well as personal safety items that may include: • Temperatures and pressures that routinely exceed alarm limits • Incidents of liquid levels either going over the top or dropping below zero • Recycle rates below minimum levels • Actual cases of containment loss • Lifting of pressure safety valves (PSVs) • Excessive flaring incidents • Loss of key instrumentation • Alarm flooding, in general. Think of near misses as well as actual incidents. Think of the safety triangle and look as far down the base as you can historically. If you don’t collect enough history, then make your first item setting up a system that does. Safety reps are often keen to get started on solving issues right away, but half the battle is deciding what issues should be solved in the first place. Some of that natural enthusiasm needs to be reined in or at least redirected to some

research effort up-front before letting the reps loose on problem solving. Basing your work list on historical issues is a natural defense against the many challenges that may be thrown at your safety reps from both management and peers alike. Management will question the validity of the reps activities and peers will question their motives—so solving those issues that have continually surfaced in the past is the best defense against both groups. Create a Website and advertise.

Once there is an agreed-upon priority matrix and a resultant work list is established, it’s time to hit the streets with the safety message. The best way is to allow the safety reps to set up their own Website on your company Website so that other people onsite know who they are and what they are working on. It also provides a forum to advertise upcoming safety meetings/events/ awareness campaigns, etc., that the reps are organizing. Most importantly, it helps to give the reps a sense of identity and accomplishment, especially if the Website is also used to keep track of successful results. Your safety reps will need to establish their credibility among their own peers. They will be subjected to all sorts of accusations from cynical peers as to why they are volunteering to be safety reps. Examples have included: • Wanting to get a promotion • Taking advantage of free business trips • Getting out of normal work • Getting extra overtime • Getting off shift work and onto days. For management, it’s important to influence safety-rep volunteers who have a real passion for safety and who can influence their own peers. For workers, it’s important that you don’t use the safety rep role as a means to a more comfortable or profitable career. Tracking activity and tangible results is the best way to counter all of these arguments, and an onsite Web presence is a great way of doing so.

• Defraying the costs of arranging offsite meetings • Visiting other worksites or industry conferences • Paying overtime to get people to participate in safety meetings • Publishing literature • Getting small projects started, etc. With time and confidence, the budget size can be increased as long as there is accountability and a recognized return on investment. It is incredibly empowering to be able to provide some degree of financial independence and decision making to your reps. This is also a good way to teach reps that any resource, especially money, is limited and that prioritization is the only way to deal with never-ending demands. Encourage networking across t h e s i t e / c o m p a n y / i n d u s t r y.

Network activities encompass everything from sending an e-mail to visiting another site and conducting peer-assisted activities. The safety matrix work-list items will warrant legitimate network activities and this will allow the safety reps to cast their net far and wide (Fig. 5). Comparing how similar problems have been solved by other departments on the same site—other sites in the same company or by other companies in the same industry—is a great way to allow quicker implementation for the correct long-term solution. Including safety reps

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FIG. 4

Give safety reps a budget—but set sensible limits!

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Establish financial independence—give reps a budget. The

ultimate management vote of confidence is giving the safety reps a budget and making them accountable is a great way to show your own trust as a manager (Fig. 4). It also gives them enough financial freedom so they operate without the need to come back to you each time there is a minor expense that needs justification. Several thousand dollars can help with many items, including:

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PLANT SAFETY AND ENVIRONMENT

Service

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FIG. 5

Networking with other sites yields benefits.

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PLANT SAFETY AND ENVIRONMENT from other associated departments onsite (i.e., maintenance and engineering) who are on the team or at least cooperating on solving work-list items together, is another example of networking across the site to get to a better answer faster. Process vs. personal safety risks.

It should not be surprising that, to begin with, most of the issues identified and plotted on the safety matrix are those concerned with personal safety onsite. These are the most easily recalled by the workforce—slips, trips and falls, dust-ineye injuries and working at height and in confined spaces. These risks only affect one or two individuals or, at worst, the immediate work group carrying out the task onsite. Process safety risks are much greater on a refinery site—they can hurt people across the whole site and indeed spread to outside the site and into the local community. Hydrocarbon gas releases and liquid spills bring fire, explosion and toxic risks to a greater number of people. Exposures to asbestos, catalyst dust, smoke particulates and residual toxic chemicals are other process examples that can still spread beyond the immediate work group. Basically, any uncontrolled loss of containment is a process safety risk, not to mention the added bonus of a significant environmental impact. The real challenge with safety reps is to strike that right balance between recognition of these process risks without causing undue alarm or over-reaction. With time, the reps and then their peers should start to identify and solve process safety issues where they can. Examples might be to review the site’s control of work processes, especially those areas where production personnel has to de-inventory, isolate, depressure and hand over equipment to maintenance. Control of work covers the whole gamut of risk assessments, work permits, field audits, near miss/incident reports, lessons-learned communications, etc. Another overlooked area is risk assessing the plant’s startup, shutdown and isolation procedures—usually assumed to be bulletproof from a safety perspective simply because “nothing’s ever happened over the last 30 years.” It just takes one serious near miss or worse still an actual process safety incident before all involved realize how ridiculously thin that excuse is. One of the greatest challenges for safety reps is to move from the readily apparent personal safety risks to the more obscure process safety risks and to add true value in helping reduce these. 64

I MAY 2010 HYDROCARBON PROCESSING

Recognize behavioral solutions.

Another challenge for safety reps is to move away from the often-held mindset that money solves all safety problems and realize that changing behaviors of their peers is a necessary component of any solution. Safety reps often see themselves as champions of the workers, there to keep management honest and ensure that the resources required to solve safety issues are forthcoming. Although there is an element of truth to this, it is not their only role. A tougher part of their role is to ask their peers what behavior should be changed to solve a safety issue. Behavioral change requires resources, too—communication, training, knowledge management processes, etc., but, ultimately it requires recognition by the workforce to learn, adapt and improve. If someone twisted his ankle by taking a shortcut over uneven ground, deliberately bypassing the paved pathway that’s provided just to shave a few seconds off his rounds—what makes more sense to solve this safety issue? Laying paving over the uneven patch or reinforcing the need to use existing pathways? Because we live in a world of limited resources, squandering resources on one safety issue means there will be less available for other safety issues on the list. The net effect is that less safety issues get resolved. Safety reps need to recognize that sometimes they will have to help management with some uncomfortable discussions with their peers and not use the “throw money at the problem” option. By husbanding their limited resources, and having those difficult conversations to change behaviors, they are providing a better service to their peers by tackling and nailing down more safety issues in the long run. Invest in your safety reps. Give safety reps the resources and specialized training required to help them do a better job. They will need help with the following: • Improving their influencing skills • Holding difficult conversations • Presentation skills • Incident investigation techniques • Understanding process safety risks • Risk assessment and analysis • Formal and informal audit techniques • Health safety and environmental (HSE) legislation • HSE training. Building reps’ skills not only improves their effectiveness but it also is a tangible

reward for their efforts and it serves to define a site role model for new, up-andcoming volunteers. Encourage a culture of continuous improvement. Ask the reps to

regularly review their progress and to differentiate between activity and results. Did a concerted awareness campaign during a turnaround actually result in a lower recordable injury frequency rate for the event? Ask them to confront the harsh realities and return to the reason for their formation. Has safety measurably improved? If it hasn’t, then urge a review and reconciliation. What needs to change to get closer to the bull’s eye next time? Celebrate their success. Reward and recognize success using safety prizes, team dinners, team events or vouchers—by publishing their success stories across the site, company and even the industry. Get them to visit other departments and share their stories. What worked well, what didn’t and what was the measureable impact on safety performance? Promote and build their profile across the site. Offer to train workers and managers on how to set up and run an effective safety rep team. What can safety reps actually do?

Here’s a list of items that safety reps can be involved with: Audits and coaching—Formal and informal. Safety reps are best placed to design and implement audits along with members from other departments (engineering, HSE, maintenance) and then to get out into the field and conduct them. Focus on quality of audits rather than on quantity. There’s no more powerful safety statement than seeing a manager and safety rep out and about conducting a safety audit together. Peer assists with other sites—Given specific issues (i.e., preparing a safety plan for a turnaround), it’s best to include safety reps that are onboard with peer-assisted teams. They have a knack of asking those awkward “under the cover” questions that often get missed by managers and HSE experts. They can often see past any spin on safety performance that another site might be using to present itself in the best possible light. They can learn from both the good and the bad experiences of another site. Incident/near-miss investigation teams—Safety reps are usually closer to the real world on shift work and know

PLANT SAFETY AND ENVIRONMENT what really does pass for good and bad practices. They can help encourage the truth to come out more readily with any investigation while at the same time ensuring that innocent victims don’t end up as disciplinary statistics for a vindictive management. New safety equipment—Safety reps are incredibly resourceful and are perfectly placed to help design and try new safety equipment onsite. An example was designing a pneumatic valve “shifter” with torque control to open and close big, stuck manual valves—a shifter that eliminated the need for brute force and would not cause back pain. It was run on compressed air, and small and light enough to be carried by one person. A small team collaborated to design, build and field test a proto type with the intent to purchase these tools for key plant areas. They were tested during turnarounds and it was reported to save many hours. More importantly, no one injured their back operating the large valves. Turnaround safety preparedness reviews—It’s easy to write up a safety plan for a turnaround, especially if you’re just copying the one from the last turn-

around. It’s a different matter when it comes to checking that the plant is ready for that turnaround from a safety perspective. Safety reps are very good at taking the plan’s requirements and checking that the real world reflects what’s been written. They will highlight the gaps and will recommend the best ways to address them. Home safety—Getting others to care about safety outside the workplace. Safety reps are great at expanding the safety message to beyond the site’s boundaries and getting their peers to reflect on safety at home or when on vacation. Small souvenir information packs, mail outs, awareness campaigns, safety draws with prizes are all ways in which your reps can get their peers to think about the safety message with their family and friends. Once you get to the point where people are holding risk assessments in their kitchen for preparing their evening meals, as one of my colleagues once said to me, then that’s probably far enough. Minor plant projects—These can help identify and design the installation of a closed loop sample system; reduce excess scaffolding onsite using alternative access methods; surveys of poor lighting

areas and their upgrades; or design emergency response procedures. Safety reps can marshal resources on shift and focus on those items that require field knowledge and experience. Run their own meetings and manage their allocated budget—Communicate these results to the wider workforce. Build and improve their profiles across the site. The individuals who are usually passionate about safety are also most likely to be very vocal about their activities and successes. HP

George Alevizos is a chemical engineer with 20 years refining experience, having worked for Shell and Mobil in Australia and Mobil, BP and Petroplus in the UK. He has also worked at refinery sites in France, Germany, Spain and the US where he assisted with unit performance test runs and other optimization and expansion projects. Mr. Alevizos has held a number of technical and operational roles, including as a lube oil process engineer, refinery linear programmer analyst, business strategy analyst, process engineering supervisor, shift manager, fuels area asset leader, site production manager and permanent site HSE manager. He founded Proconsul Services Ltd., which provides technical and organizational consulting to the refining industry worldwide.

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PROCESS DEVELOPMENTS

Consider CFD analysis to support critical separation operations This modeling method can help eliminate chronic problems caused by feed mal-distribution and poorly designed feed devices D. REMESAT, Koch-Glitsch Canada LP, Canada, Z. RIHA, Institute of Geonics AS, Czech Republic, and KOCH-GLITSCH GLOBAL REFINING APPLICATION TEAM

omputational fluid dynamics (CFD) analysis has become an integral part of providing optimal designs for inlet feed devices and surrounding separation internals. The following discussion and case studies show how the use of CFD analysis guidelines can be applied to optimize the design and performance of crucial refinery columns. Background. Critical refinery distil-

lation columns, such as crude vacuum towers, atmospheric coker fractionators and fluid catalytic cracking (FCC) main fractionators, use two-phase feed mixtures that are introduced to the tower at very high velocity. To allow for the necessary heat and mass transfer requirements, the inlet must be designed to 1) perform initial separation of the vapor and liquid, and 2) to distribute the vapor uniformly within the separation internals above the feed inlet, such as in a vacuum tower wash bed. Numerous devices have been used for this purpose. And many of these devices—in particular for refining vacuum towers—were developed through trial and error. This approach is costly and time consuming. In searching for better inlet designs, extensive testing of vapor horns was conducted on an 8ft- I.D. air/water simulator column. The cold flow testing was combined with the results of early commercial applications to develop vapor horn configuration. While simulator testing was indispensable, it cannot easily show the interaction of the inlet feed device with the other column internals. CFD models can provide a more complete picture of the inlet feed device (vapor horn and vane style) performance

by using the actual tower configuration and process conditions in the analysis. With varying crude feeds and inlet piping (e.g., transfer line) geometries impacting inlet feed device performance, potential design improvements can be evaluated quickly using this approach. Using an integrated approach over many years, the benefits of modeling and designing inlet feed devices and internals as a single entity can be realized with several application types: • Inlet feed device and wash zone internals in vacuum and atmospheric columns and coker fractionators • Inlet feed device and internals for the FCC main fractionator slurry pumparound zone.

FIG. 1

Incorporating the internals design above the feed inlet device provides increased confidence in the column performance. In certain cases, a performance guarantee for the product quality at the first product draw above the feed location (e.g., heavy vacuum gasoil for the vacuum column) can be provided. Developing CFD evaluations.

CFD analysis is essential to optimal design. Fig. 1 shows the typical planes (elevations) evaluated in the CFD analysis of a vacuum column. Velocity profiles are extensively compared throughout the entire three-dimensional (3D) space from the bottom of the vacuum tower to the bottom of the first separation internal

Typical elevations evaluated during CFD analysis (Z values represent the relative elevations). HYDROCARBON PROCESSING MAY 2010

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PROCESS DEVELOPMENTS

FIG. 2

Velocity vector profiles at the nozzle centerline elevation—iteration of CFD analysis of inlet feed device.

FIG. 3

Velocity vector profiles at the nozzle centerline elevation—later iteration.

(e.g., vacuum column packed wash bed). For this discussion, several key horizontal planes are illustrated. These planes are located above the collector just below the wash bed, between the collector and the vapor horn, through the centerline of the feed nozzle, below the vapor horn in the lower conical transition, and in the stripping section. For the results of the CFD analysis to be beneficial, an accurate representation of the feed properties to the CFD is required. A representative feed profile is created for the CFD analysis using a 3D mixture turbulent compressible vapor flow with liquid droplets moving in the solved geometry to simulate entrained liquid in the feed. Within the column, the CFD model is set up to include specific internals, wall effects and normal gravity effects. Once satisfied with the design based on the vapor phase, the impact of entrained liquid droplets is added into the iterative process to complete the design. A special function using 68

I MAY 2010 HYDROCARBON PROCESSING

FIG. 4

Velocity magnitude contours at the nozzle centerline elevation.

FIG. 5

Velocity path lines through the column at the nozzle centerline elevation.

measured data at operating facilities provides a simplified calculation of liquid droplets entrainment. Evaluation guidelines for feed devices. To create an optimum design

and meet the design guidelines, these variables are evaluated and modified on a case by case basis: 1. Number of inlet nozzles (if not fully specified by client), including reduction of flash zone/vessel height when using 2 nozzles vs. 1 2. Size of inlet nozzle(s) 3. Type of feed inlet device 4. Cross-sectional coverage of inlet feed device, including degree of tapering of device 5. Number and placement of vanes within the inlet feed device 6. Number and placement of anti-swirl vanes (enhanced vapor horn option) 7. Transfer line/nozzle/inlet feed device transition

8. Disengagement space above and below inlet feed device. For point 8, a minimum “open” space above and below the inlet feed device is strongly suggested since this “open” space greatly impacts the distribution/entrainment capabilities of the inlet feed device. Original designs or revamps with inadequate disengagement zones limit the feed distribution and cause higher entrainment than expected even after optimization of the inlet feed device using CFD analysis. The importance of the disengagement zone should not be marginalized during the project evaluation and execution phase. During the design of an inlet feed device, numerous iterations between design and CFD work are done to obtain an optimal solution. The outputs shared with the client are typically qualitative representations (illustrations and video) of the detailed numerical analysis. Figs. 2–5 show examples of an iterative analysis of a tangential nozzle enhanced

PROCESS DEVELOPMENTS (average) c-factor, defined as Eq. 1, of 0.35 ft/s (0.11 m/s). v l v

C f = vs

(1)

where v s is the superficial velocity v is the vapor density l is the liquid density.

Even with a relatively conservative column design of 0.35 ft/s and a rudi-

mentary inlet feed device, peak velocities above a c-factor of 0.6 ft/s have been observed via CFD and corroborated with poor performance in the column (e.g., dry spots in a packed bed leading to coking and further mal-distribution impacting product specifications). However, with the benefit of CFD analysis, it is possible to design the inlet feed device to ensure the peak c-factor is below 1.0 ft/s (0.31 m/s). The peak c-factor is measured at any one point in

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vapor horn for a vacuum column. The velocity profile vectors provide an indication of how the vapor traveled within the inlet feed device and as it approached the internals above and below the device. Fig. 2 shows an early iteration of the vapor horn design with some â&#x20AC;&#x153;backmixingâ&#x20AC;? in the horn. In this iteration, the cross-sectional area in the distributor is larger than necessary, resulting in low velocities at the inner distributor wall. The designers evaluated the CFD results, suggested modifications to the design as noted in points 1â&#x20AC;&#x201C;8, and performed the CFD analysis again. In revamp scenarios (and in some grassroots projects where the transfer-line design is set), special baffles/plates are considered in the transition between the transfer line, feed nozzle and feed device to optimize the flow into the feed inlet device. If the feed isnâ&#x20AC;&#x2122;t fully directed into the inlet feed device, the benefits of the device wonâ&#x20AC;&#x2122;t be realized, and the project goals will be missed. Fig. 3 shows a later iteration of the design (an improvement to Fig. 2) but not the final design. The color-coded vertical axis is the velocity calculated in the CFD analysis. The intent is to reduce the velocity to as low as possible (or to as dark blue as possible). The velocity vector profile shows a reduction of the backmixing in the vapor horn and fewer vortexes within the annulus of the horn. In other words, the distributor design is moving towards providing the necessary crosssectional area that will provide optimal vapor distribution but not increase tower vapor velocity. Together with the velocity vector profiles, the magnitude of the velocity and the impact of the design in the 3D plan are considered during each iteration. Fig. 4 shows a typical velocity profile. Fig. 5 shows a vapor path line. Vapor path lines provide a representative illustration of the input stream flows in the solved vessel and internals geometry. Basically, the CFD analysis evaluates which sections of the given space are intensively used by the flowing fluids and identifies dead space. Table 1 shares some of the critical guidelines that are used in design development. Because the velocity profile evaluation can be translated to the tower c-factor, it is of primary importance to measure the velocities exiting the inlet feed device and just prior to their entering the first packed bed above the inlet feed device. For a vacuum column, a typical rule of thumb is to size the column for a bulk

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PROCESS DEVELOPMENTS the cross-section of the vessel, just below the first packed bed above the feed inlet device. The optimal c-factor is calculated with Eq. 1 and takes the velocities calculated in the CFD analysis at the desired locations (i.e., below the packed bed). The intent is to provide a design that has peak c-factors below 1 ft/s. With the added criterion of keeping the peak velocity (and c-factor) below a certain value, the resultant improved vapor distribution can translate to:

• Project cost savings by allowing a smaller diameter • An overall increased capacity because more flow can be handled effectively while still meeting product specifications. The standard deviation of the velocity profiles is calculated and an acceptable maximum value is required to ensure the design goals from the client are met. Depending on the client specifications for product quality, entrainment and reliability, the standard deviation criteria are

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adjusted accordingly. From past experience, the standard deviation for the optimized design will be below the reference values in Table 1. In addition, the CFD calculation attempts to have the maximum amount of liquid entrainment at less than 10% of the feed mass flowrate. It should be noted that the entrainment value from the CFD analysis is theoretically based and provides the designer knowledge of areas for improvement of the inlet feed device (e.g., choice of device, use of vanes and number of vanes). A database is being created that compares the CFD entrainment values to actual operating entrainment values. Confidence in translating the CFD entrainment values to actual operational entrainment is increasing. In summary, the design goal is finding an inlet feed device layout that creates uniform velocity profiles at the evaluated cross-sectional areas (minimizing maximum peak and standard deviation of velocity values) and reduces entrainment below a specified value and doesn’t create conditions for re-entrainment (collisions of streams and backmixing of vapor stream). Overall, the standard deviation for each variable is minimized. The guidelines are explicitly applied to all critical elevations within the column. Case study 1. This project focuses on comparing different styles of inlet feed devices for a single-feed nozzle. A CFD comparison was done on three inlet feed devices: simple vapor horn, vane-style device and enhanced vapor horn. Figs. 6 and 7 show two of the devices studied— the enhanced vapor horn and the vane-style device. The simple vapor horn does not have any internal vanes or any anti-swirl baffles. The patented enhanced vapor horn (Fig. 6) uses a series of internal baffles

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FIG. 6

Enhanced vapor horn.

PROCESS DEVELOPMENTS Table 1. CFD evaluation criteria for inlet feed device design

HAVER & BOECKER

Criteria

Absolute

Relative

Velocity (peak) distributor

< 475 ft/s (145 m/s)

< Critical velocity due to liquid droplet atomization and possible entrainment

Velocity (peak) packed bed above feed

< 65 ft/s (20 m/s)

s < 20 ft/s (6.1 m/s) for point velocities across cross-sectional area; to optimize uniform vapor distribution and entrainment (s represents standard deviation)

Nozzle liquid entrainment

< 10% of feed mass flowrate*

The Solution Provider

–

Stream collision

–

Minimize interaction between feed vapor if there are multiple nozzles and vapor from below feed

Material back mixing

–

Evaluate velocity vectors to minimize back-mixing (eddy flow)

*Adjusted for flash zone design pressure

Table 2. Comparison of enhanced vapor horn designs for three different nozzle configurations Radial, slight offset

Radial, opposite

Tangential, 180° offset

12.9

8.7

7.5

Maximum velocity at the input into the distributor, m/s

127.2

143.5

92.5

Maximum velocity “vz” at the input into the packed bed, m/s

18.12

19.35

18.0

4.09

4.12

4.10

Entrainment,%

Standard deviation of velocity profile

designed to enhance separation of liquids from the vapor. These baffles also improve the vapor distribution by “slicing” off segments of vapor as the incoming stream travels around the horn, rather than allowing all of the vapor to reach the end. This inlet device can be designed for either radial or tangential with one or two nozzles. The horn width is tapered down from the nozzle around the circumference to match the amount of material within the horn as the feed travels through. This design also incorporates a series of antiswirl vanes that project into the annular space of the vapor horn. The vanes break the swirling motion of the vapor induced by the tangential motion in the vapor horn. The vapor exits the bottom of the vapor horn and turns up through the annulus. The downward flowing two-phase mixture benefits from gravity, which improves separation of liquid and vapor. The vapor has both vertical and radial velocity. It is crucial to break the swirling motion of the vapor before it enters the collector tray and wash zone packing above. High radial velocity at the wash bed inlet adversely affects vapor distribution to the bed, resulting in localized dry out and poor wash bed reliability.

The cost-saving packing system

HAVER ® FFS DELTA NT FIG. 7

Vane style inlet feed device.

The vane style inlet device has two tapered horizontal plates stretching across the diameter of the vessel at the top and bottom of the nozzle. Vertical vanes—typically evenly spaced—are placed on both sides of the device from the nozzle to the other side of the column as shown in Fig. 7. The two-phase mixture leaves the feed nozzle and enters the feed device. The vanes proportionally direct the vapor and liquid out of the device in a perpendicular direction in the same plane as the nozzle. The vane style inlet feed device is used for high-energy vapor inlet streams entering through a radial Select 174 at www.HydrocarbonProcessing.com/RS 䉴

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

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

HYDROCARBON PROCESSING MAY 2010

I 71

PROCESS DEVELOPMENTS inlet. Although the device has been utilized in applications with high-velocity mixed phase feeds, the performance of the device is best when limited to vapor-only feeds. Using the CFD design guidelines and data obtained from industrial sources where vane-style inlet feed devices were revamped to enhanced vapor horns, the

representative performance between the two classes of devices (enhanced vapor horn and vane style) is summarized in Fig. 8. For example, in one particular case, for a c-factor of approximately 0.38 ft/s, the vane style device measured over twice the entrainment in the field compared to the enhanced vapor horn.

Entrainment, %

Vane Enhanced VH

Twice the expected entrainment

c - factor FIG. 8

0.38 ft/s

Relative performance comparison (% entrainment) between enhanced vapor horn and vane (even flow) style/simple vapor horn inlet feed devices.

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Case study 2. This example com-

pares different feed configurations for an enhanced vapor horn in a vacuum column. The vapor horn provides design flexibility because different nozzle configurations can be considered while meeting the same performance criteria. This design flexibility allows different furnace layouts to be considered in the plant design phase and also enables revamp improvements for existing facilities to be met. Three types of twonozzle configurations for large-diameter vacuum columns are reviewed: • Two radial nozzles slightly offset • Two radial nozzles, opposite (180°) • Two tangential nozzles, opposite (180°). A single radial design is not shown. For this study, a criterion for the entire vacuum column design was to minimize overall vessel height. The two-nozzle approach vs. a single nozzle reduces the vessel height by reducing the flash zone height. However, a minimum spacing guideline above and below the inlet feed device was required to improve de-entrainment performance. Figs. 9–11 show the CFD arrangement for the three evaluations together with the vapor path lines colored by particle ID. Table 2 provides the output of the results for the Case Study 2 analysis. In all three cases, the standard deviation (approximately 4) of the velocity profiles was developed to be well below the guidelines in Table 1. There was high confidence that all three designs would generate a very uniform upper vapor velocity distribution. Yet, each design reached a different evaluation limit, and each is still considered a desirable design. Depending on the governing criterion (or criteria) set out by the client (e.g., minimum entrainment vs. minimum vapor maldistribution), a design can be developed to meet specific performance targets. For the radial case with slightly offset nozzles, the entrainment limit was reached first during the optimization exercise (at 12.9%). The calculated value of the entrainment is part of the total liquid mass flowrate, which comes into the column through input nozzles and goes out of the geometry through the outlet (the bottom of the packed bed). In other words, it is liquid that, isn’t separated from nozzle mixture stream on the given column walls. Total liquid mass flowrate comes into the column through distributor nozzles. The radial opposite case reached a maximum peak velocity of 143.5 m/s at the input to the distributor and a peak veloc-

PROCESS DEVELOPMENTS

FIG. 9

CFD analysis for dual entry nozzles illustrating vapor path lines (vapor flowing in solved CFD geometry)—offset radial.

ity of 19.35 m/s at the bottom of the wash bed. Comparing the three cases, it appears that the 180° offset cases can be designed to minimize theoretical entrainment. For the minimum velocity to the packed bed, the dual tangential nozzle design also provided the best result. The client’s choice will dictate how the final optimization steps proceed. For a client who requires minimum entrainment within the optimized vapor distribution criteria and has the plot space to have furnaces located on either side of the vacuum column (or is satisfied with asymmetrical transfer line piping), the 180° dual tangential design is the best choice. Observations. CFD analysis has become an important tool to improve the design of inlet feed devices in refining applications and thus improve operational profitability. CFD has uncovered the importance in establishing uniform flow to the wash bed through the design of the inlet feed device. Despite the presence of a collector tray that has a pressure drop typical of vacuum tower installations, flow irregularities persist at the entrance to the wash bed. This nonuniform flow can translate to premature flooding, poor wash zone performance and poor wash bed reliability. Large variations in vapor velocity entering the wash bed will almost certainly result in bed coking because sections with high vapor velocity (and, therefore, high vapor mass flux) will have a greater tendency to dry out. Shortened run lengths and expensive bed replacements will be the result. This work also illustrates the benefits of CFD for designing critical tower inlet devices. Because each tower is different, the interaction between the feed device, transfer line, vessel shell and other internals will vary. CFD offers a way to ana-

FIG. 10

CFD analysis for dual entry nozzles illustrating vapor path lines (vapor flowing in solved CFD geometry)—180° offset tangential.

FIG. 11

CFD analysis for dual entry nozzles illustrating vapor path lines (vapor flowing in solved CFD geometry)—180° offset radial.

lyze these interactions and optimize feed device design for a given unit. Used in conjunction with historical operating and inspection data, CFD can help to eliminate chronic problems caused by feed mal-distribution from a poorly designed feed device. Guidelines and case studies have been shared to provide insight into the benefits of using CFD analysis for inlet feed devices at the design stage to improve success of the project. HP Darius Remesat is vice president, Koch-Glitsch Canada LP, and applications consultant.

Zdenek Riha is an expert in CFD analysis at the Institute of Geonics AS, Czech Republic.

Koch-Glitsch Global Refining Application Team comprises of a group of refining experts specializing and collaborating on refining separation opportunities that include Dennis Schmude, US; Oleg Karpilovskiy, Czech Republic; Luigi Valagussa, Italy; Roque Puig, France; Alessandro Ferrari, Italy; R. Madhavan, India; Jae-Eun Kim, South Korea; and Darius Remesat, Canada. Select 176 at www.HydrocarbonProcessing.com/RS

PLANT DESIGN AND ENGINEERING

Strategize preshutdown work to enhance productivity Adopt these principles from a refinery revamp project A. KUMAR, Indian Oil Corporation Ltd., Panipat, India

evamp project management requires special skills, a positive attitude and sound leadership to formulate a strategy and to steer the entire team. In the hot pursuit of stringent safety norms inside running hydrocarbon units, revamp modifications are not simple tasks.

The revamp project: A synopsis. Today, the importance of a revamp project in the hydrocarbon industry and particularly in an oil refinery is gaining momentum due to economics and space limitations. The revamp project for a unit in a refinery is undertaken when debottlenecking units and it aims to increase the yield pattern and the unit’s capacity. The revamp project involves the addition, modification, relocation or deletion of certain facilities or equipment and changing, replacing or modifying associated piping systems, along with electrical and instrumentation modifications. Revamp projects are different than greenfield projects in a refinery since revamps are executed within the operating unit. It consists of preshutdown construction activities being executed when the unit is running and balancing activities that are only done during unit shutdown. Thus, revamp projects include a set of construction activities to be undertaken prior to shutdown depending on the feasibility (e.g., the civil foundation of new equipment, equipment erection, piping fabrication and pipe rack erection, etc.). Revamps also include shutdown activities consisting of piping tie-ins or hookups, modification in the facility or lines that are under operation and readiness of the entire system including the electrical and instrumentation networks.

Shutdown time reduction and timely completion

Preshutdown and innovation

FIG. 1

Shutdown planning and resource management Safety and reliability

Preshutdown job execution

The revamp project triangle.

I MAY 2010 HYDROCARBON PROCESSING

Safety and quality

Preshutdown work: Thrust on timebound completion. Preshutdown execution is very critical as the construction

activities are done inside the running unit with proper coordination with the operations group and plant safety awareness of potential fire hazards with regard to hot jobs like welding. The number of engineering days in a shutdown is decided at the project’s inception stage—before detailed engineering. Be careful not to set unrealistic targets that may impede the team’s morale and increase the chance that the shutdown may be overstretched. A tough but realistic target should be set for shutdown activities for revamp projects. The shutdown period during a revamp project should be planned in close coordination with refinery operations matching the shutdown schedule with the refinery’s personnel in advance. Certain strategies should be adopted during execution to reduce the number of shutdown days and to complete the maximum construction activities in the preshutdown period to increase profitability. The reduction of just one engineering day in a shutdown can account for considerable savings. The challenge lies in shifting certain shutdown activities to preshutdown and in executing them in parallel with running the plant. This is only possible by a coherent, focused and strategic approach through a core team of project engineers, a unit operation group and a refinery process and engineering team mentored by refinery management. The salient objective to execute a revamp project resides on the safe and timely completion of all planned preshutdown jobs, including nondestructive testing activities before implementing the shutdown. Also, a successful shutdown completion entails putting the revamped unit back onstream as early as possible. The revamp project triangle is illustrated in Fig. 1. Strategies and implementation. A strategic approach is needed during the engineering, procurement, planning and execution phases to speed up the project progress and build team morale. This achieves a safe and timely completion of a revamp project. The various strategies adopted and implemented in the execution of a residue fluidized catalytic cracking unit (RFCCU) revamp project in a conventional mode at an India refinery are as follows: Focus on early completion of engineering. It is important to confirm the total number of pipe isometrics to determine the pipe welding load and then to plan the number of necessary welders, skilled persons and related resources. Similarly, engineering input required the civil foundation, structural work, electrical modification in the substation, and field and instrumentation interface to

PLANT DESIGN AND ENGINEERING

FIG. 2

Placement and insertion of equipment inside a technological structure proves challenging.

FIG. 3

Timely pipe erection and welding on a residue fluidized catalytic cracking unit revamp.

be completed on time. Since certain issues require coordination Coordination and liaison with the package vendor: Putting with the refinery operation group, it becomes important to finalize an end to surprises. It is a challenging task to coordinate with the engineering requirements early. These requirements are passed package orders (e.g., a compressor package) since the boundaries on to the project management consultant for detailed engineering with package vendors compared to the project is not well defined. and issuing relevant engineering drawings for on time execution. Many surprises can come up during facility execution, installation Quick disposal of site queries by engineering: Impetus to and commissioning when dealing with a package vendor. Focus smooth execution. Since revamp projects are executed inside the areas such as short receipt of parts, pre-fabricated piping spools operating unit, accurate engineering drawings are issued for conand timely visits of service engineers during installation and comstruction. Sometimes, as-built drawings are missioning should be tackled carefully. not updated on existing facilities in the unit, ■ Necessity is the mother of Core team for brain storming: Bringso the revamp piping isometrics and gening the project, operations, mainteinvention. A tight schedule nance and engineering teams under one eral arrangement drawings (GADs) are not accurate. Fouling may then result with the for shutdowns encourages umbrella. The task of reducing the shutexisting above-ground piping, underground down load can be accomplished by taking piping, cable trenches and super structure an “out-of-box” approach the operations group into confidence and during the course of execution leading to and the need to strategize setting a platform for discussion, coordinasite queries. Time is wasted if an engineertion and innovative thinking. A multidising response is not prompt to resolve the to reduce the shutdown ciplinary team representing persons from problem. Today, 3D modeling has become operation, maintenance and engiload in a revamp execution. project, a handy tool to avoid such problems if a neering groups is formed that the brainparent-unit piping and facility has already been modeled. The storming and explores the possibility at the site to shift the shutrevamp engineering drawings can be drawn from the model. down load to preshutdown. Various innovative ideas are discussed Meticulous planning: A key to success. Sincere efforts are and meaningful solutions emerge. The methodology adopted needed to plan the activities in both preshutdown and during and the lessons learned during the RFCCU revamp at the India shutdown. At the outset, lines that can be completed, erected refinery are summarized in Table 1. or partly completed are identified from a line list. The quantum Matching material in fabrication: Expediting the receipt of of critical attributes—including pipe welding, pipe erection, piping bulk material. Since piping and pipe fittings are ordered stress-relieving quantum and radiography load—are calculated in two or three material take-offs, it becomes a dynamic situaand firmed up. The execution philosophy is discussed and agreed tion, as piping fabrication and material receipt are concurrent. upon. The operation team is taken into consideration in finalizing Sometimes it becomes a work front problem for the execution previously discussed quantum. Any more hookups (tie-in-joints) contractor to do smooth fabrication of piping spools due to nonto be done during the revamp are firmed up. They are reviewed as availability of matching material (pipes and fittings). Normally, to whether a few hookups can be completed or partly completed in conventional greenfield projects, the work front is given to in the preshutdown. Piping loops and vessel trim loops are marked the mechanical agency when the material availability is ~40%. on piping and instrumentation diagrams along with confirmation However, the same philosophy does not hold true since the prewith operation for hydraulic testing of piping loops and systems in shutdown period is fixed and fabrication slows down. The task preshutdown, and during shutdown. All critical activities— such of completing all assigned activities before shutdown becomes as piping, equipment erection, civil foundation (work denoted even more difficult. Using piping software to calculate the work as first critical, second critical, etc.)—are identified, planned and front to optimize the piping fabrication with respect to available scheduled with software to match the shutdown schedule. Brainbulk material, isometrics drawings and material expedition from storming was done to reduce shutdown days around these critical vendors, is helpful to overcome this problem. activities. Challenge lies in placement of new equipment and pipSafety during execution: Safety by design and not by ing inside the revamp unit as illustrated in Figs. 2 and 3. chance. With a revamp project, safety is assigned first priority in HYDROCARBON PROCESSING MAY 2010

I 75

PLANT DESIGN AND ENGINEERING TABLE 1. Lessons learned during the RFCCU revamp Sl. No

Focus area

Resolution

Welding inside running unit in preshutdown

A special enclosure for welding the rack piping was designed which did not allow any weld spatter to fall down. This facilitated hot job clearance from operations during preshutdown.

Placement of piping on pipe rack in preshutdown

Lines were erected on the pipe rack inside the running unit with proper care and safety after receiving clearance from operations. Whereever running line size was required to be altered, a new line was placed on the rack adjacent to an existing line to reduce the piping erection time during shutdown. The old line was later dismantled during shutdown.

Field welding on pipe rack in preshutdown

Since it was difficult to do field welding around the running hydrocarbon unit, a location was selected by the production team that was considered safe and welding clearance was obtained. Pipes were doubled in the fabrication yard and then shifted to the site. Pipes were erected on the rack by a crane and manual lifting. Further field pipe welding was done at the selected location where weld enclosure was made. Pipes were pulled on the pipe rack after welding and positioned as per GAD. Using this method enabled most of the welding to be carried out safely during preshutdown.

Change in piping route to facilitate erection in preshutdown

Line route was changed slightly to take advantage in doing the erection and field welding of piping. LPG line routing in RFCCU was changed at the site and elevated to a different tier on the pipe rack to avoid fouling and to facilitate smooth execution. Similarly, the routing on a few lines was changed on the unit pipe rack after receiving engineering clearance.

Installation of duct and tray in preshutdown

Instrumentation duct support and installation on the pipe rack was critical and it involved welding along the entire rack. The welding was replaced by a hole drilling and bolting method (welding was later done to reinforce the same in shutdown). Duct installation was possible because of this.

RCC foundation

Civil foundations coming at first or second tier on a technological structure for exchangers and vessels were changed from RCC to structural foundations to facilitate fabrication and erection in the preshutdown period and reduced shutdown load. The dismantling of the civil RCC foundations of two exchangers planned in shutdown was avoided by modifying and reinforcing correctly with respect to design for new exchangers coming on foundation.

Use of latest tools to save time in revamp

The use of a diamond core cutter for breaking slab for the RCC – achieved fast results in executing the job in a safe environment with regard to running the plant in preshutdown and during shutdown.

FIG. 4

Project agency

3-D Modeling engineering documents for execution

Eq u ere ipm cti en on t

PMC

Executive start

./ dn il f h civ renc ing e t Pil cabl

Scoping study

A typical network of revamp project activities including preshutdown job execution.

I MAY 2010 HYDROCARBON PROCESSING

ho Pipin ok g -u ps

ng ipi l./p tion ck Str rec e ra e pip on

Detailed Detailed eng. Revamp project Process pkg. conceptualization ﬁnalization feasibility report and HAZOP

Pip str ing l. f fab ab . .

Preshutdown strategies: 1. Timely engineering inputs/resolutions of site queries 2. Meticulous planning and pre-shutdown job identiﬁcation 3. Liaison with package vendors 4. Formation of core team and brain storming 5. Expediting materials 6. Emphasis on safety and quality

Pr ec o of mm sy is ste sio m nin s g

Cable laying upto in trench/duct Piping, NDT

ation odiﬁc /DCS m l e pan h PLC HT/LTrface wit e t in

Shutdown

PLANT DESIGN AND ENGINEERING TABLE 2. Interface planning adopted Sl. No

Focus area

Resolution

Radiography

Radiography for quality assurance of pipe-welding joints was envisaged as the main area of interface since maintenance repair work included radiography that could hinder revamp work during a shutdown. A sector-wise approach inside the unit and scheduling radiography during the night with proper coordination resolved the problem.

Interface between heat exchanger cleaning work and revamp pipe welding

Separate bay of heat exchanger tube bundle cleaning by hydro-jetting was made outside the unit and tube bundles were shifted in the bay to avoid interference with revamp pipe welding.

Prior intimation of equipment going under revamp to Maintenance group

List of all stationary and rotary equipments modifications/ replacement/ deletions/re-locations to be shared with the maintenance group so it could plan the maintenance work on equipment accordingly.

Resource mobilization

They included skilled manpower necessary for revamp and maintenance jobs was finalized in advance to avoid resource crunch during shutdown.

execution. A special training program is devised for all supervisors and engineers engaged in a revamp project at the site to make them aware of the safety and fire hazards in a hydrocarbon unit. Preparing an area for a hot job, certifying pipe scaffolds as fit for use, excavation with proper slope and ensuring shift-wise permit clearances are some important tasks assigned to the safety team within the executing agency. This is apart from other construction safety measures at a revamp site, along with sensitization on safety and the security of a refinery battery area. Boost confidence and ask for more. Execution inside a running hydrocarbon unit requires sincerity and dedication from the contractor side as well as from the owner project side. Efforts should be made to build confidence with respect to area preparation and safety precautions and close coordination with the operations group. Without cooperation from the operations, group completion of preshutdown jobs within the targeted time in a running plant remains a distant dream. Interphase management: Synergy with the maintenance group. Various maintenance and inspection activities like column and vessel internal inspections, cleaning of heat exchangers, preventive maintenance of pumps, and repair work of unit piping and boilers etc.—are often planned during revamp shut down which may interfere with revamp activities if interface is not envisaged properly. A joint team of maintenance and project personnel needs to work out areas of interface prior to shutdown and devise strategies and action plan to be implemented during shut down. The interface planning adopted and lessons learned in a revamp of an RFCCU is summarized in Table 2. Conclusion. A typical network of revamp project activities is illustrated in Fig. 4. An emphasis on preshutdown strategies will help enhance the productivity and completion of all planned activities and reduce the load during unit shutdown. Further, the planning of shutdown jobs with proper resource mobilization after preshutdown is a prerequisite for a successful revamp completion. Necessity is the mother of invention. A tight schedule for shutdowns encourages an “out-of-box” approach and the need to strategize to reduce the shutdown load in a revamp execution. The aforesaid strategies adopted and lessons learned during the revamp project management in the RFCCU unit at the Panipat refinery were quite different from executing a green-field project. There was a focus on effectively utilizing preshutdown time, reducing the idle time of resources and performing planned shutdown activities during preshutdown through innovative methods. A consistent

“Kaizen” approach for continual improvement will ensure the successful completion of revamp jobs during final shutdown. The revamp activities in preshutdown are critical. HP

Arvind Kumar is a senior project manager for Indian Oil Corporation Ltd., at its Panipat Refinery. He has worked at Indian Oil Corporation Ltd. for more than 19 years in different refinery units. Mr. Kumar has performed assignments in design and engineering. He has successfully executed various greenfield and revamp project, along with commissioning. He earned a BTech degree in mechanical engineering from Kamla Nehru Institute of Technology, Sultanpur, Uttar Pradesh, India and an MBA with a specialization in operations management.

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INSTRUMENTATION/SAFETY

Implementing a suitable safety instrumented system—Part 1 The “analysis phase” is the most important step for engineering and designinga suitable system R. MODI, Saudi Basic Industries Corp., Jubail, Saudi Arabia

he safety life cycle (SLC) is comprised of analysis, realization and operation phases. To manage an SLC is an engineering process to specify, design, implement, operate, modify and maintain a safety instrumented system (SIS) for achieving overall functional safety. The analysis phase is the most important step for engineering and designing a suitable SIS for the specific process requirement. This article describes different steps of the analysis phase, i.e., risk assessment, implementing independent protection layers (IPLs), safety instrumented functions (SIFs) identification and safety integrity level (SIL) assessment by using a “risk matrix” and layers of protection analyses ( LOPA), and finally, developing the safety requirement specification (SRS). The engineering philosophy adopted by Saudi Basic Industries Corporation (SABIC) are narrated for SIL assessment and verifying safety loops with a case study of a process vessel used for hazardous chemical storage as in Appendix I. Introduction. The growing complexities of industrial processes need more intelligent safety systems to achieve the desired plant safety. Industrial accidents create consequences such as: loss of life, environmental damage, assets loss, production loss, etc., that may impact long-term business. Proper care at the initial stage (analysis phase) of the project can prevent several accidents that are likely due to safety system malfunction, misoperation, improper maintenance and modifications. However, it does not

20.6% Modiﬁcation after commissioning 14.7% Operating and maintenance

5.9% Installation and commissioning

FIG. 1

44.1% Speciﬁcation

prevent safety system dysfunction due to wrong engineering or design. The “HSE95” study for primary causes of control system failures shows “specification” contributes the major (44.1%) factor and “design and implementation” contribute (14.7%). These cover almost 60% of the total control system failure causes (Fig. 1). Hence, proper care in the analysis phase can eliminate the major SIS failure causes. To control safety system design and implementation, standards, i.e., ANSI/ISA-84.00.01, IEC 61508 and IEC 61511, etc., are available. Analysis phase. IEC 61511, Part 1, Functional Safety—Safety Instrumented Systems for the Process Industry Sector, is considered as a platform to describe phases of the SLC since it is applicable to safety system users in the process sector (Fig. 2). The SLC allows a

Risk analysis and protection layer design

2 Allocation of safety functions to protection layers

Analysis phase

Safety requirements speciﬁcation for the safety instrumented system 3 Management Safety of functional life cycle safety and structure functional and safety planning assessment

Design and engineering of safety instrumented system

Operation Design and phase development of other means of risk reduction Veriﬁcation

Installation, commissioning and validation

5 Realization phase

14.7% Design and implementing

Primary causes of control system failures.

I MAY 2010 HYDROCARBON PROCESSING

FIG. 2

Operation and maintenance

Modiﬁcation

Decommissioning

IEC 61511 Part 1, safety life cycle.

INSTRUMENTATION/SAFETY systematic approach to the functional safety problems, consisting of three vertical phases: analysis, realization and operation. The “analysis phase” determines the safety requirements, like hazards and risk analyses, SIF identification, applying non-SIS protection layers, SIL assessment, SIS requirement, and safety requirement specification (SRS) finalization. The “realization phase” involves safety system design, fabrication, installation, testing and implementation. The “operation phase” comprises safety system startup, operation, total safety validation, maintenance and decommissioning. The ultimate goal of any organization is to execute all activities as efficiently and effectively as possible to achieve and maintain the desired and derived SIL throughout the safety life cycle. The analysis phase clearly defines the project purpose with required goals and measurable outcomes without any ambiguity to avoid confusion in the later stages. It also describes process, equipment limits and areas of operation. More attentiveness and care are required in this stage since it defines rules for realization. Engineers involved in this activity should have knowledge of process, technology, international standards, safety, health and environment (SHE) regulations, equipment under control (EUC), associated hazards and risk, etc., to achieve the required safety goals for the organization.

tional laws, regulations, legislation and standards. This risk level is a “target SIL” and should be compared with the present risks in the process.

Steps to SIS design. Major process plants contain hazardous

Process hazard analyses (HAZOPs). Members of a team from operations (a group directly involved with the process),

processes and adequate steps are required for process safety. It is essential to adopt different techniques to reduce the process risk to the acceptable limit for safety, environmental and economical issues. During process selection and design, care for reducing the process risk is taken. However, it still remains as residual risk. Based on the hazard and risk assessment, identifying appropriate SIFs and SIL selection are important tasks. Tolerable risk target. At the beginning of the project, the organization sets the “tolerable risk target.” This is a risk level that is tolerable in daily operation. It is derived based on the past history of the same technology, process complexity, product toxicity, plant location, injury severity, number of people to be exposed, occurrence frequency, etc., to meet applicable national/internaIntolerable region

As low as reasonably practical (ALARP). ALARP is a

method that helps to define the acceptable risk level for a specific process (Fig. 4). It defines general risk classes as “intolerable risk, tolerable risk and negligible risk.” A high gap between intolerable risk and tolerable risk targets needs a higher degree of protection to protect the plant from any undesirable event. While implementing various techniques for risk reduction at a certain level. Further risk reduction is possible only with outweighed cost. Hence, for eliminating the remaining low risk, the safeguarding cost is unreasonably high. So, the optimum level is to be achieved that balances the cost for safeguarding and the cost of consequences. According to the Exida Philadelphia-2000 survey for process plant risk tolerance and third-party liability settlement, the “corporate tolerable risk citeria” lies in the range of 1 x 10–9 to 1 x 10–5. Normally, the adopted level of tolerable risk is 1 x 10–6 per year for SHE incidents as per risk matrix analyses. Hence, appropriate SILs are to be applied to the identified SIFs that do not meet this tolerable risk target value.

Tolerable ALARP risk target

SIL assessment

FIG. 3

HAZOP

Risk matrix

LOPA

IPL application

SRS development

Total cost = cost for safe guarding+costs of risk Optimum level (safeguard vs cost)

Tolerable only if further risk reduction is impracticable or if its cost is grossly disproportionate to the improvement gained. As the risk is reduced, the less, proportionately, it is necessary to spend to reduce it further to satisfy ALARP. The concept of diminishing proportion is shown by the triangle.

(No need for detailed working to demonstrate ALARP)

Level of safeguarding Negligible risk Tolerable risk and ALARP

FIG. 4

Costs of risk

It is necessary to maintain assurance that risk remains at this level.

Broadly accepted region

Total costs

Costs of safe-guarding

Costs

Increasing risks

(Risk is undertaken only if a beneﬁt is desired)

SIS design

A “tolerable risk target” is established at the beginning of the project.

Risk cannot be justiﬁed except in extraordinary circumstances.

The ALARP or tolerable region

SIF/PIF identiﬁcation

Low level of safeguarding increases cost of consequences

High level of safe-guarding reduces cost of consequences

Tolerable risk and ALARP.

HYDROCARBON PROCESSING MAY 2010

I 79

INSTRUMENTATION/SAFETY engineering and management conduct a process hazards analysis (PHA) study to meet the safety requirement according to the national/international regulations, laws and standards. A few methods, i.e., what-if, checklists, failure mode and effect analysis (FMEA) and a HAZOP study are used in the process automation industry to identify hazards and risks. HAZOP is a brainstorming process among expertise from different disciplines like process, operation, instrumentation, safety, mechanical, electrical, inspection, etc. They discuss hazard potential, involved risk, available measures for risk reduction, additional measures or techniques required for risk reduction, and finally identify the safety function for the specific process. The HAZOP study is the adopted method for PHA by SABIC. HAZOP studies normally follow a detailed pattern for identifying potential problems, effects of these problems and the best possible solution based on resource availability. It is a method for examining many functions that are involved with complex manufacturing systems to determine potential hazard in all process conditions, i.e., normal, startup, planned and emergency shutdown, process upsets, etc.

ment installation, equipment design, i.e., high wall thickness, etc., are considered during process design. In addition to this, identifying hazardous events that may have potential to occur during plant operation are to be considered as causes for accidents. Further, these results are evaluated by applying available safeguards (protective layers) to avoid undesirable abnormalities. Some of the safeguards such as relief valves, rupture disks, dikes, etc., are inherent parts of the plant design. These are very critical process plant equipment to mitigate abnormal situations. Further availability of SISs and operator actions during process alarms are considered as preventive measures to prevent abnormal situations. All this equipment used either for prevention or mitigation should have sufficient independence that does not create interference with each other. They are called IPLs. IPLs should have properties of specificity, independence, and dependability and auditability (Fig. 5). Each layer should be independent from other protection layers and designed solely to prevent or mitigate the consequences of a specific potential hazard. It should be trustworthy to perform the specified functions for identifying danger, and random and systematic failure modes. Their design should allow regular safety or Independent protective layers. For each process, some protective function validation, i.e., proof testing and safety system measures for risk reduction such as plant site selection, equipmaintenance, whenever required. To achieve independence among these TABLE 1. Low- and high/continuous-demand modes of operation layers, SABIC has adopted an engineering philosophy to use the DCS as a BPCS and Demand mode of operation Continuous mode of operation ESD as the SIS and a PLC for nonsafety Target frequency of functions, especially for package units. Target average dangerous failures to Safety integrity level (SIL)

probability of failure on demand

Target risk reduction

perform the safety instrumented function (per hour)

ⱖ 10–5 to ⬍ 10–4

⬎ 10,00 to ⱕ 100,000

ⱖ 10–9 to ⬍ 10–8

ⱖ 10–4 to ⬍ 10–3

⬎ 1,000 to ⱕ 10,000

ⱖ 10–8 to ⬍ 10–5

ⱖ 10–3 to ⬍ 10–2

⬎ 100 to ⱕ 1,000

ⱖ 10–7 to ⬍ 10–6

ⱖ

⬎ 10 to ⱕ 100

ⱖ 10–6 to ⬍ 10–5

10–2

to ⬍

10–1

Plant emergency response

Mitigate

Community response

Physical protection/containment

Basic controls

Passive protection layer

Dike

Active protection layer

SafetyEmergency instrumented shutdown system Prevent

SIS

needs of the instrumented functions, it is required to evaluate whether the function is a protective-instrumented function (PIF) or safety-instrumented function (SIF) (Fig.

Emergency response layer

Relief valve, rupture disk

Physical protection/ relief devices

Alarms, manual intervention

Plant and emergency responses

Identifying instrumented function: PIF or SIF. After identifying the

Safety layer Trip level alarm

Operator intervention

Process shutdown

Process control layer Process alarm

Process design

FIG. 5

Independent protective layers.

I MAY 2010 HYDROCARBON PROCESSING

Basic process control system

Process valve

Process control layer

INSTRUMENTATION/SAFETY 6). A PIF is used for equipment or process protection, e.g., auto startup of a spare pump on low discharge pressure. An SIF is used for equipment or process safety, e.g., outlet valve closing on high pressure or low level in a separator to prevent over pressurization and rupturing downstream equipment (Fig. 7). An SIF needs a specific SIL that is necessary to achieve or maintain functional safety for the identified hazardous event. Selecting suitable sensing and final elements, and identifying the appropriate functions are important tasks to achieve safety and plant protection.

Is it an instrument function?

Safety integrity level. A safety loop is the physical compo-

nents that will be used to fulfill the SIF requirements and meet the SIL requirement for that function. Safety loop subsystems are different components, i.e., the sensors, logic solvers and/or final elements used to make up the safety loop. Calculate process risk

Yes Process design changes Safetyinstrumented function?

Apply other techniques to access risk

Normally a BPCS or PLC is used for PIFs and ESDs are used for SIFs as logic solvers to implement relevant SIFs. Sometimes critical PIFs are built into ESDs since they need to be treated the same as SIFs.

Protective instrumented function?

Other risk reduction, such as alarming and exception procedures

Yes

Yes (optional)

Conduct SIL assessment and validation

Safety instrumented system Tolerable level of risk

Basic control function FIG. 6

(Deﬁned by user per application)

Is it a protective instrument function or a safetyinstrumented function?

Temperature transmitter

Solenoid

Logic solver (PLC)

Solenoid

FIG. 8

Globe valve

Safety-instrumented function.

Low-demand mode (if “test interval” falls in this region i.e. less than 1 year)

Time period

Shut-off valve

Pump

Flow transmitter FIG. 7

A higher SIL has higher associated safety integrity.

Safety-instrumented function

Temperature transmitter

Level switch

FIG. 9

High-demand mode (if “test interval” falls in this region i.e. more than 1 year)

1 year ½ of the Initial event frequency

2 years Initial event frequency

Low- and high-demand modes of operation. Select 178 at www.HydrocarbonProcessing.com/RS

INSTRUMENTATION/SAFETY

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SIF is associated with a safety instrument loop that achieves the desired safety function. SIS is used to implement one or more SIFs. It is composed of any combination of sensors and final elements to meet the SIL requirement. SIL is a discrete level (1, 2, 3 or 4) that specifies the safety integrity requirement of the SIF assigned to the SIS. To calculate the SIL for an SIF, it is necessary to consider all subsystems, i.e., the SE, LS and FE required to perform the specified safety function. Therefore, it is not sufficient to assess only one subsystem, i.e., safety loop logic solver. An SIL can be specified for two modes of operation, i.e., demand and continuous (Table 1). â&#x20AC;&#x153;Demand mode of operationâ&#x20AC;? is a low-demand mode that operates in case a demand arises due to an abnormal plant condition and has a target value in the average probability of failure on demand, PFDavg. â&#x20AC;&#x153;Continuous mode of operationâ&#x20AC;? is a high-demand mode and has a target value in the frequency of dangerous failures to perform the SIF (per hour). In low-demand mode, the SIL is a proxy for the PFD; in high-demand/continuous mode, the SIL is a proxy for the failure rate. The boundary between low- and high-demand modes is in essence set in the standards with demand rate, i.e., number of demands per year (Fig. 8). For low-demand mode, the SIF initiating event is not expected to occur at a rate of more than once per year, or the SIF test interval is less than half of the expected initiating event (IE) frequency. For high/continuous mode, the SIF initiating event is expected to occur more than once per year or the SIF test interval is greater than half of the expected IE frequency. The SIL for the low-demand mode is specified in â&#x20AC;&#x153;probability of failure on demand average,â&#x20AC;? PFDavg , and is defined as the probability of a device or system failing to respond to a demand while in service. PFDavg is a numerical value that provides the objective target for each SIL that is to be compared with possible alternatives of designs and solutions. Each SIL level has a specific range risk reduction factor, RRF. RRF and % availability can be derived from PFDavg ; risk residual factor: RRF = 1/PFDavg and % availability = 1 â&#x20AC;&#x201C; PFDavg . A higher SIL has a higher associated safety integrity, which means lower probability that a system will fail to perform the defined function. As the SIL level increases, typically the installation and maintenance costs and system complexity also increase. Normally, the process automation industries operate in low-demand mode up to SIL3. In case the SIF demands safety integrity beyond SIL3, then an attempt is made to address the process design or other noninstrumented methods to bring the SIL within SIL3 or below. HP

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Part 2 of this article will be published in our June issue.

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Select 179 at www.HydrocarbonProcessing.com/RS 82

Rajeshkumar Modi an electronics and communication engineer, built a career in instrumentation, having 25 yearsâ&#x20AC;&#x2122; experience in design, engineering, maintenance and construction of instrumentation and control systems in different chemical, petrochemical and fertilizer plants. He is a control system staff engineer in the Engineering and Project Management Department of SABIC, Saudi Arabia.

SULFUR SOLUTIONS May 2010

Supplement to:

CONTENTS Design your sulfur facility with market uncertainty in mind P. Crawford, Enersul, Calgary, Alberta

S–85

Corporate Profiles AMETEK Process Instruments Enersul ExxonMobil Research and Engineering Co.

S–89 S–91 S–93

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Visit us in Hall 1 Stand P5

SULFUR SOLUTIONS 2010

Design your sulfur facility with market uncertainty in mind These strategies can effectively deliver sulfur to the marketplace P. CRAWFORD, Enersul, Calgary, Alberta

short time period, sulfur producers have seen unprecedented demand highs to oversupply and the inability to move some forms of the product. In a 15-month period, the price for sulfur increased ten-fold to over $800 per ton in July 2008 (Fig. 1). Four months later, producers of this oil and gas byproduct were scrambling since the price plummeted. The liquid market dried up and railcars under load sat idly on rail sidings, full of hundreds of thousands of tons of liquid sulfur. The liquid sulfur slowly solidified in the railcars as the months passed. Sulfur freezing in railcars was one problem, but an even bigger concern was the impact that an interruption in the sulfur supply chain would have on petroleum processing operations around the world. After a few months, the market began to accept liquid sulfur. Producers who were receiving positive netbacks six months earlier were now contemplating millions of dollars in demurrage charges and extra steaming costs to thaw the sulfur. Recently, prices have shown some stability but there are differences of opinion on market direction. China continues to buy and has increased its inventory levels while production is starting to surge. Significant amounts of new production will be coming online around the world. A drop in pricing could cause another major disruption.

Managing uncertainty. How can producers deal with a volatile and unpredictable supply/demand balance? One way to help manage the uncertainty is through facility design and selecting sulfur forming and handling technologies. What to do after sulfur recovery. Sulfur recovery refers to the conversion of hydrogen sulfide (H2S) to elemental sulfur. H2S is recovered by means of a sulfur recovery unit (SRU) that converts the gas into liquid elemental sulfur. Elemental sulfur is recovered from the processing of sour natural gas—which has high H2S content—from refining crude oil and upgrading bitumen (from the oil sands) into synthetic crude oil. Some producers and oil sands mining companies are reluctant to move sulfur to market due to low prices for the commodity and/or lack of transportation infrastructure. They opt to pour the sulfur to block.

The hot liquid sulfur from the SRU can also be loaded directly into trucks, railcars or ships and transported to market in liquid form. Molten sulfur storage tanks or pits can be used to provide a buffer between the SRU and the downstream handling system. However, this is an expensive proposition for long-term storage of large quantities of the liquid product. An alternative to blocking or marketing the sulfur in the liquid state is forming Two linesulfur caption it into particles for ease of transportation, handling and storage.

Sulfur facility: A case study. An average sulfur facility is expected to have an annual sulfur throughput of 100,000 tons. A rail line runs near the sulfur facility. The facility wants to evaluate how different sulfur handling and forming designs can help manage market fluctuations (Fig. 2).

Liquid loading. Liquid loading usually involves pumping the sulfur into a railcar, truck or ship. A railcar load-out rack is an elevated structural platform, located beside the rail track, used to access and fill railcars with liquid sulfur. The rack consists of a vertical sulfur pipe rising to a retractable swivel assembly that can be lowered into the top hatch of a railcar or truck tank. There is a flexible rubber hose on bottom flange of the swivel that is lowered 900 800 700 US $ per ton fab

Market fluctuations and uncertainty. In just a

600 500 400 300 200 100 0 Jan-06

Jul-06

ADNOC posting

Jan-07

Jul-07

Jan-08 Date

Jul-08

Jan-09

Jul-09

FIG. 1. US sulfur spot price per ton. HYDROCARBON PROCESSING SULFUR SOLUTIONS 2010

I S–85

SULFUR SOLUTIONS 2010

SRU

Liquid storage (buffer between SRU and downstream)

Blocking temporary solid storage

Forming solid sulfur particles

Block demolition

Formed storage

Remelt

Bulk loading sulfur to market

Liquid loading sulfur to market

FIG. 2. Three sulfur removal options to evaluate.

Pour to block – 275 tpd

120 m x 40 m

120 m x 40 m Sulfur poured in steps

100,000 tons each

12 m high Cross-section

Acid water collection pond

ing tower with one pouring arm. Storm water in contact with the sulfur block is collected in drainage ditches. The ditches flow to a holding pond where the water is collected; it is then pumped to the refinery water treatment facility. A series of interconnected aluminum forms and pins contain and mold liquid sulfur; the forms are raised incrementally as the sulfur block height grows. The sulfur facility is evaluating blocking two years worth of production—200,000 tons. Each block is estimated to be 120 m x 40 m x 12 m high (Fig. 3).

Block demolition. When sulfur prices increase, the block will be remelted. It is proposed that the excavators will break up the block sulfur from the center out and then top to bottom. A ramp will be constructed to facilitate transporting the solid block sulfur by the front-end loaders to the remelter.

Remelting. Remelting sulfur can be a very dirty business. The quality of the blocks will vary based on the time of year that the sulfur was poured and impurities, along with the presence of H2S and SO2, carbon content and numerous other issues. As a result of these variables, there are several concerns that the owner of a remelt facility should be aware of. The sulfur facility is evaluating a pit remelter that has the capacity to remelt sulfur at a rate of 500 tpd based on 22 hours per day of operation.

Forming. Sulfur forming involves solidifying the liquid sulfur into a dry bulk solid form that can be moved to market by truck, rail or ship. The facility selected a forming process due to its small footprint and low installed cost, and to minimize construction, decommissioning and transportation costs. This unit produces 350 tons of premium product per day. The facility’s requirement is approximately 275 tpd.

Downstream conveying. The downstream conveying FIG. 3. Blocking diagram.

into the hatch of the tank. Operators access the hatch by a retracting gangway. The access gangway and piping assembly are able to retract above the height of the railcars to provide unimpeded movement while spotting or queuing trucks. The sulfur facility is planning to load 90-ton railcars that can move the product directly to market. Each train will hold approximately 8,000 tons of sulfur. The load-out rack evaluated has multiple arms and can load approximately 4,000 tons per day (tpd) based on 22 hours per day of operation.

Blocking. Blocking is a form of temporary storage that can help manage fluctuations in the price of sulfur. When the price is low, sulfur is poured to a temporary block. When the price increases, the block can be remelted and sold. A concrete containment berm and HDPE type liner collect and isolate liquid sulfur discharged from the pourS–86

I SULFUR SOLUTIONS 2010

HYDROCARBON PROCESSING

equipment has been selected from pre-engineered conveying systems to minimize costs and manufacturing lead time. The conveying systems are portable and capable of being relocated in the future with minimal decommissioning costs. The equipment can be placed into the plant site without extensive foundation requirements. The tradeoff to this type of equipment is that it requires repeated manual adjustment. The manual adjustment of equipment is with heavy equipment, such as a loader.

Bulk storage. The stock pile system is required for storing large volumes of sulfur through the use of a stacking conveyor. The perimeter of the sulfur stockpile is bounded by concrete barriers to contain product within the designated base pad area during stockpiling and reclaiming operations. The granulated sulfur stockpile can be stacked to a maximum height of approximately 10 m, as permitted by the retaining walls and the angle of repose, approximately 25°. For conveying granulated sulfur, the maximum allowable conveying angle is 15° to prevent product rollback

SULFUR SOLUTIONS 2010

TABLE 1. Evaluating the options Option

Advantage

Disadvantage

Liquid loading

• Low initial capital cost • Low space requirement

• High storage cost • Market is usually only domestic • Exposed to fluctuations in liquid sulfur market

Blocking, block demolition, remelting

• Low short term storage cost

• Temporary • High long-term full-cycle cost • Increased environmental impact • Increased full-cycle CO2 footprint

Forming, bulk storage stockpile and bulk railcar loading

• Low medium term storage cost • Medium capital cost • High market acceptance of product • Can have lowest CO2 impact

• Lower bulk density than liquid or block

and spillage. The stacking conveyor will be on wheels, permitting it to be towed to different positions within the stockpile area. As the sulfur stockpile is formed, the geometry and arrangement of the transfer conveyors and stacking conveyor require adjustments to match the toe of the stockpile. These adjustments include moving the stacker back from the stockpile and adjusting the height of the conveyor feeding the stacker as required. When the stacker feed conveyor can no longer accommodate any further stacker movement, one of the portable conveyors will need to be removed from the lineup and temporarily stored nearby. All conveyor adjustments will need to occur while the granulator is shut down. The facility is looking to have capacity to store 25,000 tons (three months) of formed product in the designated storage area.

FIG. 4. Blocking containment.

Railcar bulk loading. The portable, flexible conveying system will be used to transfer reclaimed sulfur from the stock pile to the railcar loading station. Conveyor hoods are included to minimize spillage due to wind. The facility is planning to load 110-ton railcars that can move the product directly to market. Each train will hold approximately 10,000 tons of formed sulfur. The load-out system that the facility is evaluating can load approximately 5,000 tpd based on 22 hours per day of operation.

Summary. Table 1 illustrates the advantages and disadvantages of three sulfur removal options. Liquid loading has a low initial capital cost and low space requirement. But this option has high liquid storage costs and exposes the facility to fluctuation risks as recently witnessed in the liquid sulfur market. Blocking provides a low short-term temporary storage cost. The facility determined that this option has a high long-term full cycle cost and higher potential environmental impact. Forming has a medium capital cost, low storage cost, a high market acceptance and low environmental impact if forming a premium product. A greater storage area is required because the formed product has a lower bulk density than liquid or block. What the facility liked about this

option was that the sulfur was transformed immediately after the SRU into a highly marketable product that they can easily store and transport around the world.

Conclusion. Careful planning and by designing a sulfur facility is necessary to minimize any impact on the sulfur supply chain from the SRU. Long-term planning is required to minimize environmental impact and to effectively deliver sulfur in a marketplace that is expected over time to become more unpredictable and competitive. ■

Paul Crawford, professional engineer, joined Enersul in 2007 and has over 25 years of business experience in technology development and senior management positions within a number of different industry sectors. He is responsible for all business development, marketing and sales efforts for the corporation encompassing the intellectual property, engineering and operations services segments. Prior to taking this position, Mr. Crawford worked for Enersul as the Director of Technical Services and was responsible for all aspects of project delivery, including engineering, purchasing, quality assurance and after sales customer support. His background in technology development and strategic marketing will strengthen the corporation’s long-term business development initiatives and provide additional leadership through the current market challenges. HYDROCARBON PROCESSING SULFUR SOLUTIONS 2010

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CORPORATE PROFILE

SULFUR SOLUTIONS 2010

AMETEK Headline offers extended capabilities for sulfur (2 lines) measurement and analysis For decadesname Company AMETEK texthas provided hydrocarbon processors and sulfur recovery operators with a broad line of instruments specifically designed for process measurement and analysis. The recent addition of Asoma Instruments to its Process Instruments group has extended the company’s capabilities even further, especially in the realm of helping processors meet emerging ultra-low sulfur content regulations. AMETEK’s line now includes instruments for: • feed gas process control • residual H2S measurement • continuous SO2 emissions monitoring • tail gas and pit gas measurement and analysis • tail gas treating unit analysis • H2S, H2 and HC in natural gas • ultra-low-S measurement in fuels • S and Cl in diesel, gasoline, crude oil, bunker fuel, other petroleum distillates • S in high-temperature, high-pressure, viscous fluids like residual and crude oils.

Single- and Multi-Gas Analyzers. AMETEK makes a range of gas analyzers capable of measuring SO2, H2S, and other species with high accuracy. The Model 880-NSL tail gas analyzer has become an industry standard for online analysis of tail gas in SRUs. The robust Model 920 allows multi-range SO2 analysis, with virtually no H2O or CO2 interference, while the Model 932 multigas H2S analyzer uses a sophisticated UV-VIS photometer to measure up to five gas species in applications ranging from feed gas analysis and reaction rate monitoring to impurity detection and quality assurance monitoring. Benchtop ED-XRF Analyzer. The Phoenix II, a polarized Energy Dispersive-X-Ray Fluorescent (ED-XRF) benchtop analyzer, offers extreme simplicity of operation in a low-cost, compact design. Ideal for elemental analysis of liquids, solids, pastes, slurries and powders, this ED-XRF spectrometer can operate in the rugged production process environment or the laboratory with equal ease. A simple, intuitive touch-screen display makes analysis easy for non-technical operators, yet it’s advanced enough for even the most experienced user, with a “Low S” version capable of detecting less than 1 ppm sulfur in fuels. Predefined, factory-calibrated application packages conform to industry, national and international standards; no need for time-consuming onsite method creation and calibration.

682T-HP. The Model 682T-HP is designed for analysis of sulfur in highly viscous hydrocarbons such as residual and crude oils. This highly sensitive unit easily handles high-sample pressures and situations where fouling of flow-cell windows with paraffin or similar substances can occur.

Two line caption

Designed to measure viscous hydrocarbon in crude lines, pipelines, terminals, and blending operations, the Asoma 682T-HP can help meet emerging lower-sulfur-content regulations. It’s faster, more sensitive and more compact than previous models, and it provides continuous, reliable detection of sulfur at pressures up to 800 psig. It can operate as a stand-alone analyzer or be tied to plant-wide automation systems to provide real-time strategic measurements. Analysis range for sulfur is 0.04%–6.0%.

Experience Makes the Difference. An installed base of more than 2,000 analyzers and 45 years of quality performance make AMETEK the first choice for hydrocarbon processing and sulfur recovery professionals. Serving the industry with solutions that last…that’s AMETEK Process Instruments. Ask us about operator training, too.

Contact Information Phone: 412/828-9040 E-mail: sales.info@ametek.com Web-site: www.ametekpi.com