HP_2009_11 by androsov.info

NOVEMBER 2009

HPIMPACT

SPECIALREPORT

BONUSREPORT

Methanol rides out economic difficulties

PLANT SAFETY AND ENVIRONMENT

WATER MANAGEMENT

Misguided policies interfere with global energy market

Methods to avoid fires and accidents

New technology improves operations for plant water systems

www.HydrocarbonProcessing.com

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NOVEMBER 2009 • VOL. 88 NO. 11 www.HydrocarbonProcessing.com

SPECIAL REPORT: PLANTY SAFETY AND ENVIRONMENT

Prevent storage tank fires

Avoid confusion when performing safety integrity levels

Software tools are never a substitute for competency

Requirement engineering and management— Part 1—safety critical elements identification

Implementing these safety rules can reduce risk R. Ritchie Here’s how to differentiate safety instrumented fuction demand modes Y. A. Khalil and H. Cheddie Sound practice, experienced-based judgment and teamwork are still needed for safety engineering success S. Kozma

Use these guidelines to determine the safety-critical elements and tasks. Free software modules are available to engineer and manage the requirements F.-F. Salimi

HPIMPACT 17 Methanol industry rides out economic difficulties 19 How misguided policies interfere with global market and future supplies

BONUS REPORT: WATER MANAGEMENT

Update management of your cooling water systems

Wastewater treatment: A refinery case study

New ‘fit-for-purpose’ biocide program provides broad-spectrum biofilm control G. Laxton and R. Hernandez-Mena This refiner used an in-house initiative to troubleshoot plant-wide process water problems M. Shafique, Z. U. Kirmani, A. Khurshid, N. Alam and N. Ahmed

PROCESS ANALYZERS

Follow these recommendations for correct analyzer calibration D. Nordstrom and T. Waters

VR (100)

Hydrocracking solutions squeeze more ULSD from heavy ends

SDA at 75% DAO lift

DAO (89)

Ebullated-bed hydrocracker at 85% conversion

Products (74)

Asphalt (26) Unconverted DAO (15)

Overall conversion on Ural feed: 74%

Page 79 SDA plus residual ebullated-bed hydrocracking recycle scheme.

New processing alternatives enable upgrading vacuum residuals into higher-value products F. Morel, J. Bonnardot and E. Benazzi

ENGINEERING CASE HISTORIES

COLUMNS 9 HPIN RELIABILITY Feedback from a pump person

Fine tune accuracy in analytic measurement—Part 2

REFINING DEVELOPMENTS

Cover Industrial clients from around the world participate in one of over 130 customized training courses offered by TEEX-ESTI. Since 1929, TEEX-ESTI has been renowned for providing quality hands-on, realistic, and safety oriented training to over 81,000 personnel each year. TEEX is a member of The Texas A&M University System, one of the largest systems of technical training and higher education in the US. www.teex.org/fire.

Case 53: Electrical faults can cause shaft and gear failures This technique allows transient torques in geared units to be determined T. Sofronas

11 HPINTEGRATION STRATEGIES Installing machine protection systems in hazardous areas 13 HPIN CONTROL APC for min maintenance or max profit?—Part 2 25 HPI VIEWPOINT Forecast for process safety in the 21st century 27 HPI VIEWPOINT Ozone destruction major cause of warming!— Part 2 15 HPIN ASSOCIATIONS Refiners take stock of the new reality, looking within and without the HPI

DEPARTMENTS 7 HPIN BRIEF • 17 HPIMPACT • 29 HPIN CONSTRUCTION • 33 HPI CONSTRUCTION BOXSCORE UPDATE • 90 HPI MARKETPLACE • 93 ADVERTISER INDEX

94 HPIN WATER MANAGEMENT Are your decisions based on obtained data?

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 Chris Valdez Artist/Illustrator David Weeks Manager—Advertising Production Cheryl Willis ADVERTISING SALES See Sales Offices page 92. CIRCULATION +1 (713) 520-4440 Director—Circulation Suzanne McGehee E-mail: circulation@gulfpub.com SUBSCRIPTIONS

Subscription price (includes both print and digital versions): United States and Canada, one year $140, two years $230, three years $315. Outside USA and Canada, one year $195, two years $340, three years $460, digital format one year $140. Airmail rate outside North America $175 additional a year. Single copies $25, prepaid. Because Hydrocarbon Processing is edited specifically to be of greatest value to people working in this specialized business, subscriptions are restricted to those engaged in the hydrocarbon processing industry, or service and supply company personnel connected thereto. Hydrocarbon Processing is indexed by Applied Science & Technology Index, by Chemical Abstracts and by Engineering Index Inc. Microfilm copies available through University Microfilms, International, Ann Arbor, Mich. The full text of Hydrocarbon Processing is also available in electronic versions of the Business Periodicals Index. ARTICLE REPRINTS

If you would like to have a recent article reprinted for an upcoming conference or for use as a marketing tool, contact us 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 Cheryl Willis at +1 (713) 525-4633 or e-mail EditorialReprints@gulfpub.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 © 2009 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

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

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HPIN BRIEF BILLY THINNES, NEWS EDITOR

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BASF recently outlined its Asia-Pacific strategy through the year 2020. The company aims to grow on average two percentage points faster than the Asia-Pacific chemical market each year. With expected market growth of 4% to 5% per year, this would double its regional sales by 2020. Under its new strategy, BASF will initially target five growth industries in the region and it intends to generate 70% of regional sales from local production. BASF will also invest €2 billion in the region between 2012 and 2013, and aims to create efficiency improvements that are expected to save at least €100 million annually by 2012. The investment amount includes BASF’s 50% share of the $1.4 billion expansion of its integrated chemical production joint venture in Nanjing, China, which was approved by the Chinese national government in July 2009. In Chongqing, China, BASF is in the planning phase for a 400,000-tpy plant for diphenylmethane diisocyanate, a precursor for polyurethanes. BASF and the Chongqing authorities aim for mechanical completion of the plant by the end of 2013 and commercial operation by early 2014. Final approval of the project by Chinese regulators is expected in 2009. The European Commission (EC) is urging industry, academia and government entities to collaborate in developing new low-carbon energy technologies by 2020. In a recently released proposal, the EC estimates that an additional investment of €50 billion in energy technology research will be needed over the next 10 years to develop a reasonably priced, low-carbon economy. To reach this goal, it would require tripling the annual investment in alternative energy in the European Union (EU), from €3 to €8 billion. The EC has drawn up technology “roadmaps” which identify key low-carbon technologies with strong potential in six areas: wind, solar, electricity grids, bioenergy, carbon capture and storage and sustainable nuclear fission. “Upgrading investment in research in clean technologies is urgent if Europe is to make the road to Copenhagen and beyond cheaper. Increasing smart investments in research today is an opportunity to develop new sources of growth, to green our economy and to ensure the EU’s competitiveness when we come out of the crisis,” said Janez Potčnik of the EU's Commission for Science and Research.

Significant amounts of greenhouse gases are emitted through the disturbance and/or removal of biocarbons that overlay the oil sands of Alberta, Canada, according to a recent report from Global Forest Watch. These emissions have not previously been measured or reported by governments and industry, the report says. The total area of natural ecosystems that are planned to be removed by oil sands extraction is 1.6 million hectacres and these areas store 579 million tons of biological carbon, mostly in peatlands. As a result, the report says 873 million tons of CO2 may be emitted into the atmosphere over the next 100 years under the scenario of full oil sands development. The resulting annual average emissions of 8.7 million tons of CO2 will raise the normally reported emissions from the oil sands industry activities.

ASTM International recently released a new specification that fully approves the use of gas-to-liquids (GTL) kerosine blends for powering commercial aircraft. The new specification, known as ASTM D7566 or “Aviation turbine fuel containing synthesized hydrocarbons,” approves jet fuel containing up to 50% GTL kerosine for use in civil aviation. The blends will be known as GTL jet fuel. GTL kerosine is one of five GTL products that will be produced in commercial volumes by the Pearl GTL project, currently under construction by Qatar Petroleum and Shell in Ras Laffan, Qatar. The project will produce around 1 million tpy of GTL kerosine, enough to power a typical commercial airliner for 500 million kilometers when used in a 50% blend to make GTL jet fuel. Construction of Pearl GTL is planned to be complete around the end of 2010 with project ramp up then taking about 12 months. GTL kerosine is supposed to be available starting in 2012. The publication of the specification follows two years of research and discussion by the ASTM specification group, a consensus body consisting of producers, equipment manufacturers and consumers of aviation fuel. HP

■ The potential for natural gas The president of BP shared his outlook on the role of gas in the future of energy during a speech at the World Gas Conference in Buenos Aires, Argentina. Tony Hayward said that BP projects the world will need 45% more energy in 2030 than it uses today. To meet this increased energy need, Mr. Hayward predicted an investment of $25–$30 trillion. As far as oil fits into this concept, he remarked that “declining production from existing fields, coupled with new demand, means we’ll have to bring on nearly 50 million bpd of new production over that time—almost twice the current level of production in the Middle East.” While he acknowledged that alternative energy will play a role in addressing future energy issues, Mr. Hayward urged a dose of pragmatic realism, as the transition to a lower carbon economy will not happen overnight. This is due to the sheer scale of the energy industry. Mr. Hayward spoke in optimistic tones about the potential for natural gas. According to BP’s Statistical Review of World Energy in 2008, proven global gas reserves reached more than 6,500 tcf, with enough reserves in place to provide the equivalent of 60 years of consumption at current rates. He also noted that natural gas was the only hydrocarbon to increase in consumption in both OECD and nonOECD countries. Further, the number of countries that import LNG has risen from nine in 1999 to 22 today. “Gas is becoming a global commodity— more flexible, more tradable and more secure,” he said. “Natural gas has been described as a ‘bridge fuel’ to a lower carbon future. It can be much more. Greater use of natural gas can provide us with the quickest, most realistic path to achieving the largest emissions reductions at the lowest cost.” HP HYDROCARBON PROCESSING NOVEMBER 2009

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

Feedback from a pump person In early 2009, we responded to a reader’s request for data; he wanted to use it in a site-wide benchmarking project for pump reliability. The reader was employed at a company location that encompassed close to 1,000 centrifugal process pumps. We shared our response in a “Letter to the Editor” in an earlier issue of HP. In essence, we mentioned that the reader’s company managers had wanted to know—in the 1980s—why they were not among “best-of-class” in pump MTBF. At that time, the shortcomings of their practice of stilt-mounting base plates, “standardizing” on certain seals and couplings, disregarding specific lubricant application weaknesses, etc., were pointed out to his employers. Regrettably, but not totally unexpectedly, pointing out these and other flaws and impediments to high reliability had caused defensive reactions. Additional follow-up correspondence resulted with our reader, who is to be commended for taking the time to do this type of networking. He wrote, saying he had often run into the “defensive thinking” we had described in his company and that, unfortunately, overbearing pride or presumption can blind us to reality. To quote: “I have no illusions that this will be a quick-fix situation or that I would have time to question many of the current pump installations that we have on site. I am working closely with our two primary ANSI pump suppliers to look at parts costs and obsolescence. At the same time, I am doing an overall reliability growth study on all of the pumps at our site. As part of this effort, we are developing plans to consolidate our current rebuild-byparts philosophy and to use a “Power End* Consignment” rebuild system instead. This is because of several factors, including an aging workforce with a resultant loss in maintenance expertise due to retirement. In turn, this has caused us to have a growing number of pumps in the past few years that have experienced “sudden death” due to poor overhaul practices. In many cases, simple things such as not checking bearing housing and seal tolerances have led to failures within days, weeks or a few months. Like many companies, we are in the throes of trying to reduce costs and maintenance manpower pressures in the face of the current economic environment. We also have a number of problems with older pumps becoming obsolete, to the point that it is less expensive to buy a new pump as opposed to buying the parts to rebuild the existing pump. Additionally, the older pumps just don’t incorporate many of the reliability upgrades that now come standard with the new-design pumps available.” The reader’s observations are undoubtedly correct. However, for the edification of our readers, HP would like to add that there is one thing that’s less expensive than changing out an entire pump: It’s to take steps to avoid repair incidents altogether. Sooner * A “power end” is the non-hydraulic portion of a centrifugal pump (Fig. 1). We elected to show it here with an advanced rotating labyrinth seal upgrade (LabTecta, TM).

FIG. 1

Power end (drive-end) of a centrifugal pump, shown here with a modern bearing housing seal. Note also how the thrust-bearing cartridge is sized to allow insertion of a steel flinger disc.

or later industry and serious individuals will have to question the premise that pump failures are unavoidable. Meanwhile, there is no rationale for not investigating and understanding the rootcauses of pump failures. Next to electric motors, pumps are the simplest machine category found in a process plant, and to not understand a failure cause leads to costly repeat incidents. Sooner or later managers must insist on inculcating a loathing for repeat failures. Repeat failures are the surest sign of an entire workforce not being trained in root-cause failure analysis. Granted that, given the reader’s situation, his resorting to power-end rebuilds may be a step in the right direction. But it will not cure underlying weaknesses such as pipe stress, or base plate support deficiencies, or using 30-year-old bearing housing sealing technology, or oil rings instead of flinger discs and a host of other causal possibilities. HP

The author is HP’s Reliability/Equipment Editor. A practicing engineer and ASME Fellow with close to 50 years of industrial experience, he advises process plants on maintenance cost-reduction and reliability upgrade issues. Ten of his 17 textbooks on machinery reliability improvement subjects are still in print and updated editions have been released as recently as 2009.

HYDROCARBON PROCESSING NOVEMBER 2009

INNOVATIVE TECHNOLOGIES

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HPINTEGRATION STRATEGIES WIL CHIN, CONTRIBUTING EDITOR wchin@arcweb.com

Installing machine protection systems in hazardous areas The plant asset management (PAM) market for production assets, which includes protection and prediction solutions, has spread from traditional turbomachinery to virtually every asset essential for efficient production. ARC Advisory Group’s recently released PAM study pegged the market for PAM for production assets at more than $1.4B in 2008 and expects this to be one of the faster-growing automation investments through 2013. The study identified the growing need for integrated predictive health solutions to complement the core protection functionality required for high-end equipment. Machinery protection systems have been a common sight in the HPI and other heavy process industries ever since the introduction of sophisticated high-value turbomachinery. These systems consist of many components, including software, intrinsically safe (IS) barriers and sensors that require a large nest of wires that connect to a bank of rack-mounted electronic control equipment, often located in environmentally protected rooms or the plant control room. Most legacy machinery protection systems installed in existing plants have point-to-point connections that require as many as eight or more separate wiring runs between plant hazardous and safe areas. As plants increase in size, every inch of free space for new components has long since been filled with overloaded cable trays. This makes upgrading to new equipment of any kind increasingly difficult, since there simply is no space. Even replacing older equipment with newer units is a chore due to the increasing probability of damaging equipment and connections adjacent to or close to the slot being worked on. Designed to meet the highest reliability standards for protection systems, particularly API-670, legacy machinery protection systems have previously resisted the inclusion of IS communications networks, despite their widespread use in the process industries. And unlike PAM systems for other classes of process assets, little in the way of predictive asset management functionality was included in these solutions. Predictive technologies provide an alert well before a protection system shutdown is required, providing operators with sufficient warning to take action to prevent the economic consequences of an abrupt failure and shutdown. These and other reasons prompted SKF Reliability Systems (San Diego, California) to introduce a compact, locally mounted, IS integrated protection and predictive asset health solution for plant machinery (Fig. 1) The company, no stranger to PAM solutions for production assets, provides PAM hardware, software and services that aimed at improving asset reliability and availability. SKF has partnered with IS interface equipment leader, Pepper+Fuchs, to develop a field-mounted IS protection and predictive condition monitoring solution suitable for installation close to the equipment it protects. The SKF Multilog DMx system accepts inputs from a multitude of sensors that measure vibration, acceleration, velocity, displacement and other process variables, and its digital communication requires only a single- or dual-pair cable set, reducing

FIG. 1

In addition to highly reliable machinery protection functionality, SKF’s Multilog DMx solution provides users with critical equipment diagnostic information that can be used to predict and avoid problems, even for equipment located in hazardous environments requiring intrinsic safety.

installation costs and startup time. Field installation in hazardous areas, particularly for legacy equipment retrofits, is simplified and can reduce the number of cabinets and isolation barriers. Successful applications include critical and noncritical turbomachinery and pumps in pipelines, refineries, chemical and water and wastewater plants. End users value the low installed cost and its ability to quickly migrate old legacy systems to DMx’s distributed architecture close to the machinery, without disrupting plant operation. The IS design allows installation without special authorization, and the DMx has garnered a number of agency approvals, including ATEX, CE, UL and others. This validates its applicability for both hazardous and conventional environments. Additionally, the ability to use the RS-485 signal to connect operators in the control room to the intelligence embedded in the DMx provides needed insight into equipment health that was previously unavailable using legacy systems. The configuration and data display software provides intuitive management of transducers, equipment health data and alarms. The interface can access scalar value, time-waveform, FFT and orbit data from a multitude of DMx monitor channels. Users can also deploy SKF’s @ptitude Monitoring Suite for additional data analysis, as needed. HP The author leads the field device consulting team at ARC covering process measurement technologies. He is responsible for pressure, flow, level, temperature and related markets. Mr. Chin also covers field device communication protocols, plant asset management (PAM) and laboratory information management systems (LIMS). He has nearly 30 years’ experience in the areas of sales management, product marketing and engineering in industrial field instruments.

HYDROCARBON PROCESSING NOVEMBER 2009

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

APC for min maintenance or max profit?—Part 2 While I have promoted proper control system performance indicators18–25 since 1964, like Dr. Y. Zak Friedman,1 I also am aware of some deeper problems with realizing its full commercial potential.3,8–10,17,26 Friedman once publically claimed Clifftent24 was no panacea,27 without seeing it in action. Moreover, he charged, without any basis, that Clifftent, a mathematical procedure, could lead to burning down a furnace. My experience is proper deployment of Clifftent to operate the HPI would mitigate such events26 because it mandates careful modeling of the financial consequences of exceeding properly set limits like burning down furnaces, so operators would be using better information and models to make appropriate setpoint decisions for risky tradeoffs. Determining such effects rather than ignoring them is the main idea of science, mathematics and engineering. I refrain from blaming MVC, PID, LP, SQC, feed-forward, inferentials, six-sigma, statistics, calculus or mathematics for burning down furnaces. I have published practical examples of using Clifftent to calculate APC benefits many times for real applications6,7,18–25,28 since the low-sulfur fuel oil example24 in HP, December 1996. I have a library of commercial oil refinery, olefin, aromatics, polymer, synfuels, chemicals and gas processing applications now. Every single one is a success because it determines a profit improvement (sometimes small) and how to achieve it. I recently showed23 how to quantify the value of Friedman’s alkylation control approach.29 As for how Clifftent works, I have published that too6,7,18,19,24,25,28 and will repeat it here. Every controlled variable (CV ) has a risky profit tradeoff. Calculus and statistics teach integration of the product of a data frequency distribution with its associated profit function gives its average (expected value) profit. Repeated integrations with incremented data means give the average profit profile vs. data mean; a smooth hill (for any standard deviation >0). It’s easy to locate the hilltop max profit and corresponding optimum data mean. That’s how all HPI setpoints, limits, targets and specs are set now, although with less rigor. That's also how CV /KPI profit meters can be built.19 The HPI received the panacea in 1996.24 A Canadian University ChE Department included determining dynamic system financial performance, Clifftent, in its process control course in September 2009. Hopefully this rekindled academic interest in process control and research on building Clifftent models for integrated alarm management, process maintenance and safety. Once a set of candidate CV s and related manipulated variables (MV s) are established and the process operation and economics are known, good process control engineering practice3,6,7,16–19,21–25,28 calls for determining the economic sensitivity of each CV, their Clifftents and a variance reduction claim for each control system design, providing the appropriate setpoint determination method and benefit for that variance reduction. Then the process control engineer is in a solid position to design, maintain and improve the instruments

and control system, the process operator is in a sound position to use it and operating company management understands its role and value. They finally have a chemical engineering method for operation that is pragmatic, prudent and profitable. In fact, I claim had one or two computer-integrated manufacturing (CIM) solution suppliers adopted performance-based licensing when it was commercialized in the mid-1990s,2–17,24,25 the landscape of the APC and CIM business in the HPI today would be healthier, more significant and more profitable for those suppliers and their operating company partners. And much misguided effort and expense would have been avoided. Friedman would certainly not be proposing in a 2009 HP editorial forgoing 30% of APC performance, worth >$0.30/bbl crude refined, to reduce APC maintenance costs. It would not be pragmatic, prudent or profitable. Dr Y. Zak Friedman’s HPIn Control editorials continue to serve the HPI. I hope I can add to them on occasion. HP LITERATURE CITED Latour, P. R., “Why Invest in PROCESS CONTROL?”, CONTROL, Vol. XV, n5, May 2002, pp. 41–46. 19 Latour, P. R., “Why tune control loops? Why make control loops?”, editorial guest columnist, Hydrocarbon Processing, V81, n9, September 2002, pp. 11–12. 20 McMahon, T. K., (& P. R. Latour), “CLIFFTENT For Process Optimization,” CONTROL, V17, n12, December 2004, p. 66. 21 Latour, P. R., “Decisions about risk reduction,” Letter to Editor, Hydrocarbon Processing, V80, n6, June 2001, p. 39. 22 Latour, P. R., “Quantifying financial values”, HP In Control Guest Columnist, Hydrocarbon Processing, V80, n7, July 2001, pp. 13–14. 23 Latour, P. R., “Align alkylation separation to economics,” HPIn Control Editorial, Hydrocarbon Processing, V88, n1, January 2009, p. 98. 24 Latour, P. R., “Process control: CLIFFTENT shows it’s more profitable than expected,” Hydrocarbon Processing, V75, n12, December 1996, pp. 75–80. Republished in Kane, Les, Ed, Advanced Process Control and Information Systems for the Process Industries, Gulf Publishing, Co, 1999, pp. 31–37. 25 Latour, P. R., “CLIFFTENT: Determining Full Financial Benefit from Improved Dynamic Performance,” Paper C01, Third International Conference on Foundations of Computer-Aided Process Operations, Snowbird, Utah, July 5–10, 1998. Proceedings published in AIChE Symposium Series No. 320, V94, 1998, pp. 297–302. 26 Baker, J. A. et al, “The Report of The BP U.S. Refineries Independent Safety Review Panel,” January 2007. 27 Friedman, Y. Z., (& G. D. Martin, P. R. Latour), “APC Survey,” Exchange of Letters to the Editor, Hydrocarbon Processing, V85, n10, October 2006, pp. 45-46 and V85, n11, November 2006, pp. 45-52. 28 Latour, P. R., “Align Olefin Operations to Economics – Clifftent optimizes setpoints,” presented at 2007 Spring AIChE Meeting Ethylene Producers Conference, Houston, Texas, April 23, 2007. Published in Conference Proceedings CD. 29 Friedman, Y. Z., “Alkylation product separation control,” HPIn Control editorial, Hydrocarbon Processing, V87, n9, September 2008, p. 178. 18

The author, president of CLIFFTENT Inc., is an independent consulting chemical engineer specializing in identifying, capturing and sustaining measurable financial value from HPI dynamic process control, IT and CIM solutions (CLIFFTENT) using performance-based shared risk–shared reward (SR2) technology licensing.

HYDROCARBON PROCESSING NOVEMBER 2009

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HPIN ASSOCIATIONS BILLY THINNES, NEWS EDITOR

bt@HydrocarbonProcessing.com

Refiners take stock of the new reality, looking within and without the HPI Last month, the NPRA convened its yearly technical forum in Fort Worth, Texas. Papers were presented, introductions were made and business was done. As attendees milled around the anterooms of the new downtown Omni Hotel and hospitality suites percolated with activity, Hydrocarbon Processing monitored it all with an understated efficiency. Transportation fuels outlook. Jeff

Morris, CEO of Alon USA, offered a keynote address on fuels and made it clear that refiners are completely intertwined with the automotive industry. “Before we can have a view on the future of transportation fuels, we must first have a view on the future of vehicles,” Mr. Morris said. “What we need to think about as an industry is if are we going into a new normal or reverting to the vehicle buying habits of the past.” Looking at an overview of the automotive industry and why things are the way they are with current vehicle manufacture trends, Mr. Morris said, “The automakers are going to meet CAFE standards and want to be the greenest out there, but they don’t have any money to retool so they are pushing what they’ve got. The Europeans are pushing diesel. The Asians have the hybrids and they are pushing them. Detroit, unfortunately, did neither, so they went the ethanol route and that didn’t work, so now they are going to a plug-in hybrid, which might be the right approach.” Refiners can address the loss in gasoline consumption by turning to distillates. Mr. Morris cited statistical data that would indicate that as industrial production improves, distillate demand should improve. Thus, as the US and the rest of the world slowly emerge from the current recession, diesel demand will be back. Experts from the EIA, to Purvin and Gertz suggest that from 2015 to 2030, there is the possibility for a net gain of 1 million barrels per day of distillate consumption.

Jeff Morris of Alon USA addressed the future of transportation fuels during the 2009 NPRA Q&A and Technology Forum.

“What that means is that we have to retool a million barrels a day of our production capacity from gas to diesel,” Mr. Morris said. A report from the Argonne National Labs analyzing fuel efficiency and greenhouse gas emissions on a well-to-wheels basis per month shows that, if you want to improve fuel efficiency for the US fleet by 2020, clean diesel is 20% better and plugin hybrids are 55% better. But for the plugins, this assumes a 40-mile range and an average commute of less than 40 miles. Still, crude oil is going to be important for global transportation. “Crude oil will continue to be the basic feedstock for transportation fuels,” he said. Legislative overview. Greg Scott,

the new executive vice president and general counsel for the NPRA, delved into the NPRA’s key public policy areas in Washington, DC, which are federal climate change legislation; fuel regulations like renewable fuel standards (RFS2), E15 and low carbon fuel standards (LCFS); taxes; chemical facility anti-terrorism standards (CFATS); and reform of the Toxic Substances Control Act (TSCA). Regarding the cap and trade legislation that passed the US House in June, Mr. Scott pointed out that refiners make

up 36–38% of the inventory of CO 2 emissions in any given year. “And yet we received from the House, in a fascinating political dynamic, only about 2¼% of the allowances in year one and that declines over time,” he said. Mr. Scott continued this train of thought by pointing out that electricity generators are responsible for 35% of overall US emissions and yet they received a 38% allowance of credits. He thinks rationale for this credit imbalance is because House members did not want the electricity interests to pass the costs through to consumers and then have the consumers react unfavorably, thereby creating a political backlash. “There is something wrong here when they are giving free allowances to utilities and no allowances to the oil companies and producers of motor fuel for consumer emissions,” Mr. Scott said. Plant automation session. Dustin Beebe and Darwin Logerot of ProSys discussed optimization and carbon caps. They pointed out that CO 2 limits will begin for refineries in 2014. Two approaches to reducing CO2 emissions were discussed: advanced process control (APC) and CO2 sequestration. APC, using multivariable predictive control (MPC), was cited as the most cost-effective method to increase plant efficiency and thus reduce emissions. The problem with current APC implementation is that it is typically applied to individual process units with little coordination between process units. A solution is real-time optimization (RTO). RTO has been discussed for several years but there are few installations because the models weren’t accurate enough and implementation was too expensive to yield a good return on investment (ROI). However, with improved models running on lowercost computer hardware, the economics of implementing RTO is improving. HP

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HPIMPACT BILLY THINNES, NEWS EDITOR

BT@HydrocarbonProcessing.com

Methanol industry rides out economic difficulties The global MeOH market has more capacity than demand, according to remarks made by Jim Jordan at the 2009 Methanol Forum in Houston, Texas. A gap exists between global supply and demand and a number of factors are contributing to the present situation. Interestingly, the global supply and demand graph indicates a very long MeOH market, especially during 2009 and 2010 (Fig. 1). Demand is forecast to increase in 2009, even though two major consuming regions (US and Europe) have seen sharp declines in demand due to the recession. In contrast, MeOH demand in China has overshadowed all recession-driven losses in other regions this year. Looking ahead, the growing alternative fuels market will drive most of the new MeOH demand in 2011–2013.

mostly imported from the US. Recently, Chile has become a major MTBE consumer. In SA, MeOH capacity is approaching 10 MM mtons. A new MeOH facility in Venezuela is scheduled for startup during the first half of 2010. Chile has approximately 3.8 MM mtons of capacity. Unfortunately, Chile lacks sufficient natural gas supplies to operate all available capacity. In North America (NA), MeOH demand has declined substantially in response to the removal of MTBE from the gasoline blending pool. Formaldehyde has always been the mainstay for MeOh demand in NA. Unfortunately, demand for this petrochemical was severely impacted by the current recession. Formaldehyde demand is closely linked to the housing industry and recent low housing starts have had a negative impact on formaldehyde demand. Losses in the MTBE market and a downturn in formaldehyde demand has caused several US MeOH plants to close.

onstream in 2009 and 1010. Most of this new capacity is located in the ME. China is forecast to add 5 MM mtons by 2013; however, commissioning of the new capacity can be delayed. Data associated with the global recession and the recent, ongoing capacity expansion suggests that MeOH producers should be going out of business at a record pace. Operating rates of 70% or less normally spell disaster for most commodities. Nevertheless, MeOH prices around 75¢/ gal to 80¢/gal ($249–$266/metric ton) are providing reasonable returns for most producers. Even most Chinese plants can run profitably at present prices. In China, several plants have not operated in 2009. Low prices earlier this year forced many plants to shut down at a time when China’s MeOH demand was actually growing. Imports filled the gap between domestic production and demand. China’s MeOH capacity is growing, but so is demand. In 2005, China’s MeOH demand and capacity was 4 MM mton. At present, China’s annual MeOH demand will reach 15 MM mton. In a high-price environment, the major portion of this demand will be produced internally, but the longer term pattern remains unclear.

MeOH demand, million metric tons

The Middle East. The Middle East (ME) is the “bread-basket” for the global MeOH New capacity. Approximately 10 to industry. When Africa is included, MeOH 15 MM mtons of new MeOH capacity is capacity in this region exceeds 15 milllion approved or under construction to come metric tons (MM mtons). Yet, the ME only consumes about 70 3 MM mtons, most of which is World capacity for methyl tertiary butyl ether 60 (MTBE). The rest of the regional MeOH production is exported, 50 with a significant portion as MTBE. The ME’s MTBE production is forecast to increase 40 over the next 10 years in reaction to lower MTBE production 30 in the US. The Americas. Similar to the 20 ME, South America (SA), including the Caribbean, remains a sig10 nificant MeOH producer but not a large consumer. In the late 1980s, most MeOH capacity was 0 built in Chile, Trinidad and Ven2006 2007 2008 2009 2010E 2011E 2012E 2013E ezuela, but that trend is changOthers Methanethiol (methyl mercaptan) ing. Argentina exports sizeable Methanol-to-Oleﬁns Dimethyl terephthalate (DMT) Fuel Cells Methyl methacrylate amounts of biodiesel to Europe Alternative fuels Methyl tert-butyl ether (MTBE) and is increasing biodiesel usage as Methyl chloride (Chloromethane) Acetic acid a fuel substitute. MTBE continMethylamines Formaldehyde ues to be produced and consumed FIG. 1 World MeOH demand and capacity, 2006–2013. in Venezuela. Mexico consumes a significant volume of MTBE—

Pricing trends. MeOH

prices have risen and should exceed $250/metric ton. This will stimulate US production. Yet, MeOH is an energy product and will ultimately follow energy prices. With MeOH moving more and more directly into energy applications, this becomes even more evident. The global MeOH market now has more capacity than is required to meet present demand, with additional capacity coming onstream. As global economies recover and MeOH demand increases not only in China, but globally, the overhang of supply will decrease. Until then (probably through at least 2011 and possibly 2012), price volatility for MeOH will continue. —Stephany Romanow

HYDROCARBON PROCESSING NOVEMBER 2009

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HPIMPACT

The new energy economy. As

Production and consumption, million bpd

society moved from the 1800s to present day, energy sources and carbon output changed, Dr. Economides said. In the 1800s, humans were using wood, which had high carbon content. As time went on, the transfer was made to coal and oil which can be classified as having medium carbon content. Now, society is evolving to natural gas (low-car8 bon content) and the envisioned 7 hydrogen solution would have no carbon content. 6 The professor then delved into a series of slides showing news 5 stories discussing new energy pos4 sibilities. These included extracting hydrogen from vegetable 3 matter by heating the vegetable 2 matter to 437°F, golf resorts using hydrogen fuel cells, cattle brains 1 being turned into biofuels and 0 robotic lawnmowers. 1980 “There are no alternatives to hydrocarbon energy sources FIG. 3 in the foreseeable future,” Dr. Economides said.

Majors

Top 25 reserves oil, NGL and natural gas

300,000 250,000 200,000 150,000 100,000 50,000

Total

Surgutneftegas

ConocoPhillips

Chevron

Petrobras

Lukoil Pemex (Mexico) Shell

Turkmengas

QP (Qatar) Gazprom (Russia) KPC (Kuwait) PDV (Venezuela) Adnoc (Abu Dhabi) NNPC (Nigeria) Sonatrach (Algeria) Libya NOC CNPC (China) Petronas (Malaysia) Exxon Mobil Rosneft (Russia) BP

INOC (Iraq)

NIOC (Iran)

0 Aramco (Saudi)

Rice University convened its 12th annual global engineering and construction forum in mid-September. One of the featured speakers was Dr. Michael Economides, a professor of chemical and bimolecular engineering in the Cullen College of Engineering at the University of Houston. Dr. Economides gave an engaging presentation on how misguided policies interfere with global market and future supplies. Dr. Economides began his remarks by offering an overview of the global energy market, touching on energy sources from hydrocarbons to solar power. He said that international demand decline for natural gas has been larger than anticipated. Because of LNG developments in Qatar, Egypt and Sakhalin 2, there could be 10 Bcf/d of excess natural gas supply. This would create considerable impact on prices in Europe and the US, he said. A major geopolitical problem facing the world currently is that oil and gas reserves are not easily accessible by independent oil companies (IOCs). These companies only have access to 7% of the world’s reserves (Fig.2).

350,000

MMboe

How misguided policies interfere with global market and future supplies

Source: Energy Intelligence Group 2008

FIG. 2

Top 25 global reserves for oil, NGL and natural gas.

Climate change. Regarding climate change, he said it is highly politicized, with everyone having an opinion on what to do, wondering if anything at all can be done and what the cost might be. He said there is sometimes confusion, at times deliberate, between global warming and man-made effects. Dr. Economides remarked that it is “preposterous” to believe that “science is all in” in relation to global warming. He is offering $10,000 for one peer-reviewed paper showing causality between CO2 and increased temperature, because he believes no link exists. He then cited a study in which two South Florida scientists assert that warming ocean temperatures actually translate to fewer Atlantic hurricanes menacing the US. Their argument is that higher ocean surface temperatures increase wind shear, and wind shear makes it difficult for large storms to maintain their integrity.

Axis of energy militants. Dr. Economides included Iran, Venezuela, Russia, Iraq and China in his proposed axis of energy militants. In Russia’s case, he pointed out that with the crash in oil prices, the bright spot is waning in the Russian economy. He also sees a “re-Sovietization” happening in the county, with corruption running rampant, the press under lock down and a cooling investment climate. Dr. Economides believes that production in Russia is bound to decline. He also discussed Russia’s energy re-centralization, with the central government running roughshod over private companies like BP, Shell, Yukos and Sibneft. Finally, Dr. Economides points to indicators showing Russia is moving to control even more of Europe’s natural gas market, a market it already dominates. Gazprom provides Europe with over 25% of its natural gas, and a series of business deals with Iran and Libya point to efforts to increase this share.

China’s oil production and consumption Production Consumption

1985

1990

1995 Year

2000

2005

China’s oil production and consumption, 1980–2010.

2010

China. The big question that has yet to be answered is if China can keep its lights on. Energy very well could be China’s choke point, Dr. Economides said. Since the early 1990s, China’s consumption of oil has far outweighed its production, as show in Fig. 3. To make up that growing difference, China has become an assertive, if not belligerent player in cutting deals for oil with countries like Sudan, Nigeria, Canada and Venezuela. In conjunction with those deals, Dr. Economides believes that China’s energy future is directly linked to Russia. HP

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HPINNOVATIONS SELECTED BY HYDROCARBON PROCESSING EDITORS editorial@gulfpub.com

Sustainable hydrogen process announced The Linde Group is developing an innovative process for the sustainable hydrogen production from biogenic raw materials. Hydromotive GmbH, a subsidiary of The Linde Group, plans to build a demonstration plant at the chemical site in Leuna, Germany, which will produce hydrogen from glycerine—a byproduct of biodiesel production. Promising opportunities for the sustainable cost-effective hydrogen production are possible by using biogenic raw materials. The new technology can provide an innovative step toward low-emission energy supply using hydrogen. The plant will reprocess, pyrolyse and reform raw glycerine; the facility is forecast to come onstream in mid-2010. This facility will produce a hydrogen-rich gas, which will be fed to the existing Leuna II hydrogen plant for the purification and liquefaction. The “green” liquefied hydrogen produced will initially be used in German centers such as Berlin and Hamburg where hydrogen is distributed as a transportation fuel. Due to high hydrogen content, raw glycerine, produced from biodiesel manufacturing, is particularly suited for hydrogen production. Biogenically produced glycerine will not compete with food production and is available all year round. As the world’s largest manufacturer of hydrogen plants, Linde has access to the full-range of technology required for using hydrogen as an energy carrier. Select 1 at www.HydrocarbonProcessing.com/RS

Specialty heat exchanger wins award Alfa Laval has a new technology that can increase efficiency and reduce energy consumption for chemical production with the first plate reactor, called ART PR49. This development implies a revolutionary technology shift for chemical production processing methodology. Competitive pressure and environmental legislation are forcing the chemical industries to find new production techniques for safer, cleaner and more efficient means of manufacturing. Alfa Laval’s latest innovation changes one of the most essen-

tial organic chemical processes—the reaction between two or more substances. The ART PR49 combines the properties of a chemical reactor with those of a plate-heat exchanger. Traditionally, you create a reaction by adding one substance to another. The reaction can generate intense and damaging heat. To minimize the negative impacts, the reacting substance is either diluted or added over a longer time. The new plate reactor reduces the time needed, and the reaction can be performed with higher concentrations. The continuous flow of reactants creates optimal reaction conditions, and the plate technology removes any excess heat. Alfa Laval’s new continuous plate reactor ART PR49 was shown during the international process industry exhibition ACHEMA 2009, and won the “Process Innovation Award.” Select 2 at www.HydrocarbonProcessing.com/RS

New elastomers for film applications released ExxonMobil Chemical has introduced three new grades of Vistamaxx specialty elastomers, which exhibit a very low gel count, making them ideal for high-performance film and fiber applications. Like all Vistamaxx specialty elastomers, these grades can be blended with polyethylene (PE) and polypropylene (PP), or used as interfacing layers with PE and PP structures, to deliver excellent tie layer and lamination performance. Offering very low seal-initiation temperatures combined with high seal strength, they are ideal for use as a sealing layer in coextruded structures. Easy to process and available as free-flowing pellets, Vistamaxx 3020FL, Vistamaxx 3980FL and Vistamaxx 6102FL elastomers also offer good optical properties and good chemical resistance. Additionally, the melt flow and ethylene co-monomer content of the VisAs HP editors, we hear about new products, patents, software, processes, services, etc., that are true industry innovations—a cut above the typical product offerings. This section enables us to highlight these significant developments. For more information from these companies, please go to our Website at www.HydrocarbonProcessing.com/rs and select the reader service number.

tamaxx 3020FL and Vistamaxx 3980FL grades makes them perfectly suited for other polymer modification applications. “These grades to the Vistamaxx elastomer portfolio further increases the ability of compounders and converters to develop innovative solutions and tailor properties to better meet the needs of many applications,” according to Lynell Maenza, specialty elastomers Asia Pacific market manager, ExxonMobil Chemical. Vistamaxx specialty elastomers are suited for all polyolefinic blends and can also be a partial substitute for a variety of other polymers including styrene block copolymers and polyisobutylene. Using Vistamaxx elastomers can reduce compound cost and improve performance where a balance of flexibility, impact strength and transparency is required. Typical applications include calendered or extruded sheetprofiles, extrusion coating, nonwovens and injection- or blow-molded goods. Select 3 at www.HydrocarbonProcessing.com/RS

Thermoplastic pipe is easier to maintain Evonik has introduced, for the first time in North America, a new high-performance thermoplastic polyamide pipe that is less expensive to install and easier to maintain than traditional steel pipe. VESTAMID LX9030 PA12 (VESTAMID PA12) offers exceptional performance for high-pressure applications, which helps gas companies effectively design their underground infrastructure without sacrificing flow capacity. Researchers estimate that PA12 pipe has significant labor and installation savings over steel. It is an excellent alternative to steel pipe in high-pressure applications up to 250 psi for gas distribution lines. The material is lightweight and allows for faster construction than steel, while maintaining higher volumes associated with higher pressures. Installation can be accomplished using a smaller construction crew, saving time and money. Low initial investment is required for construction teams because the same equipment and processes are used when installing VESTAMID PA12 pipe (Fig. 1) as with other plastic pipe. Traditional steel pipe must adhere to corrosion control and HYDROCARBON PROCESSING NOVEMBER 2009

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HPINNOVATIONS

FIG. 1

VESTAMID PA12 pipe coils reduce labor and installation costs.

cathodic protection requirements, which adds to a company’s expense. PA12 is corrosion resistant and has labor and installation savings over steel. In research performed by GTI and sponsored by Operations Technology Development, NFP (OTD), PA12 has been evaluated for use as gas-distribution piping in North America and technical support necessary to obtain regulatory approval for its use in the US was developed. Extensive testing of materials resulted in a comprehensive database of the physical properties of PA12 pipe and demonstrated conformity to ASTM standards. Select 4 at www.HydrocarbonProcessing.com/RS

Video software records exactly what was on HMI screens Longwatch announces the Operator’s Console Recorder, a software module that automatically records images being shown on multiple HMI or SCADA operators’ displays. The module takes its signals directly from each HMI screen’s video software driver, so it records the actual video being sent to the HMI. The software can accommodate video signals from an unlimited number of HMIs to show what operators were watching at the time of an event, alarm or process upset. Video images can be combined with the automatic data mapping capability of Longwatch’s Video Historian, so the Console Recorder can automatically retrieve and replay operator displays simply by clicking on a time-based alarm or system message. Playing back what the operator was seeing at the time of an event can be a valuable tool for training and analysis purposes, and can help mitigate insurance and regulatory issues by eliminating guesswork and conjecture. Select 152 at www.HydrocarbonProcessing.com/RS

Videos used for monitoring plant activities can also be combined with the operator console videos and data from a process historian. This enables engineers, analysts or investigators to see what was happening in the plant, what the operator was seeing on the HMI screen at the time, and all relevant real-time data that occurred at the time of an event. Capturing the actual video feed to the operator HMI is a much better solution than traditional methods, says Steve Rubin, president of Longwatch. “Before Longwatch, recording and playback of an operator’s HMI was clumsy and limited. One method was to put a camera over the operator’s shoulder. This is intrusive and intimidating, and the camera has a limited ability to read what’s on the screen,” he explains. “In an installation with multiple HMIs, this solution would require a camera on each screen.” Select 5 at www.HydrocarbonProcessing.com/RS

‘Universal Process Identifier’ Cutler Technology introduces a new paradigm in process control that provides the automated means to capture new revenue from existing operations while enhancing the control room operators’ ability to manually contribute to the overall success of the operation. The same Universal Process Identifier creates models for advanced process control, online operator advisory systems and the operator training simulator. Clients in the oil refining and chemicals industries are enjoying increased profits while lowering their cost of ownership and maintenance compared to similar stand-alone solutions. Specific benefits include improved controller performance by mitigating regulatory control problems caused by tuning and valve saturation. Use of the controller’s model as a basis permits simulation speeds of 100 to 150 faster than real time for the online advisor and the offline training simulator. A high-frequency multivariable controller using an all-valve dynamic process model with adaptive valve transformations and unmeasured disturbance rejection can provide satisfactory control of a complex process such as an FCCU. More importantly, the new controller delivered more economic benefit than the classic DMC application. The use of the same basic model for advanced process control, advising the operator on future alarms, and offline simulations with training scenarios, solves many of the problems with maintenance of these type of systems. Select 6 at www.HydrocarbonProcessing.com/RS

Exceptionally reliable H2 compression Innovation involves more than good ideas! P a s s i o n f o r C o m p re s s i o n

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Welcome to the Future iPRSM® is what your company needs to achieve PSM compliance and meet OSHA’s 29 CFR 1910.119 standard. A powerful engineering calculation platform from Farris Engineering Services, iPRSM: • Creates the foundation for a comprehensive pressure relief management solution • Minimizes operational interruptions and losses by identifying overpressure risks • Models engineering changes at any stage of a process with the Impact Analysis Tool • Provides a complete documentation package which can supplement a MOC policy • Features patented web-based technology for quick integration into your plant or multi-site corporation Coupled with the resources of iPRSM, the Farris Engineering Services team can provide you with: • Comprehensive pressure relief system evaluation • Proven process safety management audit methodology • Pressure relief device mitigation and recommendation for corrective action Welcome to your future. Proactive, cost-effective effective solutions for a safe and hazard-free work environment. ment. For more information, visit us on the webb at http://fes.cwfc.com

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HPI VIEWPOINT SANJEEV SARAF, GUEST COLUMNIST ssaraf@exponent.com

Forecast for process safety in the 21st century 600

551

500 Number of incidents

The 20th century was a time of great technological change. Such changes that have forever altered how we live and work. The 1970s brought the creation of the US Environmental Protection Agency and the Occupational Safety and Health Agency. The 1980s witnessed one of the greatest tragedies in the last century— an estimated 4,000 people died in the 1984 Bhopal accident. Following Bhopal, we saw the birth and development of the field of Process Safety Management. Since then, the process safety community has evolved in its approaches and methodologies to manage risks. But what have we, as process safety professionals, learned from the experiences of the 20th century, and how can we use that learning to make the process industry safer in the 21st Century?

400 300

270

200 100

49 Total incidents

Historic incident data. Based on data from Lee’s Loss PrevenFIG. 1

One Two Zero fatality fatalities fatalities Number of fatalities

16 Three fatalities

Fatalities in the process industry by number of incidents, 1911–1995.

1,000 281 incidents with one or more fatalities f, frequency of incidents with N or more fatalities

tion Handbook, during the 81 years from 1911–1995 , there were 551 process incidents (Fig. 1).1 By no means is this incident data comprehensive. Additionally, some of the incidents cannot be strictly categorized as process incidents. • Out of the 551 incidents, 270 (49%) had zero fatalities. • One out of every five (19%) of the total incidents resulted in less than four fatalities. A more elegant way to analyze the accident data is to construct a fN curve, where f is the cumulative frequency of incidents leading to N or more fatalities. In this fN curve, the first point represents the 281 incidents that resulted in one or more fatalities. The last point is the Bhopal accident that is estimated to have resulted in 4,000 fatalities. Based on the 20th century fN curve (Fig. 2), we see that in the 1911–1995 timeframe there were 100 process incidents that resulted in 10 or more fatalities—an average of 1.2 incidents/yr in which 10 or more people were killed. There were 14 incidents (2.5%) in which more than 100 people died—an average of 1 incident every six years. There were 3 incidents (0.5%) In which more than 1,000 died—an average of 1 incident per every 28 years.

100

10 Bhopal 0 1

FIG. 2

100 1,000 N, number of fatalities

10,000

Frequency of fatalities in the process industry, 1911–1995.

Incomplete incident database. The accident data in Fig. 2

by no means is comprehensive. For example, in 2008, there were 35 incidents within the manufacturing sector (petroleum, coal products, chemical, plastics and rubber products) in the US alone, according to the Fatal Occupational Injuries Data from Bureau of Labor Statistics. Assuming an average of 35 fatal incidents/yr for US processing plants would imply 3,500 fatal incidents over a period of 100-years. Thus, the total fatal incidents in the fN curve in Fig. 2 are significantly under represented; yet, major incidents with 100+ fatalities are adequately captured. Will there be another Bhopal? Increasing industrial activi-

ties, particularly in countries such as India and China, and proximity of facilities to the neighboring population does present a significant potential for major incidents. Also, there appears to be increased awareness with respect to process safety particularly

in petrochemical/chemical facilities in various countries. The increased reliability of risk mitigation measures that are being applied in the process industry for high-consequence incidents considerably minimizes the occurrence of catastrophe. Industrial insurance providers in various parts of the world will contribute to risk reduction. All of these factors indicate increased risk management practices, and I believe that likelihood of major incidents will reduce in the coming decades...only time will tell. HP Dr. Sanjeev Saraf is a Senior Associate in Exponent’s Engineering Management Practice. Dr. Saraf’s primary focus is on evaluating processes/products foraincreased Tim Lloyd Wright is HP’s European Editor and has been active as reporter safety, reliability, and economic Saraf holds aindustry PhD in chemical engineering and conference chair in the feasibility. EuropeanDr. downstream since 1997, before from A&Ma University, where he reporter worked atfor thethe Mary O’Connorpress Process whichTexas he was feature writer and UKKay broadsheet andSafety BBC Center (MKOPSC). You in can read more process risk management from radio. Mr. Wright lives Sweden andabout is founder of safety a localand climate and sustainability the author on his blog at http://risk-safety.com. initiative.

HYDROCARBON PROCESSING NOVEMBER 2009

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HPI VIEWPOINT ROBERT A. ASHWORTH, GUEST COLUMNIST bobashworth@earthlink.net

Ozone destruction major cause of warming!— Part 2 Warming of the stratosphere is caused by the reaction of ultraviolet light with ozone. However, loss of ozone in the stratosphere will cause it to cool and the earth to warm. The direct effect of ozone concentration on stratospheric temperature is shown in Fig. 1.1 Whenever ozone concentration drops, the temperature drops and vice versa. This effect can be seen from 1995 to 2005 when there were no large volcanic eruptions like that seen with El Chichón and Pinatubo that increased stratospheric temperatures due to release of fine particulate. A NASA team led by Drew Shindell at the Goddard Institute for Space Studies found that ozone destruction was responsible not only for heating the lower atmosphere, but also for cooling the upper atmosphere.2 Considering CFC-11 (trichlorofluoromethane), the predominant CFC reaction in destroying ozone is:

CCl3F + UV-C light+ CCl 2 F + Cl + O3 ClO + O2 A continuous destruction of ozone occurs because the chlorine atoms are not sequestered but get freed up to react with more ozone:

ClO + O Cl + O2 Though the concentration of CFCs in the stratosphere is only around 3 ppbv, one CFC molecule can destroy some 100,000 ozone molecules during its lifetime there. When CFC refrigerants and aerosols were produced and released to the atmosphere in the 1960s, the stratosphere started to cool and the earth started to warm. The Montreal Protocol banned CFCs in developed countries in 1978 and the earth started cooling in 1998.

The lower stratosphere–upper troposphere was 1.37°C cooler in 1998 than it was in 1966. By subtracting the energy in the lower stratosphere–upper troposphere found in 1966 from that found in 1998, the loss in UV light energy absorption was calculated. The amount of stratospheric heating from UV-B light in 1998 was 1.7123 x 1018 Btus less than it was in 1966. The lower troposphere–earth temperature in 1966 was used as a base and the added UV-B light (1.7123 x 1018 Btu) that passed through the lower stratosphere–upper troposphere in 1998 was added to the lower troposphere–earth. That increase was sufficient to heat the lower troposphere and 10 in. of earth (land and sea) by 0.48°C. Conclusion. Many factors can influence the earth’s temperature.

However, the effect of CO2 appears insignificant due to an earth temperature drop of around 0.6°C from 1998 to 2008, when CO2 concentration in the atmosphere increased some 20 ppmv. It should be obvious to anyone who has analyzed climate change that climatedriving forces, other than CO2, control the earth’s temperature. CFCs appear to be the dominant cause of greater than normal earth warming. One can account for most, if not all, of the 0.48°C rise in earth’s temperature from 1966 to 1998 with the additional UV light that hit the earth due to loss of ozone in the stratosphere. CFC destruction of ozone is a simple mechanism that can explain all of the observed earth and atmosphere temperature anomalies seen from 1966 to 1998. HP Note: An expanded version of this article may be found at http://omsriram.com/GlobalWarming.pdf. 1

Proof through mass and energy balance analysis.

The sun’s thermostat modulates in short-term cooling–warming cycles of approximately 11 years.3 The period chosen for analysis to negate this effect was 1966 to 1998. At these two points in time, the solar irradiance reaching the earth was approximately the same (1,368.8 Watts/m2). 500

Total ozone, DU

Temperature

220

450 215 400 El Chichón

350 1980 FIG. 1

1985

210

Ozone Pinatubo 1990 Calendar year

205 1995

2000

Ozone concentration versus stratospheric temperature.

Stratospheric temperature, K

225

LITERATURE CITED United Nations Environmental Programme (UNEP) Vital Ozone Graphics, p. 13, ISBN 978-92-807-2814-9. Shindell, D. T., et. al., “Increased Polar Stratospheric Ozone Losses and Delayed Eventual Recovery Owing to Increasing Greenhouse-gas Concentrations,” Nature 392 589–592, April 9, 1998. Lean, J., “Evolution of the Sun’s Spectral Irradiance Since the Maunder minimum,” Geophysical Research Letters, Vol. 27, No. 16, pp. 2425–2428, Aug. 15, 2000.

The author is a chemical engineering graduate from West Virginia University (BS 1960) and has presented over 50 technical papers on fuels and environmental controls. Relating to the subject of global warming, he has written two papers, “CFC Destruction of Ozone—Major Cause of Recent Global Warming” and “No Evidence to Support Carbon Dioxide Causing Global Warming.” Mr. Ashworth is a member of the American Geophysical Union. He is a dissenter in the US Senate Minority Report: More Than 700 International Scientists Dissent Over Man-Made Global Warming Claims—Scientists Continue to Debunk “Consensus” in 2008 and 2009. Mr. Ashworth was one of 115 scientists who signed the Cato Institute newspaper advertisement to President-Elect Obama’s attention debunking CO2 causing global warming. In his present position as senior vice president—technology for ClearStack Combustion Houston, his fortes design, and Tim LloydCorp., Wright is HP’sTexas, European Editor are and conceptual has been active as amass reporter energy balances and analysis. Mr. Ashworth holdsindustry 16 US patents. ClearStack is and conference chairdata in the European downstream since 1997, before working commercialize two of hisreporter patents, for a three-stage oxidation press technique that which hetowas a feature writer and the UK broadsheet and BBC reduces sulfur dioxide, nitrogen oxides mercury a dry scrubber that removes radio. Mr. Wright lives in Sweden and isand founder of aand local climate and sustainability nitrogen and sulfur oxides from flue gas. In 2001, Governor Paul Patton commisinitiative. sioned him a Kentucky Colonel for his work on clean coal technology. HYDROCARBON PROCESSING NOVEMBER 2009

I 27

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Select 65 at www.HydrocarbonProcessing.com/RS

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

North America BP recently announced that construction, equipment purchases and engineering related to an expansion of its refinery in Whiting, Indiana, is about one-third complete. Construction began in May 2008 and the project is scheduled for completion in early 2012. The budget for the expansion is still targeted to $3.8 billion, with a majority of the allocated money dedicated to helping BP process high-sulfur crudes from the tar sands of Canada.

Central America CB&I has a contract in excess of $100 million with Petroterminal de Panama, S.A. (PTP) to engineer, procure and construct the Phase 2 expansion of the TransPanama pipeline facilities. The work scope includes the design and construction of 5.4 million barrels of crude oil storage and the associated civil, mechanical and electrical work at PTP’s terminal facilities in Chiriqui Grande on Panama’s Atlantic coast and Puerto Armuelles on the Pacific coast. CB&I, which built the original PTP storage tanks in the late 1970s, was awarded the EPC contract for Phase 1 of the expansion project in May 2008.

Europe CB&I has a contract valued in excess of $60 million by Royal Dutch Shell for the engineering, procurement and construction of a diesel hydrotreater at the Pernis refinery in Rotterdam, The Netherlands. The hydrotreater will reduce the sulfur content in the diesel to meet European environmental standards and increase the refinery’s capacity to produce clean diesel fuel. CB&I has received a contract from a Serbian oil refinery worth more than $70 million. The contract from NIS Petroleum Industry to upgrade its Pancevo refinery includes engineering, construction management and associated support and auxiliary work. Lurgi’s hydrogen generation unit for Grupa LOTOS S.A. is ready for startup, according to recent company reports. Grupa LOTOS S.A. incorporated the unit as a strategic decision within the further

development of the refinery in Gdansk, Poland. Following the successful startup of a HDS unit, the refinery’s hydrogen needs increased significantly, so Lurgi delivered, in under 29 months, the new H2 unit. The plant went onstream in the last days of September and it brings a substantial increase in H2 capacity to the site.

Middle East Jacobs Engineering Group Inc. has a contract with Abu Dhabi Polymers Co. (Borouge) to develop front-end engineering and design (FEED) for a section of the “Borouge 3” project, a grassroots polypropylene/polyethylene facility in Abu Dhabi, UAE. Jacobs’ section will involve the compounding, soaking and product handling line. The project’s FEED portion is scheduled to be complete by mid-2010. SNC-Lavalin has a front-end engineering and design (FEED) and project management services contract with Saudi Aramco for the Wasit gas development program. The program will provide for 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.

the production and processing of up to 2.5 billion standard cubic feet per day of gas from the Aribiyah and Hasbah offshore non-associated sour gas fields to meet the future demands of Saudi Arabia. This is a five-year contract. Air Products, working with Samsung Engineering, announced that it has secured a contract for an air separation unit (ASU) to supply National Industrial Gases Co. (NIGC), a subsidiary of Saudi Basic Industries Corp. The ASU will produce 3,550 tpd of oxygen, 3,600 tpd of nitrogen and 150 tpd of argon. It will be located at NIGC’s facility in Al Jubail, Saudi Arabia, and is to be onstream in 2011. Foster Wheeler AG’s Global Engineering and Construction Group has a process design contract with SETE Energy Saudia for Industrial Projects Ltd. (SETE Energy) for the expansion of an industrial wastewater treatment plant in Saudi Arabia. The plant is owned by Power & Water Utility Co. for Jubail & Yanbu (MARAFIQ). MARAFIQ is the authority responsible for providing power generation, water supply and treatment utilities for the industrial complexes of Jubail and Yanbu in Saudi Arabia. SETE Energy is the engineering, procurement and construction contractor for this project. Foster Wheeler will undertake the process design and provide technical assistance during pre-commissioning, commissioning and startup phases.

Asia-Pacific Gujarat State Fertilizers & Chemicals (GSFC) has given Burckhardt Compression an order for a compressor that will be used for oxygen compression in its methanol plant in Baroda, Gujarat, India. Delivery of the compressor will take place at the end of September 2010. The compressor will be installed in the 525-Mtpd methanol plant that is scheduled for startup in March 2011. The process used in the methanol plant was designed by Haldor Topsøe. KBR recently announced the establishment of a KBR office in Gurgaon, India. KBR will offer its process technologies HYDROCARBON PROCESSING NOVEMBER 2009

I 29

HPIN CONSTRUCTION for the refining, petrochemicals, fertilizer, transportation fuels and coal gasification industries from this location. KBR was recently awarded a contract from Hindustan Petroleum Corp. Ltd. (HPCL) to provide licensing and engineering services and proprietary equipment for augmenting the capacity of an existing de-asphalting unit in its Mumbai refinery in India. At this refinery, KBR will also perform a revamp on an existing propane de-asphalting unit

(PDA) using its proprietary technology and internals to achieve the key objective of improving refinery margins. Recon Technology, Ltd., has received over $1 million in new equipment orders from China National Petroleum Corp. (CNPC). Recon received a $981,000 order from the CNPC Qinghai oilfield in China’s Gansu Province. Crude petroleum from this area contains impurities including water and

natural gas that must be removed before the petroleum can be sold. The order includes 11 patented oilfield furnaces that remove these impurities and prevent solidification and blockages in oil pipelines. According to Recon, its furnaces highly operate with 90% heating efficiency. Recon also received a $67,000 order from the CNPC Sebei natural gas field in China’s Gansu Province. This included 7,300-kilogram welding rods and welding wires used for gas transport pipes. Aker Solutions’ contract with Chevron Australia Pty. Ltd. has been extended to include the delivery of a monoethylene glycol system to the Gorgon project located on the Australian northwest shelf. The total contract value for Aker Solutions is approximately NOK300 million. CB&I has a contract valued at approximately $550 million with Chevron Australia Pty. Ltd. for the LNG and condensate storage tanks at the Gorgon LNG liquefaction project on Barrow Island in Australia. CB&I’s scope of work includes the engineering, procurement, fabrication and construction of two 180,000-cubic meter full containment LNG tanks, four condensate tanks and the associated piping, electrical, instrumentation and civil works. CB&I’s portion of the project is scheduled to be completed in the third quarter of 2013. An Air Products joint venture company based in Sichuan, China, has signed an agreement to build an air separation unit (ASU) for PetroChina Co. Ltd. The ASU will supply oxygen and nitrogen to PetroChina’s main refinery and ethylene complex in Sichuan, as well as produce liquid products for Air Products’ merchant gases customers in the Chengdu area. The ASU is to be onstream in late 2011.

Correction In the section of the October issue detailing HPI Construction Boxscore updates (page 29), the engineering company for Staatsolie’s refinery expansion project in Suriname was incorrectly identified. The basic engineering and FEED for this project is being done by CB&I Lummus Netherlands, while Aker Solutions Houston is the PMC tasked with the support of the Staatsolie team, assisting in the management of the EPC tendering process. Detailed Engineering will be performed by an EPC contractor that has yet to be selected. Hydrocarbon Processing regrets the error. HP Select 153 at www.HydrocarbonProcessing.com/RS 30

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HPI CONSTRUCTION BOXSCORE UPDATE Company

Plant Site

Project

Capacity Est. Cost Status Licensor

Jordan Cove Energy Motiva Enterprises LLC

Coos Bay Port Arthur

LNG Terminal Coker

1 Bcf 95 Mbpd

E 2014 U 2011 Shell

Enerkem/Greenfield Ethanol JV Total E&P Canada Ltd

Edmonton Edmonton

Waste to Biofuel Plant Crude Unit

36 MMl/y None

U F 2015

Petroterminal De Panama, S.A. Petroterminal De Panama, S.A.

Chiriqui Grande Puerto Armuelles

Storage, Crude Storage, Crude

2.7 MMbbl 2.7 MMbbl

England Netherlands Netherlands Netherlands Netherlands Poland Portugal

LyondellBasell Industries Shell Royal Dutch Shell Royal Dutch Shell Royal Dutch Shell Royal Dutch Grupa Lotos SA REN-Atlantico

Carrington Pernis Pernis Pernis Pernis Gdansk Sines

Polyethylene, LD Hydrocracker Hydrogen Gasification Hydrotreater, Diesel Polygeneration Hydrogen Terminal, Gas

Russian Federation Russian Federation Russian Federation Russian Federation Russian Federation Russian Federation Serbia Sweden Sweden AB|Total Uzbekistan

Rosneft Rosneft Rosneft Rosneft Rosneft Rosneft NIS a.d. Novi Sad Domsjo Fabriker AB Chemrec AB

Tuapse Tuapse Tuapse Tuapse Tuapse Tuapse Pancevo Domsjo Pitea

generator, gas turbine (1) generator, gas turbine (2) generator, gas turbine (3) generator, gas turbine (4) generator, gas turbine (5) generator, gas turbine (6) Hydrocracker/Hydrotreater Unit Bio-Dimethyl Ether Bio-Dimethyl Ether

MW MW MW MW MW MW None 40 MMgpy 4 tpd

Sasol/Petronas/Uzbekneftegaz

Undisclosed

GTL

1.3 MMtpy

Société Ivoirian Refining Co (SIR)

Abidjan

Gas Emission Reduct. Srvcs

Mina Al Ahmadi Al Jubail Jubail 2 Ind Zone

LNG Regasification Vessel Air Separation Unit (1) Acrylic acid\acrylates

Engineering

Constructor

UNITED STATES Oregon Texas

Black & Veatch

CANADA Alberta Alberta

LATIN AMERICA Panama Panama

100 100

E 2010 E 2010

CB&I CB&I

238

E E E E C E

2012 Shell Global 2012 Shell Global 2013 2012 Shell Global 2009 2012

135 135 135 135 135 135 450 440 20

U U U U U U E F U

2010 2010 2010 2012 2012 2012 2012 CLG 2012 Chemrec AB 2010 Haldor Topsøe|Chemrec AB

EUROPE 185 kty 9 Mtpd 1650 tpd None 117 MW 7 m-t/hr 390 Mm3 47 47 47 47 47 47

CB&I Lurgi Somague Engenharia SA| TGE Gas Engineering GmbH Siemens Energy Siemens Energy Siemens Energy Siemens Energy Rosneft Siemens Energy CB&I

Lurgi

Haldor Topsøe|Preem AB

Haldor Topsøe|Preem

S 2014

AFRICA Ivory Coast

None

S 2009

Axens|Orbeo

C 2009 E 2011 APCI S 2014 Aker Solutions

Excelerate Energy Samsung Eng|APCI Aker Solutions

MIDDLE EAST Kuwait Saudi Arabia Saudi Arabia

KNPC SABIC Dammam 7 Petrochemicals

500 MMcfd 3.5 tpd None

Excelerate Energy

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

Select 154 at www.HydrocarbonProcessing.com/RS

HYDROCARBON PROCESSING NOVEMBER 2009

I 33

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PLANT SAFETY AND ENVIRONMENT

SPECIALREPORT

Prevent storage tank fires Implementing these safety rules can reduce risk R. RITCHIE, SGS North America Inc., Bartlesville, Oklahoma

ost storage tank fires are not on the same scale as the Buncefield Oil Depot accident in Hertfordshire, UK, since they are common occurrences. Although each oil storage facility must be individually evaluated with regard to its overall safety, there are general principles that can be applied to reduce the risk of storage tank fires and mitigate the extent of damage if a fire does occur. In discussing these principles, it must be recognized that risk can be managed to achieve acceptable levels, but it cannot be totally eliminated. Types of storage tanks. Above-ground atmospheric hydrocar-

bon storage tanks come in a wide range of types and sizes, each with its own sets of fire hazards. Generally, these tanks range from 3 m to over 100 m in diameter and they average 16 m high.1 Individually, they are capable of holding up to 1.5 MM barrels of hydrocarbons each. However, a single facility may have over 100 storage tanks. Generally, the tanks are separated from each other by earthen or concrete dikes, or bunds. However, several tanks may be surrounded by a single dike. In this case, the tanks are usually grouped based on similar contents. The dike height walls are generally set so that the dike can contain the entire tank’s contents plus a safety margin. The above-ground storage tanks can be broadly classified into several major categories based on roof design. Design specifications for most large atmospheric above-ground storage tanks are covered by standards from the American Petroleum Institute (API) and the British Standards Institute.2,3 Fixed-roof tanks. Fixed-roof tanks have a roof permanently attached to the tank’s vertical side walls. The roof may be cone shaped, domed or relatively flat, and it may or may not have prominent ribs. Regardless of shape, the roof side-wall weld is left intentionally weak so that if an incident occurs, the tank roof will separate from the tank rather than the floor or side-wall joints rupturing. This allows the tank to retain its contents. These tanks are usually vented to allow for expansion and contraction as a result of loading, unloading and temperature or pressure changes. Floating-roof tanks. Floating-roof tanks have a layer of steel, aluminum, or plastic, that floats directly on the tank’s liquid contents, or floats just above the contents using pontoons. These roofs rise and fall with the tank’s liquid level. Floating-roof tanks have seals between the side walls of the tank and the roof. These seals serve to reduce evaporation of the tank’s contents. According to API 2021, “tank designers consider the floating roof to be the single most important design variable affecting the potential for, and severity of, a tank fire.”4 As long as the floating roof remains buoyant, the roof limits the evaporation of the tank contents, and limits the potential for fire to the gap between the

INCIDENT AT BUNCEFIELD OIL DEPOT

On Sunday, December 11, 2005, a filling gauge on tank 912 at the Buncefield Oil Depot in Hertfordshire, UK, got struck by lightning. The safety system, which should have automatically stopped the flow of unleaded gasoline into the tank, failed. Approximately 300 tons of gasoline poured over the tank sides and began to fill the containment dike. Eventually, the vapor cloud above the gasoline flowed over the dike and spread out through the facility and beyond its perimeter. At 6:01 a.m. there was an explosion. It appeared to have been centered in the car parking lot to the west of the facility.5 This and the subsequent explosions were the largest explosions in the UK since the end of WW II. The smoke cloud was so large it could be seen from space. It took five days for the last fire to be finally extinguished. A total of 23 storage tanks had been involved in the fire and the majority of the terminal was destroyed. British government investigations and recommendations documented significant effects from the incident and they concluded that:5–8 • Forty-three people were injured with no fatalities. • Homes and businesses as far as five miles away were damaged or destroyed. • There was a temporary evacuation of over 2,000 people. • Fuel delivery to Heathrow Airport was impacted. • Economic cost from the incident was estimated at 894 million British pounds. • Criminal proceedings were commenced against five defendants, relating to the causes of the fires and the environmental impact. floating roof and the tank shell. Generally, this is 2% of the tank surface. This is further reduced by the presence of a seal between the floating roof and the tank shell. Floating-roof tanks can be further classified based on whether there is an additional roof to protect the floating roof from exposure to wind and rain. These may be classified as: • Open-top external floating-roof tanks. In these tanks, the floating roof is directly exposed to the elements. The tanks are often referred to as “open floaters,” and are often used to store crude oil. Generally, there are no vents visible on the tank’s side walls. • Covered internal floating-roof tanks. In these tanks, there is a fixed roof above the floating roof that protects the floating roof from exposure to the elements. The tanks have vents to allow the space between the floating and fixed roofs to “breathe,” as well as overfill ports that prevent the liquid level to exceed the tank’s capacity. The tanks are usually used for the storage of highly flammable materials such as gasoline. HYDROCARBON PROCESSING NOVEMBER 2009

I 35

PLANT SAFETY AND ENVIRONMENT

Rim-seal ﬁre

Obstructed full surface ﬁre

are hundreds of above-ground atmospheric pressure hydrocarbon storage tank fires every year.9 Table 1 shows the primary fire hazards associated with each standard tank type.1

Vent ﬁre

Storage tank fire causes and prevention. There

Overﬁll ﬁre

• Domed external floating TABLE 1. Common tank-type fire hazards roof tanks. These tanks are essentially external floating roof tanks where a domed roof has been retrofitted to provide weather protection to the external roof. Tank type They are typically used to store finished or refined products. Floating roof Internal

Yes

External

Yes

Domed

Yes

Fixed roof

Yes

Overfill fires. Overfill fires occur on the ground in the dike around the tank as a result of piping or tank leakage. All above ground storage tanks are subject to these types of fires. The majority of these fires are caused by equipment malfunction or operator error, or both. This leads to the tank and spillage of the hydrocarbon into the diked area. The Buncefield fire was this type of fire. If the overfill is detected, igni-

tion sources should be isolated to prevent the fire. In the Buncefield situation, the overfilling continued for 40 mins before ignition occurred.5 Vent fires. Vent fires occur as a result of

ignition of the plume from hydrocarbon gases exiting tank vents, typically during tank filling. These fires are usually caused by lightning. However, electrical arcing, static discharge and human activities around the tank can all cause ignition of a flammable

Select 155 at www.HydrocarbonProcessing.com/RS 36

mixture. Investigation of a 2003 tank fire in Glenpool, Oklahoma, found that a static charge was generated as a result of the operator using flowrates that were too high for the transfer operation.10 The subsequent static discharge ignited the vapors being vented from beneath the floating roof into the No space between the internal floatYes ing roof and the fixed roof of the tanks. API RP 2003 identifies the No proper flowrates and conditions to Yes prevent static discharge in storage tanks.11 Vent fires can occur in all tank types except external floatingroof tanks, which do not have vents.

Unobstructed full surface ﬁre

SPECIALREPORT

Rim-seal fires. Rim-seal fires are the most common type of fire for floatingroof tanks, especially external floating-roof tanks.9 It is estimated that 95% of rim seal fires are the result of lightning strikes and 0.16% of all tanks with rim seals will experience a rim-seal fire in any given year.12 Fig. 1 shows the global distribution of lightning strikes based on satellite monitoring. 13 This shows that all regions of the world are subject to lightning strikes, although Europe and northern Asia have a lower probability of strikes. To comply with NFPA 780, operators install roof shunts to dissipate lightning energy to prevent fires.14 However, tests for the API RP 545 task group have shown that, rather than reducing the fire risk from lightning strikes, they may actually be increasing the risk. 9,12 Tests have shown that both above-roof and submerged shunts can produce arcing at the shunt-shell interface under all lightning conditions.4 Shunts above the roof produce a greater risk because the arcing occurs where there may be a flammable vapor-air mixture. Recent studies indicate that the risk of rim-seal fires can be reduced by ensuring that: • Tight-fitting primary and secondary seals are in place and are effectively preventing vapors escaping from the tank12 • Submerged grounding cables are installed that directly connect the tank roof and shell. This is shown to be more effective than roof shunts, which, due to wall coating, corrosion or an out-of-round shell, may not effectively connect the roof to the shell.9 The API RP 545 task group is planning additional studies to evaluate alternative methods of connecting the tank roof to the wall.9

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SPECIALREPORT

FIG. 1

PLANT SAFETY AND ENVIRONMENT

Global distribution of lightning April 1995–February 2003.

Monitoring systems and firefighting systems are typically installed around the tank rim to detect rim fires and allow for rapid response. These must be regularly inspected to ensure that they are in good working order to prevent small rim-seal fires from escalating.

■ While it is impossible to eliminate

the risk of storage tank fires, the risk can be substantially reduced by ensuring that proper design, operation and maintenance guidelines are in place and are followed.

Full-surface fires. Full-surface

fires occur when the entire liquid surface in the tank is on fire. They can be further divided into obstructed full-surface fires and unobstructed full-surface fires. Obstructed full-surface fires are those where access to a portion of the burning surface is blocked by the roof or pan, and happen when the roof or pan sinks. Roof sinking occurs due to a variety of reasons, such as: • Rain buildup on the roof, where there is inadequate drainage either from plugging of the drains or the rain amount received exceeds the design standards for the tank • In pontoon roofs, where the pontoons have become filled with the tank liquid as a result of corrosion or other failure • Improper application of firefighting materials during a rim-seal fire, causing the roof to sink. Drain plugging and pontoon failure can be identified as part of the regular inspection programs prescribed for storage tanks in API 653. These components must be maintained in excellent condition to pre38

I NOVEMBER 2009 HYDROCARBON PROCESSING

vent tank fires.14 Unobstructed full-surface fires occur when there is ready access to the entire tank surface. For tanks 45 m or smaller in diameter, these are generally readily extinguished as long as there are sufficient resources (water, foam, etc.) and personnel available. In tanks greater than 45 m, the fires are generally very difficult to fight due to the large amount of resources required to extinguish such a large tank. These fires usually occur in fixed-roof tanks without internal roofs, where, as a result of an incident, the weak roof-shell weld is broken and the roof is lifted off the tank. These fires may also occur in external floatingroof tanks, where heavy rains may exceed the design capacity for water removal from the roof. The largest successfully extinguished full surface tank fire occurred on June 8, 2001 in Norco, Louisiana. A tank 82 m in diameter and 10 m high with a 325,000 barrel capacity was struck by lightning associated with Tropical Storm Allison.15 The tank was extinguished in

65 mins of suppression activity at the end of 13 hr. The total amount of water used was 50% greater than the total amount of water available at the Buncefield site. Fire risk reduction. While it is

impossible to eliminate the risk of storage tank fires, the risk can be substantially reduced by ensuring that proper design, operation and maintenance guidelines are in place and are followed. Completing proper inspections according to the API 653 standard is essential in identifying design and maintenance issues with existing storage tanks. There are three types of inspections detailed in API 653 and they are: Monthly routine in-service inspections. These include a visual inspection

of the tanks, exterior surfaces looking for evidence of leaks, shell distortions, settlement, corrosion, foundation condition, paint coating, insulation systems and appurtenances. Formal in-service external inspections. These must be done every five

years or sooner if the remaining corrosion allowance for the tank is less than 20 years. In the latter case, the inspection must be done at the interval that is one quarter of the remaining estimated tank life. The areas inspected include the dike, foundation,

PLANTY SAFETY AND ENVIRONMENT shell, shell appurtenances, access structure, wind girder, roof, internal floating deck, fire protection system and the tank mixer. Out-of-service internal inspections. These must be done a minimum

of every 20 years unless a risk-based inspection system is in place, or at one quarter of their calculated remaining life. If they do not have an established corrosion rate, they must be inspected within 10 years. To perform these inspections, the tanks must be emptied and cleaned. In addition to visual inspection, a combination of leak testing, magnetic flux, and ultrasonic thickness testing are employed. The primary purpose of the inspection is to assure continued tank integrity by verifying that the bottom is not severely corroded, gather the data for minimum bottom and shell thickness assessments, and identify and evaluate any tank bottom settlement. Furthermore, the interior shell walls and the roof are inspected for general corrosion and localized pitting. If the tank has pontoons, these are inspected to evaluate them for fracture and corrosion that could lead to their failure. In addition to these inspections, it is essential that proper procedures are in place within a storage facility, and that they are followed. In the Glenpool tank explosion, the written operating procedures, if followed, would probably have prevented the tank fire. However, the incident that led to the fire didn’t follow the operator’s procedures or the recommended industry practices. API RP 2021 identifies a number of other publications that can assist in the design, operation, maintenance and inspection of storage tanks to prevent storagetank fires:4 • Control of spills and protecting against overfill (API RP 2350) • Environmental ignition factors such as lightning, especially relevant to open floating-roof storage tank seal fires (API RP 2003 and NFPA 780) • Proper arrangement and spacing of tanks (NFPA 30) • Providing fire, control and extinguishment equipment and systems (API RP 2001 and NFPA 11) to help prevent small fires from escalating • Safe cleaning of storage tanks (API Standard 2015 and RP 2016). All these standards and reference materials are meant to support the efforts of operators and personnel in the safe operation of storage tanks. However, they are not a substitute for informed and diligent safe operation by personnel who are properly trained. HP

LITERATURE CITED Shelley, C. H., A. R. Cole and T. E. Markley, Industrial Firefighting for Industrial Firefighters, PennWell Corp, Tulsa, Oklahoma, pp. 294–298, 2007. 2 “Welded steel tanks for oil storage,” API 650, Tenth Edition, American Petroleum Institute, 1998. 3 “Specification for the design and manufacture of site-built, vertical, cylindrical, flat-bottomed, above-ground, welded, steel tanks for the storage of liquids at ambient temperature and above,” BS EN 14015, British Standards Institution, 2004. 4 “Management of Atmospheric Storage Tank Fires,” API Recommended Practice 2021, Fourth Edition, American Petroleum Institute, May 2001. 5 “The final report of the Major Incident Investigation Board,” Buncefield Major Incident Investigation Board, Vol. 1, The Office of Public Sector Information, Information Policy Team, Kew, Richmond, Surrey UK, 2008. 6 “Recommendations on the emergency preparedness for, response to and recovery from incidents,” Buncefield Major Incident Investigation Board, Vol. 2, The Office of Public Sector Information, Information Policy Team, Kew, Richmond, Surrey UK, 2007. 7 “Recommendations on land use planning and the control of societal risk around major hazard sites,” Buncefield Major Incident Investigation Board, The Office of Public Sector Information, Information Policy Team, Kew, Richmond, Surrey UK, 2008 8 “Recmmendations on the design and operation of fuel storage sites,” Buncefield Major Incident Investigation Board, www.buncefieldinvestigation.gov.uk/reports/index.htm, 2007. 9 “Lightning Protection: Floating-Roof Tank Shunts,” Industrial Fire World, Vol. 21, No. 6, www.fireworld.com/ifw_articles/lightning.php, 2006. 10 “Storage Tank Explosion and Fire in Glenpool, Oklahoma, April 7, 2003, Pipeline Accident Report, NTSB/PAR-04.02,” National Transportation Safety Board, Washington, DC. 11 “Protection Against Ignition Arising Out of Static, Lightning and Stray Currents,” API RP, American Petroleum Institute, 2003. 12 Breitweiser, C., “AST Lightning Protection—API 545 Update,” American Petroleum Institute Tank Conference Proceedings, 2008. 13 “NFPA 780: Standard for the Installation of Lightning Protection Systems,” National Fire Protection Association, 2004. 14 “Tank Inspection, Repair, Alteration and Reconstruction,” Includes Addendum 1 (2003), Addendum 2 (2005), Addendum 3 (2008) and Errata (2008), Third Edition, American Petroleum Institute. 15 Crawford, K. E., “Tank Fire Suppression/Tank Overfill Prevention,” American Petroleum Institute Storage Tank Conference, September 2008. 1

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Richard Ritchie is the director of global programs for asset integrity management in the SGS AIM Competence Center. He has 19 years experience in the specialty chemical, and inspection and testing industry. Mr. Ritchie received a BS and an MS degree in mechanical engineering from Virginia Tech and MIT respectively. Select 156 at www.HydrocarbonProcessing.com/RS

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Avoid confusion when performing safety integrity levels Here’s how to differentiate safety instrumented fuction demand modes Y. A. KHALIL, Zakum Development Company, Abu Dhabi and H. CHEDDIE, Cteris Consulting Inc., Ontario, Canada

IEC 61508-4, is where the frequency of demands for operation afety integrity levels (SIL) are allocated to safety instrumade on a safety-related system is no greater than one per year mented functions (SIFs) to establish how the said functions and no greater than twice the proof test frequency. Otherwise, it have to be realized, operated, maintained and modified. It is is considered to be operating in the high or continuous demand a lifecycle parameter. Two modes of operation have been defined mode. In other words, in the high or continuous demand mode, for SIFs, i.e., low demand mode of operation and high demand demands are placed on the SIF much more frequently than in the or continuous mode of operation. low demand mode. In the low demand mode each SIL relates to an average probability of failure on demand (PFDavg) range, while in the high or Avoid confusion while performing a SIL for various the continuous demand mode a SIL relates to the probability of demand modes. After discussions with a number of engineers dangerous failure per hour (PFH) range. The relation between a in the field of process industries, they revealed that there is a bit of SIL and PFDavg and their correspondent risk reduction factor is confusion among them in assigning SIL for SIFs operating in high displayed in Table 1 for low demand mode. The relation between or continuous demand mode. Some are dealing with these SIFs as a SIL and PFH is displayed in Table 2 for high or continuous if they were operating in low demand demand mode. mode and others don’t give them any For a safety function operating in weight in preventing the occurrence of low demand mode and when a hazardthe hazardous event. ous event or incident occurs, a demand ■ Errors can arise when using In low demand mode, SIL is deterhas to be placed on the SIF and the SIF low demand SIL selection mined by calculating the amount of has to fail to respond satisfactorily. risk reduction the SIF has to provide to • Hazard rate (h) = demand rate techniques such as LOPA, Risk achieve the tolerable risk criteria. But, (d) x average probability of failure on in the high or continuous demand demand (PFDavg) of SIF. matrix or Risk Graph for SIFs mode, the overall dangerous undeFor a safety function operating in tected failures rate ␭DU of the SIF must high or continuous demand mode, a operating in high demand mode. hazardous event or incident will occur be less than or equal to the associated whenever the safety related control tolerable frequency. system fails. The following example has been specifically modified and • Hazard rate (h) = probability of a dangerous failure per hour simplified to emphasize the differences and shows how to assign a of SIF SIL for SIFs operating in high or continuous demand mode. The formulas assume no other safeguards exist. Problem: A pressure transmitter (PT) is located on an air receiver Here’s how to distinguish between various modes vessel (shown in Fig.1) and is used to activate the load/unload control of operation. Low demand mode, as defined in 3.5.12 of mechanism (blow-off valve) of an instrument air centrifugal compresTABLE 1. Safety integrity levels for low demand mode of operation

TABLE 2. Safety integrity levels for high or continuous demand mode of operation

SIL

PFDavg

RRF

SIL

PFH

≥10–5 to < 10–4

>10,000 to ≤100,000

≥10–9 to < 10–8

≥10–4 to < 10–3

>1,000 to ≤ 10,000

≥10–8 to < 10–7

≥10–3 to < 10–2

>100 to ≤ 1,000

≥10–7 to < 10–6

≥10–2

>10 to ≤ 100

≥10–6 to < 10–5

to <

10–1

HYDROCARBON PROCESSING NOVEMBER 2009

I 41

SPECIALREPORT

PLANT SAFETY AND ENVIRONMENT

TABLE 3. Layer of Protection Analysis assigning a SIL level Most credible consequences:

Compressor surge and damage due to high pressure

Tolerance frequency goal:

1.00E–03 per year

SIF being reviewed

Pressure transmitter (PT) located on an air receiver vessel used to activate the load/unload control mechanism (blow-off valve) Likelihood of each cause/yr

IPL #1 vibration system

IPL PSV

Unmitigated vent frequency

Blockage downstream piping or system

0.01

0.03

3.00E–04

PCV fail close

0.02

0.03

6.00E-04

High pressure in the receiver vessel due to varying air consumption rates

3,000

0.03

9.00E+01

Cause(s) of initiating event

Total unmitigated event frequency due to all causes: (Ftotal unmitigated frequency )

9.00E+01 PFDavg RRF SIL

sor with 3,000 on/off operations/yr and with no automatic diagnostic of failures. Compressor surge and damage due to high pressure is the worst case scenario if the PT failed to unload the compressor. A hazard assessment team estimated a major consequence with an associated maximum target frequency of 1 x 10–3/yr. The layers of protection that can prevent the occurrence of this accident are:

Elemental Analysis of Fuels

Determination of Sulfur and other elements at-line and in the laboratory 42

I NOVEMBER 2009 HYDROCARBON PROCESSING

Vibration system (XE/XT) PFD Pressure safety/relief valve (PSV) PFD

1.111E–05 90,000.9 4

=1 = 0.03

Note: The team estimated that the vibration system as well as

the MCC protections were not fast enough to protect against this incident.

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SPECIALREPORT

Air intake ﬁlter

ATM

PLANT SAFETY AND ENVIRONMENT

Plant shutdown ATM

Load/unload PSV

Trip

Vibration monitoring system

FIG. 1

XT XE

PSLL To instrument

air distribution network

Alarm Local control panel (LCP) Blow-off valve

Trip PT PSHH

Air dryer

Cooler

PCV Air receiver

Scrubber

Compressor package diagram.

protection layers must be less than or equal to the target frequency. Thus, FPT (dangerous failures rate of SIFPT) x PFD XE/XT (1) x PFD PSV (0.03) must be less than the Ftolerable (1 x 10–3 /yr) Therefore, the dangerous failures rate of the SIFPT (␭D) must be less than or equal to 1 x 10–3/3 x 10–2 = 3.33333 x 10–2 failures or 3.8 x 10–6 failures/hr. The team performed continuous mode SIL assignment according to Table 2. The dangerous failures rate of 3.8 x 10–6/hr falls in between 10–5 and 10–6, so the SIL associated with the calculated failure is SIL 1. Therefore, this SIF (SIF PT) should be designed with overall dangerous failures (␭D(PT) + ␭D(LCP) + ␭D(blow-off valve) ) less than 3.8 x 10–6 failures/hr.

Methodology No.1. The SIL assessment team applied the

Conclusion. Errors that can arise when using low demand SIL

Layer of Protection Analysis (LOPA) technique to assign the SIL level for the SIFPT , as follows: It became obvious to the team that the SIFPT operated in a high demand mode; hence the results using the LOPA methodology were unacceptable.

selection techniques such as LOPA, Risk Matrix or Risk Graph for SIF operating in high demand mode could be in the magnitude category of the required Risk Reduction Factor. Clearly, Methodology 2 is the correct approach for SIFs operating in high or continuous demand mode. In the previous example, there was another protection layer (PSV) that contributed in preventing the occurrence of the incident, but, in many other cases the availability of other protection layers may not exist. In this case, the dangerous failure of the SIF leads to an immediate incident. Designers should ensure that the overall undetected dangerous failures rate of the SIF (␭DU) is less than or equal to the associated maximum target frequency (FTolerable). In the process industry it is normally assumed (incorrectly) that all SIFs operate in a low demand mode. This assumption can and will lead to errors in the SIL determination and SIL verification since the mode of operation affects both the SIL determination and SIL verification methodology. HP

Methodology 2. The team realized that the PT is the SIF

operating in continuous demand mode; and recognized that it’s dangerous failures rate multiplied by the PFD values of all other

Yasser Ali Khalil is senior instrument and control engineer at Zakum Development Company (ZADCO) based in Abu Dhabi. He has over 20 years of experience in the oil and gas industries in the fields of engineering design, commissioning and operation support. Mr. Yasser has worked with internationally reputed engineering and operating companies on petrochemicals, oil and gas projects. In 2002 he joined ZADCO which operates one of the largest offshore oil fields in the world. Mr. Yasser specializes in instrumentation, safety and control systems engineering related to oil and gas processing plants. He holds a BSc degree in electrical (computer and automatic control) engineering from Ain-Shams University, Cairo, Egypt. Mr. Khalil is also a CFSE and TÜV Certified Functional Safety Expert, and was a member of ZADCO who received the runner-up ADNOC HSE award, for safety in 2004.

Harry Cheddie P.Eng., CRE, CFSE is director of engineering for Cteris Consulting Inc. located in Ontario, Canada. He is presently responsible for completing reliability, HAZOP and safety studies for end users, developing training programs, and teaching safety courses with an emphasis on IEC 61508 and IEC 61511.Mr. Cheddie graduated from Salford University in the UK with a BSc degree in electrical engineering. He is a registered Professional Engineer in the province of Ontario, Canada. Mr. Cheddie is certified by the American Society for Quality as a Quality Engineer and as a Reliability Engineer. He is also a TÜV Certified Functional Safety Expert. Select 158 at www.HydrocarbonProcessing.com/RS 44

PLANT SAFETY AND ENVIRONMENT

SPECIALREPORT

Software tools are never a substitute for competency Sound practice, experienced-based judgment and teamwork are still needed for safety engineering success S. KOZMA, exida Canada Ltd., Calgary, Alberta

e’ve witnessed it; we’ve probably even experienced it. The “it” is the amazing effectiveness that safety life cycle software tools produce in the hands of competent users. As a result, there is a growing list of such tools on the market specifically designed to help ensure that potential hazards, safety instrumented functions (SIFs) and safety instrumented systems (SISs) are identified, assessed, designed, tested, installed, and operated in accordance with regulatory requirements and international safety standards. Unfortunately we’ve also likely witnessed and/or experienced the other extreme; poor results that exactly the same software tools may produce if used by someone who has the software user’s manual lying in their lap. So don’t think for a minute that automated software tools are a substitute for having a competent set of eyes to review both the software’s input and its corresponding output.

when, what to document, and how to best document it. This higher level of competency provides the necessary understanding of the software’s results, and more importantly, it helps to determine if the results are actually correct and useful. This is especially important in the critical front end analysis activities leading up to equipment specification since these activities are shown to cause the greatest fraction of major industrial accidents. So, before giving into temptations such as using a software tool to automatically extract the results of a process hazard analysis (PHA) to determine safety integrity level (SIL) target values, first consider the processes and overall competencies required to properly execute these critical front end tasks.

PHA competency. PHA studies employ proven risk-management principals to help form the foundation on which to construct safe and effective processes. Frequently used PHA techOverall competency. Scattered throughout internationally niques include: accepted safety standards International • Checklist analysis Electrotechnical Commission (IEC) • DiGraph analysis ■ HAZOP studies are based on 61508 and IEC 61511 is language • Failure modes and effects analysis emphasizing the importance of using the principle that a team approach (FMEA) competent persons to properly assess, • Fault tree analysis design and periodically verify that the to hazard analysis will identify • H A Za rd a n d O Pe r a b i l i t y safety system continues to meet its (HAZOP) studies more problems than individuals design criteria throughout its life. • Safety system checklists IEC 61508, Part 1, Paragraph working independently with • What-if studies. 6.2.1 (h) states, “...ensuring that The most notable of these is the applicable parties involved in any of combined results. HAZOP study. A common misconthe overall E/E/PE or software safety ception is that HAZOP studies focus life cycle activities are competent to carry out activities for which specifically on safety and environmental concerns. The reality is they are accountable.” that 50–60% of recommendations resulting from a HAZOP study IEC 61511 (ISA S84-2004), Part 1, Paragraph 5.2.2.2 states, focus on issues related to product quality and process operability. “Persons, departments or organizations involved in safety life cycle HAZOP studies are based on the principle that a team activities shall be competent to carry out the activities for which approach to hazard analysis will identify more problems than they are accountable.” individuals working independently with combined results. The Upon reading these statements, each seems sound enough team approach prevents decisions from one discipline having but the more you learn about IEC safety standards, the more you a potentially adverse effect on a process or piece of equipment realize those statements are woefully insufficient to fully specify (e.g., an instrument engineer wanting to raise a trip set point the competencies necessary to produce an effective SIS solution. may not know the resulting effect on the overall design). This Certainly the growing number of safety life cycle software tools direct teamwork also promotes rapid and effective brainstorming helps ensure that the math is done correctly and consistently and to ensure that a wide breadth of possible scenarios is considered that transcription errors are reduced. However, overall safety life from a wide range of perspectives in a way that isolated individuals cycle competency is required to know which math to do and simply cannot match. HYDROCARBON PROCESSING NOVEMBER 2009

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SPECIALREPORT

PLANT SAFETY AND ENVIRONMENT

The HAZOP team typically consists of “senior” representatives from process engineering including chemists, operations, instrumentation and controls, mechanical maintenance, health and safety, and other assorted technical specialists. Led by seasoned HAZOP facilitators, HAZOP teams typically meet in 3–6 hour sessions over several days or weeks, systematically examining the process under study, one node at a time. The team examines the process parameters (flow, temperature, pressure, level, etc.) of each node by applying pre-defined guidewords such as “no/low” or “more/high” with the parameter “flow” to produce a “no flow” deviation condition. The team will discuss the potential consequence of the “no flow” condition for the node under study. Depending on team makeup, authority and time constraints, the team may also categorize (rank) each identified initiating cause according to the owner/operator’s pre-defined risk management guidelines. HAZOP teams will frequently record possible safeguards and corrective actions with the understanding that these, along with other possible safeguards, will be evaluated at a later time by persons other than the HAZOP team. Thus, the value delivered by a good team based HAZOP can be significant. The results produced by such a HAZOP study typically include: • Identification of possible deviation states • Identification of the possible causes for deviations • Probable worst-case consequence • Documentation of existing and possible safeguards • Action(s) required to reduce risk • Assignment of follow-up actions to an individual or group. HAZOP study teams do identify environmental and safety risks but most of a team’s focus is on identifying ways to improve product quality and overall process operability. In fact, it’s not uncommon for the HAZOP facilitator to periodically remind the team that he or she is there to identify issues, not to engineer a final fix. Similarly, environmental and safety (and often asset or commercial) related issues often end up requiring additional analysis delegated to ensure the proposed preventive and/or mitigating safeguards are adequate. A competent facilitator will strike the best balance of identifying, engineering and delegating while automated software will simply allow a poor facilitator to look good on the surface and hide the problems, which may grow and fester until they are inevitably found later. SIL determination competency. The next critical front end safety life cycle activity builds directly on the results of the

FIG. 1

Independent layers of protection—typical.

I NOVEMBER 2009 HYDROCARBON PROCESSING

PHA. SIL target determination is the first step in the design, specification, installation and operation of any SIS that may be needed to manage the risk identified in the PHA. SIL determination or SIL target selection is the process of determining the mitigation amount required to reduce each identified risk to a tolerable level. IEC safety standards suggest a number of SIL determination techniques, but most safety system experts endorse the Layers of Protection Analysis (LOPA) approach (see Fig. 1). LOPA has repeatedly proven to be an effective and powerful method for assessing the adequacy of Independent Protection Layers (IPLs) such as: • Alarms with defined operator response • Basic process control systems • Blast walls and dikes • Deluge systems • Fire and gas systems • Pressure relief devices • SISs • Standard operating procedures. LOPA is not just another hazard or risk assessment idea; it is a detailed engineering tool that builds upon the foundation established during the PHA. Using initiating event frequencies and IPL effectiveness estimates, known as Probability of Failure on Demand (PFD), LOPA evaluates the risk of each scenario under consideration. The major actions and documentation required to complete the LOPA are: • Clearly identify all reference documentation (i.e., PHA, rupture disk and relief valve designs and inspection reports, etc.) including dates and revision numbers. • Clearly document the links between specific process deviations (i.e., node-by-node evaluations conducted during the HAZOP study) and hazard scenarios. • Use regulatory- and industry-accepted data to establish acceptable and traceable frequency and failure rate for each device, system and/or person included in the mitigating solution. • Use federally, locally and industrially-accepted data to determine the likely environmental and safety consequences of each hazardous scenario. • Use company-accepted data to determine the likely economic impact of each hazardous scenario. • Identify each IPL capable of preventing and/or mitigating each initiating cause. • Ensure that each IPL under consideration is independent, specific, dependable and auditable. • Assemble as many recommendations as possible, each with reasonably detailed implementation documentation. That last bullet surprises many people, but a LOPA analysis does not always develop “the” mitigation answer to each identified risk. Instead LOPA semi-quantifies multiple possibilities so that the project team can make informed decisions. The key benefits for using LOPA over other SIL determination methodologies are that it can: • Expose additional risks not revealed by other methodologies • Provide an effective, numerical means of resolving disagreements about “the” best solution • Help identify acceptable and less costly risk–mitigation alternatives, such as procedural changes or adding additional protection layers • Provide a clear link between identified hazards and mitigation actions.

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Blindly following an automated software menu without the detailed understanding of the technique on its own puts all of these benefits at risk and more importantly it puts the entire plant staff at an even greater risk. Similarly using such software automation to fully combine the HAZOP and LOPA activities into a single one is also filled with potential problems. Instead of speeding things up, it actually can have the opposite effect of over burdening the team and causing errors which take much more time and effort to fix later, or worse, end up getting designed into the plant. Integration competency. The international acceptance of IEC safety standards has produced a growing number of software tools. Some of these software tools have been “certified” by independent third-parties. This means that the software has been tested and verified to accurately perform the calculations the manufacturer says it will do. In the hands of competent individuals, each of these software tools can improve efficiency and eliminate “silly” calculation and transcription errors between project elements. But, the secret is knowing when and how to use these software tools and how to best integrate them into the overall engineering process. Simply understanding probability mathematics does not demonstrate the competency level required to perform LOPA. Simply being able to read through a list of parameters and guide words does not make a HAZOP. And, simply bolting two techniques together does not make an effective engineering process. As one can see, a significant amount of knowledge must go into each equation element and how the equations are linked together.

I NOVEMBER 2009 HYDROCARBON PROCESSING

Before buying into the notion of using a software tool to extract the results of a PHA to “automatically” calculate the SIL target value, competently consider: • A list of environmental and safety risks that the PHA team produced • The competencies of the persons that participated in the PHA. 1. Are you confident that the list identifies ALL the possible mitigation possibilities? 2. Did the makeup of the PHA team have all the right credentials to evaluate every possible risk? 3. Did the PHA facilitator allow sufficient time to develop multiple mitigation possibilities for each risk? If you’ve answered no to even one of these three questions, then the competency level acquired proves that you are not ready to proceed with a SIL determination tool. HP

Sam Kozma is the managing partner for exida Canada Ltd. in Calgary, Alberta, and is responsible for process safety and safety instrumented design and verification projects. Mr. Kozma has a diploma in electrical engineering technology from the Southern Alberta Institute of Technology. Before joining exida, Mr. Kozma owned a safety services company. He has more than 20 years of safety services experience including a variety of processes with a special emphasis in the Western Canadian oil & gas sector. Mr. Kozma is a Certified Functional Safety Expert and is actively engaged in several Canadian functional safety committees.

Select 159 at www.HydrocarbonProcessing.com/RS

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Requirement engineering and management—Part 1—safety critical elements identification Use these guidelines to determine the safety-critical elements and tasks. F.-F. SALIMI, ADEPP Academy, France

hen a project is susceptible to the risk of major accident hazards, modern industrial regulations call for a rigorous approach to determine the safety-critical systems (SCSs), subsystems, elements and related tasks. The requirements for the SCSs, subsystems, elements and tasks shall be engineered and managed during the project life cycle. Defining the exact expectations of project management toward the numerous contractors and subcontractors that are located at the physically remote locations is one of the most challenging tasks of modern project managers. Any miscommunication or missing information/requirement could cause high costs and significant project delays. Part 1 of this article explains explains how the prescriptive approaches like API 14C and API 581 can be used in combination with risk-based approaches such as the safety integrity level (SIL) assessment described in IEC61508 and IEC61511 to determine the safety-critical elements (SCEs) and tasks. Part 2 of this article describes how SCSs and their performance standards can be managed by available online tools such as the ADEPP monitor. The ADEPP monitor is an online secure tool and offers a robust, efficient and user-friendly tool to engineer and manage performance standards of the SCSs, subsystems, elements and tasks. This approach has been applied by the author and her collaborators since 1996 for various major oil and gas projects.1,2 Introduction. Any hazardous industrial project consists of a

large number of SCSs, subsystems, elements and related tasks. They shall be determined and managed with a systematic approach. Most hazardous projects are realized by the contractors located in physically remote offices. Sometimes the applicable codes and standards, regulations, risk criteria and the methodology for determining SCEs are different. The inconsistency between the assumptions and perceptions about the methods and approaches could lead to inconsistent performance standards and expensive communication and correction efforts. To overcome the complex project configuration, management should establish a reliable, secure online system to:

• Define clearly and exactly the project expectations in concise, comprehensive, traceable and auditable performance standards at least for all the SCSs, subsystems, elements and related tasks. This is called “requirement engineering.” • Monitor and audit if these performance standards are applied properly throughout the project. This is called “requirement management.” With a reliable secure online system, the project can easily communicate and follow-up the performance standards to the project team wherever they work at the right time. The efficient and cost-effective Web meetings could be organized to involve all parties to quickly review and approve the updated performance standards and assigned tasks. This article explains the approach and method used by the ADEPP monitor to: • Identify the SCSs, subsystems, elements and related tasks • Produce the performance standards for them

Leadership and commitment Policy and strategic objectives

Audit and SCORE assessment by ADEPP

Organization and resources

Evaluation and risk management

Supervisory corrective action

Planning, standards and procedures

Implementation

and

Management corrective action

ADEPP monitor

Management review Continuous improvement

FIG. 1

SCORE assessment by the ADEPP monitor and the HSEMS model. HYDROCARBON PROCESSING NOVEMBER 2009

I 49

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KTI Corporation 1990 Post Oak Blvd., Suite 1000, Houston, TX 77056 Tel: (281) 249-2400 Fax: (281) 249-2328 E-mail: sales@kticorp.com KTI - KOREA #612, Kolon Science Valley II, 811, Guro-dong, Guro-gu, Seoul, 152-050, Korea Tel: 82-2-850-7800 Fax: 82-2-850-7828 E-mail: BSKim@kti-korea.com Select 96 at www.HydrocarbonProcessing.com/RS

PLANT SAFETY AND ENVIRONMENT • Monitor the application and development of the performance standards during the project life cycle as required by the adopted verification process. Project HSE management system. The projects with a potential major hazard shall be demonstrated to have an effective management system to minimize the risk to the health and safety of people and the environment during all project phases. A typical HSE management model is shown in Fig. 1. According to this model, once the HSE policy is defined, the project will progress based on an iterative cycle of: • Planning work • Doing work • Checking through appropriate measurement that work is being done as per the HSE plan • Acting on the findings to improve the system. The project HSE policy states what it intends to achieve on the projects with respect to HSE. The project team shall perform their tasks in compliance with HSE policy. The processes and procedures primarily dictate how the project team will work. Therefore, appropriate work processes and procedures must be available and integrated with the overall project management system. The processes and procedures could be implementing successfully only if the following fundamental issues are effectively covered: • Knowing what should be done (i.e., communication of responsibilities) • Being competent to do it (i.e., sufficiently qualified, trained and experienced) • Being encouraged to do it (through the company’s culture) • Being managed effectively so that it gets done. To achieve these goals, a major hazard project will plan for: 1. SCE identification. Determine and rank SCEs and tasks during the project life cycle including design, construction, procurement, operation, maintenance and inspection. 2. Performance standards. Define the requirements, assumptions and domain knowledge about an SCE such as: • Functionality • Reliability/availability • Survivability • Dependency/interaction with other systems • Constructability • Maintainability/accessibility • Operability • Procurement criticality rating and options. 3. Verification. Develop and implement a suitable verification scheme to ensure that SCEs are suitable and will remain in good repair and condition during operation. The SCEs’ performance is assured in two complementary ways: by routine checking of their design, maintenance, inspection and testing, and also by independent and competent verification of these activities. Routine checking of design, maintenance and inspection are covered in: • Integrity reviews—design • Integrity reviews—fabrication, construction, installation and commissioning • Operation • Maintenance • Modification and repair • Decommissioning and disposal

SPECIALREPORT

• Inspection, test and examination (written scheme of examination). Independent and competent verification provides further assurance that the SCEs are, and remain, suitable, i.e., they meet appropriate performance standards. 4. Action tracking and follow-up. Make sure that verification recommendations are traceable and auditable for the SCEs and safety-critical tasks and comply with the requirements defined in their performance standards. What is a safety-critical system? An SCS is any part of an establishment or installation that has a significant role with the: a. Prevention of major process hazards b. Control of major process hazards c. Limitation and recovery from containment loss d. Limitation and recovery from fire and explosion e. Escape and refuge f. Evacuation and rescue. A major accident means an “uncontrolled occurrence” in the operation of a site that leads to severe or catastrophic consequences to people, assets, the environment and/or company reputation. The consequences may be immediate or delayed and may occur outside as well as inside the site. There will also be a high potential for escalation. Examples of “major accidents” are: • Containment loss of flammable and/or toxic fluids leading to a fire, explosion and/or toxic injury • Events resulting in structural failure that could lead to further progressive collapse • Loss of stability of a mobile offshore installation • Well blowouts • Ships colliding with offshore installations or onshore jetties used for bulk loading explosive, flammable or toxic substances • Service vessel colliding with or otherwise affecting offshore installations • Other external hazards affecting offshore and onshore sites, e.g., accommodation/work barges alongside fixed installations, helicopters and aircraft, and road/marine product tankers. Once the hazardous events are identified, safety barriers are provided to prevent or mitigate the consequences of the major hazards. Event tree is one of the assessment techniques of hazardous scenarios (Fig. 2). The event tree is used to represent the sequence of the events in a hazardous scenario. A typical event tree consists of an initiating event, arrows that show the event sequence, barrier functions realized by barrier systems and possible outcomes. A horizontal arrow indicates that a barrier system functions (i.e., fulfills its function), whereas a downward arrow indicates failure to fulfill the barrier function. If the system failure in the event tree: • Causes a major accident, or • Contributes substantially to a major accident, or Initiating event (deviation from normal situation)

Preventive/protective safety barrier

Works

Fails

FIG. 2

“Safe state”

Undesirable event

Typical event tree with a safety barrier.

HYDROCARBON PROCESSING NOVEMBER 2009

I 51

SPECIALREPORT Initiating event

PLANT SAFETY AND ENVIRONMENT

Barrier functions Detect failure

Consequences

ESD system failure

Detect release prior to normal production

Incorrect ﬁtting of ﬂanges or bolts during maintenance

Self-control/ checklist

Initiation failure

A subsystem

“Safe state” failure revealed

ICSS failure

And

Commoncause failure

ESD valve failure Or

And

Fire and gas detection And

Control of work/ inspection

Gas detection

Or Leak test And

“Safe state” failure revealed

Valve body failure

Manual Or

Fire detection

Actuator failure Or

Control room

Mechanical failure

Local

SOV failure

No person

Action

Release

An element

And

Communication FIG. 3

Barrier block diagram—“incorrectly fitted equipment.”3

• Prevents or limits the mitigation of the consequences of a major accident, Then it shall be considered as the SCS. Sometimes more than one safety barrier are required. Fig. 3 shows an example for multiple safety barriers. In this case, applying the wrong fittings during maintenance can be detected during inspection and leak test prior to operation and avoid the undesirable event of the hydrocarbon release. If a series of subsystems (hardware) and related tasks (software) are associated with the SCS fault-tree analysis could be used to show how these subsystems and tasks are related and contribute to the failure of the whole safety barrier. If the fault tree of the SCSs is combined with the event tree of the hazardous event then the effect of each element of the fault tree on the risk of each branch or entire event tree can be measured and the criteria of safety criticality could be set as follows: “If failure of a system, subsystem or element increases more than 10% the risk of scenario or more than 1% the risk of the whole installation then it shall be considered as safety critical.” These are the arbitrary criteria and are set based on the experience and judgment of the operator and designer. These criteria have been applied for the safety criticality test of the Judy Joanne Platform.1 Safety-critical subsystems. A safety barrier such as ESD,

blowdown and firewater systems consists of the various subsystems and elements. Fault-tree analysis could be used to present the configuration of the subsystems and elements. If a subsystem or element failure causes the failure of the whole SCS then it is considered as critical and it is required to develop the performance standards for them. Fig. 4a shows that if any part of the ESD valve or ICSS fails the whole ESD function will fail. But for initiation failure, the fire 52

I NOVEMBER 2009 HYDROCARBON PROCESSING

Push-button

FIG. 4a Fault-tree analysis for the ESD system.

FIG. 4b Proof Test Optimisation with ADEPP risk models.

and gas detectors as well as manual detection must fail at the same time to cause the failure of the whole ESD function. Event trees from QRA and Fault trees can be combined in the ADEPP risk models. The safety criticality of each system and its subsystems are tested using the above or any other safety-criticality test criteria. One of the advantages of this approach is that the effect of time of test or repair on the risk of scenario, risk of installation and criticality of systems can also be assessed (Fig 4b). SIL classification and safety-critical elements. SIL is

a simple way to relate the reliability/availability of a safety barrier in terms of probability of failure on demand to the risk of the hazardous event.

K T I C O R P : R E VA M P G RO U P

Fired Heater Global E-3 Services EVALUATE - ENGINEER - EXECUTE FIRED HEATER STUDIES ENGINEERED REVAMPS EMERGENCY REBUILDS CONSTRUCTION SERVICES REPLACEMENT PARTS KTI Corporation 1990 Post Oak Blvd., Suite 1000, Houston, TX 77056 Tel: (281) 249-2400 Fax: (281) 249-2328 E-mail: sales@kticorp.com

KTI - KOREA #612, Kolon Science Valley II, 811, Guro-dong, Guro-gu, Seoul, 152-050, Korea Tel: 82-2-850-7800 Fax: 82-2-850-7828 E-mail: BSKim@kti-korea.com

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SPECIALREPORT

PLANT SAFETY AND ENVIRONMENT

Fig. 5b shows the event tree for overpressure protection. Traditionally, the overpressure protection system consists of Consequence of hazardous a high-pressure trip as the primary proNonevent SafetyInstrumenttection and a relief valve as the secondary instrumentcritical based Tolerable Process based protection. tasks and protection risk risk protection IEC 61508 and IEC 61511 provide the procedures layer layer Frequency guidelines to increase the resolution of the of hazardous Necessary risk reduction prescriptive approach of API 14C by a riskevent based approach as shown in the Fig. 6. In Fig. 6, three independent categories of the protective systems as instrumented Safety integrity of non-SIS prevention/mitigation Process and the based, noninstrumented based and proceprotection layers, other protection layers and SIS basic process matched to the necessary risk reduction dural based can be distinguished. control system When the required SILs are assigned a FIG. 6 Protection layers affect either the frequency of occurrence or the severity of the SIL verification is performed to verify if the consequence of an undesirable event. required SIL can be achieved with the actual design. If not then the different options are examined by trial and error and changing the following: Process Primary Secondary Outcome • Time of test/repair upset protection protection • Protective system type, their number or configuration Yes Safe state • Basic design. Overpressure The risk models with the combined event and fault trees could Over-temperature be applied for SIL verification. When one of the above parameters Over-filling No Yes Safe state Gas blowby is changed the risk of scenario will change. The iteration is conVacuum tinued by the time that the risk of scenario reaches to as low as a Under-temperature No Undesirable reasonably practicable level (ALARP). Etc. Fig. 7a shows how that the manifold isolatable section is isoFIG. 5a Safety barriers for the process upset according to API 14C lated by the ESD valve upstream of the heat exchanger and ESD recommendations. valves on the outlet of injection compressor trains in a gas processing plant. The author applied this quantitative SIL assessment and verification method for this project. Remain Shut off Pressure The author applied the combined event tree and fault tree containment Outcome Overpressure inflow relief integrity analysis for the quantitative SIL assessment and verification method for this project. Fig. 7b illustrates this risk model for the medium gas release. As Pressure Primary pressure “Safe state” without over (PAHH) protection (PSD) environmental impact shown in the event tree, the amount and duration of gas release could be limited if the ESD system can be isolated. Otherwise a continuous release will cause the more severe consequences and escalation. “Safe state” with Secondary pressure The different ignition control systems such as hazardous-area environmental impact protection (PSV) classification, compliance with ATEX regulations, bonding, grounding, etc., reduce the risk of delayed ignition and further explosions. Residual strength “Safe state” pressure Table 1 summarizes the possible noninstrumented-based sysin steel < tolerable level tems that are applied to reduce the risk of scenario. This example shows that even with the ESD function fire duration will be more Release, risk of than the failure time of the adjacent equipment. Therefore, if fire and explosion there is no passive fire protection the domino effect and escalation will be unavoidable. FIG. 5b Safety barriers for release due to overpressure. Fig. 7c shows the subsystems and elements of the fire and gas and ESD systems. Because of the small amount of gas inventory If the SIL of a single safety barrier is not sufficient to reduce in the heat exchanger the SSSV and a wing valve could be conthe risk of the hazardous scenario to a tolerable level then another sidered as the back up for the ESD valve downstream of the heat independent and diverse safety barrier shall be considered. exchanger. But the streams from the injection compressors are API 14C (ISO 10418) recommends providing at least two isolated by just one ESD valve. With this isolation configuration independent and diverse safety barriers for all those undesirable not more than SIL1 can be achieved while quantitative SIL assessevents that could lead to a major accident on an offshore installament calls for an SIL2 ESD system. tion. This concept has been broadly accepted and adopted by the To increase the ESD system integrity level to SIL2 the following other hydrocarbon processing projects. option is proposed: Fig. 5a illustrates the API 14C concept in the form of an event If a solenoid valve is added to the control valve on the stream tree for the typical process upset scenarios like over pressure, from the injection compressors then it can provide the dual funcovertemperature, etc. tions of control and ESD. 54

I NOVEMBER 2009 HYDROCARBON PROCESSING

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SPECIALREPORT

PLANT SAFETY AND ENVIRONMENT

As the control valve is continuously on line and its operational failures like blockage are revealed we assumed that failure-on-demand for the ESD function will be limited to “fail to close on demand.” Fig. 7d compares the integrity of isolating one injection compressor line for the base case for this option. It also shows that SIL4 compressor isolation can be achieved by adding a solenoid valve to the control value. Safety-critical integrity tasks. Safety-critical integrity tasks and activities are defined to assure the integrity of an SCE during the project life cycle including the design, construction, installation, commissioning, operation, modification, repair, inspection, testing or examination phases. Sometimes even with provision of the required instrumentedand mechanical-based safety barriers, the risk of scenario remains high. In these cases operator interventions get more important and are classified as the safety-critical tasks. Typical safety-critical tasks are: • Performing the specific studies or calculations that affect the design and performance standards of the SCEs • Interdisciplinary SCE design verification 1E-3n01 1ESD-3110

From injection compressor 1ESD-2110 1PCV-2110

1MV-3n03

Train-1

Wing valve 1MV-3n111

MeOH

1ESD-2215 1PVC-2215 Train-2

1SSSV-3n01

1ESD-2315 1PVC-2315 Train-3

FIG. 7a

Schematic for isolation section (IS-01).

Initial event

Release, M Fr (1/yr) 3,7E-02 Consequence IS-01 Module

Medium

Safety barrier (ESD)

Safety barrier (ignition control)

Limited release ESD system State Works Gas 0.9562

Ignition probability Jet fire 0.105 Explosion 0.001

F&G

Flash fire

0.9562

0.030

M, kg 26,948 Rate, kg/s 12.0 BD rate, kg/s Automatic BD? No T,min, m

Lflame @ 5min, m

RA Continuous release ESD system

Event Ignition probability

DJet-Target, m

State

Fails

Jet fire

0.105

CA F

X340 mbar, m

Gas

0.0438

Explosion

0.009

Flange guard

F&G

0.0438

Flash fire

0.301 Event

SIL assessment for ESD

Explosion escalates

RRed

Event

0.03

ALARP

Jet fire escalates 10,000 2,30E-05 0.23

ALARP

Explosion escalates 100,000

FRed

2,03E-06

Risk reduction required

RRed

FIG. 7b

1,7E-04 Risk reduction required

Explosion 100,000 3,25E-07

1,5E-05

Target risk

SIL2

16.8

Event CRed FRed

ALARP

CRed

Required SIL

Jet fire escalates 100,000

RRed

0.04

100,000

383

2,61E-03

Event CRed FRed

3.2

Explosion 100,000 3,2E-05 Risk reduction required

RRed

Jet fire 100 3,7E-04

Max. risk without ESD Required PFD

Event CRed FRed

367

Jet fire 100,000 3,7E-03 Risk reduction required

Event CA F

TPFP, min, m TBD, min, m

Outcome for actual design with: - SIL1 ESD - No automatic BD - Not enough safety distance - No passive fire protection - No flange guard - No compact flange

• Verifying the SCEs by competent third parties • Verifying the specifications and/or communications to contractors and subcontractors • Testing the products for both material and functional aspects at delivery time • Testing the function of the equipment during operation • Inspection and routine maintenance procedures • Specific operational procedures related to the SCEs • Specific training and communication with operators • Continuous improvement and updating the design and operation after a specified period of time (e.g., every three or five years) Generic failure frequency is an average value. It could be more or less for the plant under study considering the specific conditions and the plant management. Fig. 8, from API 581, summarizes the parameters that affect the adjusted equipment failure frequency. Safety-critical tasks are considered to reduce the adjusted failure frequency and, therefore, reduce the residual risk of scenario to the minimum possible. Sometimes even with provision of the required instrumentedand mechanical-based safety barriers, the risk of scenario remains high. In these cases operator interventions get more important and are classified as the safety-critical tasks. Typical safety-critical tasks are: • Performing the specific studies or calculations that affect the design and performance standards of the SCEs • Interdisciplinary SCE design verification • Verifying the SCEs by competent third parties • Verifying the specifications and/or communications to contractors and subcontractors • Testing the products for both material and functional aspects at delivery time • Testing the function of the equipment during operation • Inspection and routine maintenance procedures • Specific operational procedures related to the SCEs • Specific training and communication with operators Outcome for modified design with: • Continuous improvement and updat- SIL2 ESD ing the design and operation after a speci- No automatic BD - No enough safety distance fied period of time (e.g., every three or five - J30 passive fire protection - Flange guard years) - Compact flange

1.5

0.2

ALARP

Event tree for quantitative SIL assessment of fire and gas and ESD systems to protect against the medium gas release in a gas plant.

I NOVEMBER 2009 HYDROCARBON PROCESSING

Identifying the safety-critical systems. The SCSs must be identified from

the conceptual phase. At this stage, based on the contract and feasibility studies, the typical layout and technology options are selected. Within these initial inputs the preliminary SCSs are identified by a coarse SCE identification. The roles of SCEs for the inherently safer options and the impact on the public living nearby and the environment are the governing criteria at this stage of the project. At the basic engineering phase of the project, the requirements for the safety barriers could be determined based on either: • A code-based approach such as API 14C and API 14J • A risk-based approach such as a fire and explosion study or SIL assessment.

PLANT SAFETY AND ENVIRONMENT

TABLE 1. Noninstrumented-based safety barriers to reduce the risk of fire and explosion

ESD system failure

Ranking

Case

ICSS failure

Fire and gas detection

Consequence

Injection compressor (x 3 train) Isolation

Heat exchanger isolation And

And

Wellhead Isolation

Initial

Other risk-reduction measures Reduction Final factor Description

Jet fire

Isolation failure

Frequency

ESDV

SPECIALREPORT

ESDV

Risk

1,000

High

ALARP

10,000

Consequence

Frequency

100

High

ALARP

100

PCV

FIG. 7c

Risk

Wing valve

Consequence

1—factor of 10 for flange guards 2—the factor of 100 for PFP 30min cannot be considered because duration of continuous release could be more than the 30 minutes passive protection

Frequency

Improvement of ESD system from SIL

High

ALARP

Injection compression 3

PFD

1,27E-02

CSU

1,27E-02

SIL

Risk

Escalation of explosion

SIL1

PFD(M)

9,46E-05

CSU(M)

9,48E-05

SIL(M)

SIL4

Compressor output ESD

Compressor output control valve

No.

Tag

1ESD-2p10

Mod-1

PFD

1,27E-02

No(M)

CSU

1,27E-02

Tag

1PCV-2p15

SIL1

PFD

7,45E-03

CSU

7,46E-03

SIL

SIL2

p =1 to 3

Consequence

Frequency

High

ALARP

Risk

And

SIL

1—factor of 10 for compact flanges (reduction of the flange number) 2—factor of 10 for flange guards (increase the probability of safe gas dispersion)

Escalation of jet fire

Fault tree for the ESD system.

No.

Compact flange

Explosion

And

SSSV

1—factor of 10 for flange guards 2—factor of 100 for PFP30min where required

No.

0 Change the 1PCV-2p15 to dual ESD, control functions valve

FIG. 7D Fault tree for isolating injection compressor line. The red part shows the modifications for the proposed option.

At this stage the SCSs get more detailed for the subsystems, elements and required tasks. The bow-tie technique using a combination of event and fault-tree analysis could also be used to identify the required SCSs. During the basic design, the functionality, reliability/availability, survivability and dependency of the SCSs are defined based on the risk assessment, codes, standards, industrial guidelines, specific requirements and know-how of the company and contractor.

Improvement of ESD system from SIL1 to SIL2

It is necessary that the designers, operators and verification bodies get involved for review and comments on SCEs and their performance standards. A brainstorming session has proven to be the most effective approach to involve all the relevant parties in identification of the SCEs. During the detailed design, the performance standards must be completed for constructability, maintainability/accessibility, procurement criticality ranking and operability during commissioning and normal operation. Brainstorming sessions. The brainstorming session is a

multidisciplinary exercise and involves all the key personnel in the discussion. The SCE identification team consists of: Facilitator: to facilitate the identification process with a systematic approach. All team members are encouraged to give the essential inputs and comments about the SCEs. Secretary: to record reasons for selecting or rejecting items and the scope of SCE requirements. Technical HSE experts: to provide information about major accident hazards, interpreting local legislative requirements or practices and safety study results. Disciplines leaders: to provide the information about the basis of design, assumptions, accuracy and limitations, credible undesirable events and provision of the mandatory safety requirements. HYDROCARBON PROCESSING NOVEMBER 2009

I 57

SPECIALREPORT

Generic failure frequency

Equipment modiﬁcation factor

(FE )

PLANT SAFETY AND ENVIRONMENT

Management system evaluation factor

Technical module subfactor

(FM )

Damage rate Inspection effectiveness Universal subfactors Plant condition Cold weather Seismic activity Mechanical subfactor Equipment complexity Construction code Life cycle Safety factor Vibration monitoring Process subfactor Continuity

FIG. 13

The first ADEPP monitor interface lists the results of the HSE critical assessment.

FIG. 19

Results of the QRA and dynamic simulation are attached to the performance standard.

Stability

Frequencyadjusted = Frequencygeneric X (FE ) X (FM )

FIG. 8

Relief valves

Calculating the adjusted failure frequencies (from Fig. 8-1 of API 581).

Operator and maintenance representatives: to provide details on current operational arrangements and ensure ownership of the performance standards and provide a detailed working knowledge of the installation equipment and its operating conditions. Independent verification body (IVB): to ensure that the criteria, experience and comments of the IVB has been considered. During the SCE identification sessions the following questions shall be answered and recorded: Main questions: • Does the system/equipment prevent or limit the effect of a major accident? • Would system/equipment failure cause or contribute substantially to a major accident? Further questions: • Are there any specific local regulatory requirements or expectations for specific barriers and SCEs? • Are there other SCEs that are considered to be good practice within the region or wider industry? • Are there specific features of the design and operating philosophy of an installation which means that specific equipment or systems should be considered as SCEs? The discussions and eventual actions and recommendations are summarized and recorded in the worksheets. Fig. 13 shows the online ADEPP monitor interface for the SCE identification brainstorming sessions. The main advantages of using ADEPP monitor for the SCE identification are as follows: 1. Cost-effective solution for communication between people involved in the project prior, during and post brainstorming sessions. The new inputs or comments are added as an independent and traceable entry. The team members are informed by an automatic e-mail about the new updates. 58

I NOVEMBER 2009 HYDROCARBON PROCESSING

2. The possibility of linking the results (curves, tables, texts and images) of important supporting documents such as the fire and explosion study and dynamic simulation to each requirement. 3. The possibility of linking the other relevant project databases like HAZID, FIREPRAN, etc., to the SCE identification worksheets (see Fig-19). 4. Efficient online action tracking and follow up. The ADEPP monitor can be applied for any hazardous plant including upstream onshore and/or offshore installations, pipelines, hydrocarbon processing, chemical, power and nuclear plants, railway and aeronautics. The ADEPP monitor could also be applied to monitor all the HSE-related subjects such as HAZID, HAZOP, SIL and bow-tie, and produce an online HSE case for the project. To evaluate the prototype of the ADEPP monitor, please enter as a guest at the following Website: http://www.adepp.webexone.com.

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SPECIALREPORT

PLANT SAFETY AND ENVIRONMENT 2

each) are available in http://www.adepp.com/demo.html. Free software modules are available at http://adepp.com/demo. HP ACKNOWLEDGMENT The author thanks the valuable comments of Mr Frederic Salimi on this article and developing the ADEPP monitor. Mr Frederic Salimi obtained his MSc in dependability from “Ecole Centrale Paris” and has been the HSE leader for various major oil and gas projects.

ADEPP ALARP CSU ESD HSEMS ICSS PAHH PFD PSD PSV SCE SCS SIS SIL SOV

ACRONYMS Analysis and dynamic evaluation of project Processes As low as reasonably practicable Critical Safety Unavailability Emergency shut down Health, safety and environmental management system Integrated control and safety system Pressure trip alarm high-high Probability of Failure on Demand Process shut down Pressure safety valve Safety-critical element Safety-critical system Safety instrumented system Safety integrity level Solenoid valve

LITERATURE CITED Roger, M. C., Bamforth, P., Salimi, A., Thomas, E. J., “Determination of safety critical equipment, safety critical procedures and softwares utilising quantitative risk assessment data,” Offshore structures hazards & integrity management, International conference of ERA Technology, London/UK, 4-5 December 1996.

3 4 5

6 7

8 9

Dr. Salimi Fabienne-Fariba, Mutiplan R&F, France and Martin C. Rogers, Kvaerner Oil & Gas, UK, Use of Quantified Risk Assessment for the determination of Safety Integrity Levels (SIL) utilised in the design of offshore oil and gas installation, ERA Technology, Dec. 1999. SINTEF REPORT No STF38 A04419, Safety barriers to prevent release of hydrocarbons during production of oil and gas, 2004 ISO 10418, Analysis, design, installation and testing of basic surface safety systems for offshore production platforms. (Replaces API RP14 C). ISO 13702, Petroleum and natural gas industries—Control and mitigation of fires and explosions on offshore production installations—Requirements and guidelines. IEC 61508, Functional Safety of Electrical/Programmable Electronic Safety Related System, (all parts) IEC-61511-3, Functional safety—Safety instrumented systems for the process industry sector—Part 3: Guidance for the determination of the required safety integrity levels, 2003. Stevens, Richard and James Martin, “What is requirement management,” Quality System and Software Ltd. Jan. 1995. Fitch, John, Requirement management workshop, Systems Process Inc., Feb 1995.

Fabienne F. Salimi is a senior HSE consultant and has more than 20 years of experience in process safety engineering in the chemical and oil and gas industries, both onshore and offshore. She has a particular expertise in risk-base design and identifying safety-critical systems and developing their performance standards for the life cycle of the major hazardous projects. Since March 1994, Dr. Fabienne has been the project manager of Multiplan R&F in France and later the ADEPP Academy in the UK. She is also the codeveloper and project manager for developing the ADEPP monitor, an online innovative tool for identifying safety-critical equipment and management of their performance standards. Dr. Salimi obtained her PhD in chemical engineering from “Ecole Centrale Paris” in 1996. Her main qualifications were obtained in Iran and France and she is member of the American Institute of Chemical Engineers (AICHE) and the International Society for Instrumentation (ISA).

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Better slime control. Chlorine dioxide as a biocide has been

used effectively as a disinfectant for over 65 years, in municipal markets. On the contrary, it has not been widely used in the HPI as an alternative to more common oxidants due to perceived cost and safety issues. However, over the past 10 years, chlorine dioxide has been successfully applied to treat either severe microbial fouling issues or to maintain control in both once-through and recirculating cooling systems. From this experience, several key insights have been identified as to why this biocide is so effective against surface “biofilm” populations, and why its unique characteristics make it a truly “fit-for-purpose” biocide for the HPI. One such insight is chlorine dioxide’s lower reactivity with hydrocarbons when compared to other oxidants. When process hydrocarbon leaks occur, most oxidant usage costs tend to skyrocket, due to increased demand from the hydrocarbon and sudden microbial growth in cooling water systems. Chlorine dioxide, however, delivers efficient biocide control by reacting, almost preferentially, with microorganisms—not with the hydrocarbon. Chlorine dioxide has also been shown to actually reduce corrosion rates in cooling water systems. Chlorine dioxide—’Fit-for-purpose’ biocide. Chlorine

dioxide is a broad-spectrum microbiocide that is effective over a wide pH range. While chlorine and sodium hypochlorite (bleach) are shifted toward the less effective hypochlorite state at pH ranges typical of most modern cooling water programs, chlorine dioxide remains a potent biocide. Unlike other oxidants under these conditions, chlorine dioxide is less reactive with hydrocarbons and does not form chloramines when ammonia-nitrogen compounds are present. This makes it a particularly “fit-for-purpose” biocide for the HPI. Being less reactive is especially important during system leaks that raise the hydrocarbon concentrations in the cooling water. Chlorine dioxide

is also less reactive with most treatment chemicals (corrosion and scale inhibitors) commonly used in cooling tower programs. Mechanism for biofilm attack. Field experience indicates that more than 80% of all cooling water system problems are due, either directly or indirectly, to microbiological control problems, specifically biofilms. Corrosion, scaling and fouling are all affected significantly by the presence of biofilm. Therefore, it should be a priority to eliminate biofilm within cooling water systems. There are two general classifications of microorganisms in cooling water systems: planktonic and sessile. Planktonic organisms are free floating in circulating water while the sessile organisms adhere to system surfaces. Sessile bacteria are the ones that cause the major problems in cooling systems, such as loss of heat transfer, corrosion, and accelerated fouling and scaling rates.1 Fig. 1 shows the insulating potential of biofilms with respect to other scaling or fouling materials. Microbial biofilms are the most insulating of the scaling or fouling mechanisms studied.1 In most cases, planktonic species are the only ones tested on a routine basis, as it is often more difficult to accurately sample sessile bacteria. Unfortunately, testing for planktonic bacteria does not always provide a true indication of the amount of biofilm present in a system. Result: There is frequently sufficient halogen present to give a low planktonic bacteria count, while allowing significant

60 Thermal conductivity, W/m/°K

ydrocarbon processing industry (HPI) processes require temperature control to maintain chemical reactions needed to manufacture a wide variety of products and to ensure operations safety. HPI facilities rely on process cooling water to achieve these goals. New developments have discovered more effective biocides to prevent biofilm formation in cooling water systems. Several presented case histories show how efficient and effective biofilm control can be achieved in refining and petrochemical applications while reducing corrosion rates within the cooling water system.

50 40 30 20 10 0 Carbon steel

FIG. 1

Stainless steel

Titanium

CaCO3 scale Materials

Iron oxide

Bioﬁlm

Thermal conductivity of heat exchanger construction materials, biofilms and scale. HYDROCARBON PROCESSING NOVEMBER 2009

I 61

BONUSREPORT

WATER MANAGEMENT

amounts of sessile bacteria to flourish. Fig. 2 shows a pictorial representation of the progression of a microbial biofilm. Biofilm develops in a cooling system by the formation of an organic monolayer, and organisms attach to the surface. Planktonic organisms drop from the bulk water to the surface and begin attachment. The attachment process at this point is weak, resulting in some reversible adhesion. Some microbes, however, remain on the surface and begin to develop an exopolysaccharide sheath. This sticky substance entraps nutrients and debris. Continued growth of the bacterial population results in surface colonization and continued growth of the biofilm. The biofilm continues to grow until shear forces and physiological changes limit its size.2 However, low-flow velocities can result in plugging, as is sometimes observed in heavily fouled heat exchanger tubes. The end results of biofilm formation include: • Heat transfer loss. Biofilm is the most highly insulating material in a cooling system. • Corrosion. Conditions are created for differential oxygen concentration cell corrosion of underlying metal. • Limited ability of corrosion inhibitors to contact and thus passivate metal surfaces. A biofilm layer of only 10 to 12 organisms thick (too small to be seen with the naked eye) can create anaerobic conditions that foster the growth of many bacterial populations, such as acid-producing bacteria and sulfate-reducing bacteria (SRB), such as Desulfovibrio desulfuricans. These bacteria impact both general and pitting corrosion rates by generating hydrogen sulfide (H2S) and iron sulfide deposits. • Increased scaling for once-through cooling systems. The negative surface charge of biofilms attracts scale-forming ions (Ca2+, Mg2+, etc.) and results in localized concentrations that exceed solubility limits for these materials. These conditions could initiate scaling where biofilms are present.

• Higher fouling rates. The “sticky” polysaccharide layer produced by biofilms acts as an adherent for foulants such as mud, silt and corrosion products. Chlorine dioxide biofilm control model. Chlorine, in the form of gas or liquid (sodium hypochlorite), has traditionally been used to control microbial growth in cooling systems. However, there are many instances where, even in systems with consistent chlorine residuals, biofilms are present and the problems listed earlier are encountered. During extensive field work, chlorine dioxide has shown the ability to consistently remove biofilm, prevent its regrowth and thus significantly improve system performance. Both research and field experience indicate the effectiveness of chlorine dioxide on biofilms and can best be explained by the mechanisms illustrated in Fig. 3. It has long been known that biofilms have a negative surface charge.3,4 Thus, hypochlorous acid and hypobromous acid (formed when chlorine, sodium hypochlorite or bromine are dissolved in water), being negative ions, are repelled. This results in a higher dosage required to penetrate the biofilm. Chlorine dioxide (ClO2) is a molecule, with a neutral charge that is not repelled; thus, providing improved penetration at a lower dosage (see Fig. 3a). Upon reaction with the biomass, most of the chlorine dioxide (50% to 70%) reverts back to the chlorite ion (ClO2–) as shown in Fig. 3b. Biofilms can have acidic conditions underneath, due to a common mixed population containing acid-producing bacteria and other microbes. The chlorite ions are able to undergo reconversion to chlorine dioxide via the acid/chlorite reaction:

5NaClO2 + 4HCl 4ClO2 + 5NaCl + H 2O The chlorine dioxide generated inside the biomass quickly kills it and destroys the polysaccharide protective layer (Fig. 3c). By removing the biofilm from the system, conditions causing the vast majority of system performance problems are eliminated. State-of-the-art chlorine dioxide generators. Wide-

FIG. 2

(a)

Progression of biofilm formation over time.

CIO2 bioﬁlm kill mechanism

ClO2 pentrates

FIG. 3

spread adoption of chlorine dioxide biocide has been hampered by concerns over safety and unrealistic treatment costs. Effective application of chlorine dioxide requires onsite generation. Older generator systems, by their design, were plagued with leaks, incomplete reaction products, reduced chlorine dioxide generation efficiencies and high maintenance requirements. New state-of-the-art generators rely on vacuum-eductor systems that are inherently safe and are designed to withstand the

HOClrepelled

Negative HOBr - surface repelled charge

(b)

CIO2 bioﬁlm kill mechanism

ClO2 reacts with bacteria

Most reverts back to ClO2-

Bioﬁlm

ClO2 + MBgClO2-

Substrate

(c)

CIO2 bioﬁlm kill mechanism

Microbes under bioﬁlm produce acid

ClO2- acid produces ClO2

Targeted kill of bioﬁlm

ClO2 + MBgClO2- + H+ gClO2 Substrate

Microbes

a.) Initial penetration of ClO2 on a biofilm; b.) ClO2 reaction with bacteria under the biomass, and c.) Destruction of the polysaccharide layer by ClO2.

I NOVEMBER 2009 HYDROCARBON PROCESSING

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BONUSREPORT

FIG. 4

WATER MANAGEMENT

FIG. 5

a.) Heavy microbial growth in the high-efficiency fill of a US refinery, and b.) Clean structured packing of the cooling tower fill following two months of ClO2 treatment.

FIG. 6

a.) Heavy microbial growth in a large ammonia plant cooling water system; and b.) Clean cooling water system following ClO2 treatment.

State-of-art chlorine dixoide generator simple, compact design ensures reliability and safe ClO2 generation.

rigors of an industrial environment. These design characteristics can ensure the safety of chlorine dioxide generation: • Motive water through the eductor produces a vacuum that pulls the precursors into the generator. • Since no pumps are required, no head failures and leaks will occur, which can reduce maintenance requirements and costs. • If water flow is lost to the eductor, no vacuum is produced. Therefore, no chemicals are fed and the reaction stops. Improved chlorine dioxide generation efficiencies are obtained using various types of feedback control mechanisms, which include online monitoring of chemical flow, chlorine dioxide residual, pH and/or bleach concentration. When coupled with the added ability to maintain wireless communications, this new generation of equipment is extremely safe and reliable. Fig. 4 shows examples of a sophisticated chlorine dioxide generation system. Cost efficiencies for chlorine dioxide programs are realized by the additional advantage that it is fed intermittently and continues to provide clean system surfaces. Field experience has taught us that total application time is typically one to two hours, twice per day. Depending on the system (open-recirculating or oncethrough) and level of contamination, the dosage may vary from 0.2 ppm to 1 ppm during the application. Only heavily fouled recirculating systems require dosages approaching 2 ppm. Case history 1: Large southern US refinery. This refiner

cost savings to the refinery were $850,000 for fill replacement and in excess of $1 million/yr for recovered heat transfer capability. Case history 2: Large southern US ammonia plant.

This large ammonia plant refitted its cooling tower with highefficiency film fill and experienced an immediate increase in chlorine gas feed to maintain the free residual. This was attributed to increased microbial growth in the new fill media. A chlorine dioxide program was instituted to address this problem. Shortly thereafter an ammonia leak occurred that further increased microbial growth. At this facility, chlorine dioxide was fed at 0.8 ppm for three hours per day. The system ran for 15 months before the customer was able to shut down for repair. When inspected after this extended leak, the cooling water system was cleaner than it had ever been before (see Figs. 6a and 6b). Case history 3: Large Middle East seawater cooling system. A very large central once-through cooling water

system used seawater to provide process water cooling capability to numerous large industries at a Saudi Arabian HPI complex. This system had historically used electrolytic generation of sodium

had a cooling tower with a water recirculating capacity of 45,000 gal/min. A process leak was present, and the refinery was unable to shut down and repair the leaking heat exchanger. The system was being treated with sufficient chlorine (Cl2) gas to obtain 0.5 ppm free available chlorine (FAC). In addition, two biocides and a biodispersant were fed in an effort to control microbiological growth. There was heavy microbial growth in the high-efficiency film fill (Fig. 5a). The refiner was planning a shutdown to replace the cooling tower fill due to heat transfer loss. Chlorine dioxide was applied for 30 minutes, three times per day to achieve a 0.5 ppm residual. Over a two-month period, the fill FIG. 7 a.) Heavy microbial growth in the large once-through sea-water cooling system, b.) ClO2 generating system treating microbial growth, c.) Marked improvement and was cleaned completely (Fig. 5b), thus elimicontrol of algae growth in the cooling systems. nating the need for the fill replacement. The 64

I NOVEMBER 2009 HYDROCARBON PROCESSING

M.E. reﬁnery cooling tower

2.0 Iron, ppm

Begin CI02

5 Total iron Calcium CoC

1.5

4 3

1.0 2 0.5

1 0

FIG. 8

8/3/2007

8/20/2007

Date

7/19/2007

7/4/2007

6/19/2007

6/4/2007

5/5/2007

0.0

Cycles of concentration, (CoC)

WATER MANAGEMENT

Decreased iron levels and consistent cycles of concentration indicate lower corrosion rates.

hypochlorite from seawater to dose the system for microbial control. Due to the extensive nature of the open distribution system, it was not possible to feed sufficient hypochlorite to eliminate algae growth in the back portion of the canals during the summer. A chlorine dioxide generation system was installed in areas with poor algae control. The product was fed at 0.25 ppm to 0.5 ppm for two hours per day. The algae were effectively controlled (see Figs. 7a–7c). Case history 4: Middle East refinery cooling tower.

At this refinery, the cooling water system is an open-recirculating, fresh-water cooling tower whose makeup water source is city secondary wastewater with high organic and ammonia content. This system had historically experienced heavy biofouling and very high corrosion rates. The refiner had used all other microbiological control options at various times in the past (chlorine, bromine, non-oxidizing biocides and combinations of oxidizing and non-oxidizing biocides). The most recent treatment program consisted of continuous bromine feed, two non-oxidizing biocides, an algaecide and a biodispersant. Chlorine dioxide was applied three hours per day at 1.2 ppm dosage (approximately 0.5 ppm residual). There has been a documented 3 to 5 log (99.9% to 99.999%) reduction in both sessile and planktonic aerobic bacteria, as well as a 2 to 3 log (99% to 99.9%) reduction in both sessile and planktonic anaerobic bacteria. Heat exchangers and coupons are now biofilm free. As shown in Fig. 8, the iron levels in the cooling water are much lower, indicating reduced corrosion rates. New treatment option. Chlorine dioxide is a broad-spec-

trum microbiocide that is effective over a wide pH range. Unlike other oxidants, chlorine dioxide is less reactive with hydrocarbons and does not form chloramines when ammonia-nitrogen compounds are present. Chlorine dioxide is more effective than other halogens during system leaks, which raise levels of hydrocarbons in the cooling water. The neutral charge of the chlorine dioxide molecule allows it to better penetrate the negatively charged biofilm structure, resulting in more effective biofilm control. HP 1 2

LITERATURE CITED Characklis, W. and K. Marshall, Biofilms, Wiley Interscience Publications, John Wiley and Sons, Inc., New York, 1990. Sauer, K., A. K. Camper, G. D. Ehrlich, J. W. Costerton and D. G. Davies, “Pseudomonas aeruginosa Displays Multiple Phenotypes During Development as a Biofilm,” Journal of Bacteriol, Vol. 184, pp. 1140–1154, 2002.

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3Shibley,

G. S., “Studies in Agglutination —The Relationship of Reduction of Electrical Charge to Specific Bacterial Agglutination,” Department of Medicine of the College of Physicians and Surgeons of Columbia University, and the Presbyterian Hospital, New York, 1924. Burke, V., and F. Gibson, “The Gram Reaction and the Electric Charge of Bacteria,” Bacteriological Laboratories, State College of Washington, 1932.

Garry Laxton is a chlorine dioxide technical consultant in the Baker Petrolite Industrial Technology Group with Baker Hughes. He has 33 years experience with utilities and water treatment including seven years in utilities engineering and operations, and 26 years in industrial water treatment (cooling, boiler and wastewater). Mr. Laxton served as a technical manager with Baker Petrolite; and was the technical manager for the Middle East from 2004 through 2006. He has specialized in chlorine dioxide technology for the past 18 years, working in North America and the Middle East. He has authored or co-authored numerous technical papers on chlorine dioxide and holds one US patent. Mr. Laxton graduated from Texas A&M University in 1976 with a BS degree in mechanical engineering.

Roy Hernandez-Mena is a microbiologist in the Baker Petrolite Industrial Technology Group with Baker Hughes. He has over 25 years of industrial experience in the control of microbiological problems in cooling systems. Mr. Hernandez-Mena has conducted research to develop novel methods to control biofilms, and holds three US patents. His research interests include biofilm control and online monitoring of biofilm growth and he has published in peer-reviewed publications. Mr. Hernandez-Mena holds a bachelors degree in biology from the University of Pennsylvania. HYDROCARBON PROCESSING NOVEMBER 2009

I 65

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WATER MANAGEMENT

BONUSREPORT

Wastewater treatment: A refinery case study This refiner used an in-house initiative to troubleshoot plant-wide process water problems M. SHAFIQUE, Z. U. KIRMANI, A. KHURSHID, N. ALAM and N. AHMED, Attock Refinery Ltd., Rawalpindi, Pakistan

ll refineries produce wastewater with varying contaminant levels that require further treatment before discharge. Because wastewaters are collected from various processes, problems do arise. Hydrocarbon-processing facilities must comply with local and federal standards on water quality exiting the facility. Exceeding such limits will trigger an incident and fine in most cases. In this case history, the Attock refinery used two wastewater streams: oily and non-oily to carry process wasterwater to treatment facilities. Unfortunately, this refiner exceeded discharge limits for the facility and needed a plan to handle high pH and chemical oxygen demand (COD) from spent caustic and oil/water emulsion formation in wastewater.

The facility. Attock Refinery Limited (ARL) is based at Rawalpindi, Pakistan. ARL is one of the few refineries that can process a complicated mix of 70 different crude oils with APIs ranging from Distillation unit

Heavy crude unit (HCU)

Desalter cuff header

APIseparator

Boiler house

HBU-I (distillation unit)

Spent caustic treater

HBU-II (distillation unit)

Reformer

The approach. The main concerned parameters to be conCooling tower

APIseparator Tanks drain

C-sump Legend 1. Red (non-oily wastewater stream) Two SRC 2. Black (oily wastewater units (100 stream) gpm each) Reﬁnery exit FIG. 1

10 to 64. These crude oils are processed in four different crude mixes: light-sweet, light-sour, heavy and high total acid number (TAN) crudes. This refinery has a nameplate crude capacity of 40,000 bpsd and uses four distillation units namely HBU-20,000 bpsd and HBU-5,000 bpsd—both processing light sweet crudes; CDU-5,000 bpsd processes a light sour crude; and HCU-10,000 bpsd capacity processes heavy crude and a reforming unit. Wastewater produced from these crude distillation units (CDUs), desalters and crude/product tanks is categorized as oily wastewater. Wastewater from boilers and cooling towers is categorized as the non-oily stream. Oily wastewater after leaving the plant battery limit is collected in the API oil-water separators and finally collected in the equalization tank. From the equalization tank (C-sump), the oil is collected from the top and the oil-water emulsion is sent to primary treatment—the slant-rib coalescer (SRC) and dissolved air flotation (DAF) units. Fig. 1 is a detailed scheme of oily/non-oily streams at ARL. Previously, wastewater exiting the refinery premises occasionally violated pH and oil & grease (O&G) values as well as exceeded COD limits set by the National Environmental Quality Standards and Pakistan Environmental Protection Act 1997.1,2 Table 1 summarizes the wastewater quality results from the ARL facility. trolled were pH, total suspended solids (TSSs), O&G and COD. Therefore, these parameters were analyzed in all effluent streams to gauge their total impact on the main refinery effluent streams. From Fig. 1, boiler blowdown water was sent to the non-oily stream, and it was the main contributor for high pH and TSS valTABLE 1. Wastewater quality before treatment Sample No.

DAF unit (100 gpm each) APIseparator

Block diagram of refinery process units and wastewater streams at ARL.

Parameter

NEQS limits

Temperature, °C (Max)

pH value

ARL values

6 to 9

9.5

O&G, ppm (Max)

COD, ppm (Max)

150

300

BOD, ppm (Max)

TSSs, ppm (Max)

200

180

TDSs, ppm (Max)

3,500

2,500

Phenols, ppm (Max)

0.1

0.05

HYDROCARBON PROCESSING NOVEMBER 2009

I 67

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WATER MANAGEMENT

BONUSREPORT

ues. The treating plant for naphtha and kerosine generated spent wastewater streams, which pass through the pre-treatment and caustic that was disposed of in the oily stream. This wastewater primary treatment along with oily water. The high pH of the stream was the main contributor for high pH, COD and O&G caustic was also responsible for creating strong oil/water emulsions levels. The quality of the oily stream impaired the total efficiency that directly decelerated operating efficiencies for the API separaof the pretreater. Wastewater from the heavy crude unit (HCU) tors, equalization tanks, and SRC and DAF efficiencies. had a high oil content. The oily water, rich in surfactants with a high COD (700 Characteristics of the process wastewater at ARL include: ppm), is produced from the HCU desalter and was another source • Blowdown water produced from three boilers and softener strong of oil-and-water emulsions that impaired API separator backwash is rich in TSS and total dissolved solids (TDSs) with efficiency and downstream SRC and DAF treatments. a pH value greater than 12. Water treatment chemicals used in • Blowdown water from three cooling towers is another boilers are phosphate based for scaling control, sulfite based as stream that is directed to the non-oily wastewater stream. The conoxygen scavenger and ammonia to control pH in boilers. Before cerned parameters for this stream include pH, TSSs, TDSs, COD the study, blowdown water with high pH and TSS values was and occasional O&G. Water treatment chemicals used in cooling sent to the non-oily wastewater stream and it was mixed with towers are phosphate based to control scaling, biosperse and deothe treated oily wastewater before exiting sperse to control oil, sodium hypochlorite the refinery. This stream exceeded the ■ ARL’s quality circle designed for bacterial contamination, and sulfuric total wastewater quality specifications acid for pH control. and resulted in violations of the National and implemented cost-effective All of these streams were individually Environmental Quality Standards. analyzed for their physical and chemical indigenous solution of refinery • Spent caustic is produced from a properties on a laboratory scale. naphtha treating plant. This downstream wastewater to meet National sweetening unit processed sour naphtha Environmental Laws. Action plan. First, the boiler blowand kerosine; alkyl mercaptans in the down water was analyzed for its neutralnaphtha and kerosine oil were converted into alkyl disulfides. By ization with hydrochloric acid and sulfuric acid. However, to combining caustic soda solution in the presence of charcoal and be more cost-effective and to reduce chemical consumption, catalyst, nearly 99% of all mercaptans, as well as oxygen and nitrosulfuric acid was selected for further studies. Table 3 summarizes gen compounds, can be dissolved from petroleum fractions. neutralization results with sulfuric acid to control pH, and TSSs The refinery kerosine treater had a design capacity of 1,600 TABLE 4. Analysis of spent caustic bpd; the naphtha treater was designed for 4,400 bpd. The main 3 reactions involved in the sweetening process are: Sample Initial Initial RSH, Phenol, COD,

H 2 S + 2NaOH Na 2 S + 2H2 O

source

Na 2 S + H 2 S 2NaHS RSH + NaOH NaSR + H 2 O 2NaHS + 2O2 Na 2 S2 O3 + H 2 O 2RSNa + O2 + H2 O 2NaOH + RSSR The treater used 3% caustic strength for the naphtha/kerosine pre-wash, and 8%–10% caustic strength for the naphtha/kerosine settler. The quantity and drainage frequency of caustic from the prewash and settler is listed in Table 2. Before the study was conducted, the plant spent caustic, with high pH (12) and COD (~50,000 ppm), was directed to oily TABLE 2. Sources and quantity of caustic drainage Caustic source

Strength, %

% spent

temp., °C

ppm

382

2.5

9,331

LWK. prewash

14.19

11.86

875

1.1

55,209

Naphtha settler

15.68

12.46

4,129

1.6

6,026

Naphtha prewash

50.9

9.44

3,025

–

LWK. settler

TABLE 5. BBDW and spent caustic neutralization results Sample source

COD, ppm

Spent caustic soda (SCS) with oily layer

11.8

55,209

Spent caustic soda (SCS) after oil removal

11.8

4,600

Boiler blowdown water (BBDW)

11.66

98% BBDW + 2% SCS

11.76

180

7.0

190

98% BBDW + 2% SCS + 0.3% H2SO4

Qty, m3

Monthly disposal

Naphtha prewash

3 to 4

6 times

Naphtha settler

8 to 10

6.5

6 times

Kerosine prewash

3 to 4

4 times

Kerosine settler

8 to 10

2 times

TABLE 6. Final effluent water quality after implementation Sample No.

TABLE 3. Lab scale BBDW H2SO4 treatment results

Parameter

NEQS limits

ARL values

Temperature, °C (Max)

pH value

6 to 9

O&G, ppm (Max)

TSS, ppm

COD, ppm (Max)

150

140

Boiler blowdown water (BBDW) – Blank

11.13

BOD, ppm (Max)

Sample source BBDW + 0.30 ml H2SO4

10.01

TSSs, ppm (Max)

200

BBDW + 0.40 ml H2SO4

8.60

TDSs, ppm (Max)

3,500

2,500

BBDW + 0.50 ml H2SO4

6.95

Phenols, ppm (Max)

0.1

0.05

HYDROCARBON PROCESSING NOVEMBER 2009

I 69

BONUSREPORT

WATER MANAGEMENT 12 2008 results 2007 results

NEQS limit min NEQS limit max

8 6 4 2 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 600 2008 results 2007 results NEQS limit

500

FIG. 2

New treatment pit installed to improve management of oily and non-oily wastewater with high pH.

COD, ppm

400 300 200 100

Distillation unit

Desalter cuff header

APIseparator

HBU-I (distillation unit)

Boiler house

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Spent caustic treater

HBU-II (distillation unit)

Treatment pit

Reformer Cooling tower

APIseparator Tanks drain

TSSs, ppm

Heavy crude unit (HCU)

500 450 400 350 300 250 200 150 100 50 0

2008 results 2007 results NEQS limit

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec C-sump

Legend 1. Red (non-oily wastewater stream) Two SRC 2. Black (oily wastewater units (100 stream) gpm each) Reﬁnery exit FIG. 3

FIG. 4 DAF unit (100 gpm each) APIseparator

Revised refinery process wastewater management system and new installations at ARL.

are listed, too. Laboratory scale studies concluded that 0.4 ml of 98% pure H2SO4 per liter of boiler blowdown water (BBDW) is required to lower the pH < 9 as required by the National Environmental Quality Standard. In the second phase, detailed analysis of spent caustic from the treating plant was conducted and Table 4 summarizes the testing results. From the initial test results, it was observed that high COD values were attributed to the oily layer from the spent caustic discarded by the sweetening process. Therefore, by removing the oily layer from the spent caustic, a reduction of 80% to 90% of spent caustic COD was obtained. The remaining portion of spent caustic was mixed with boiler blowdown water since the spent caustic was only 2% of the total boiler blowdown water. Table 5 lists the boiler blowdown water and spent caustic neutralization. 70

I NOVEMBER 2009 HYDROCARBON PROCESSING

Refinery trends for COD, pH and TSSs at ARL before and after new wastewater management initiatives.

The heavy-crude-unit desalter oil-water emulsion was tested. The problems from this wastewater stream were sourced to the presence of a surfactant in the crude oil received from the Chanda oil field. The surfactant aided in creating in a strong oil/water emulsion.4 Testing. Laboratory-scale experimentation results were evaluated and used to develop optimization plans for the ARL facility. From the testing results, a neutralization pit with a total capacity of 0.1 million gallons (Fig. 2) would be installed. Boiler blowdown water would be collected in the first half of the pit. Temperature at the collection pit ranged from 80°C to 90°C. The wastewater was allowed to cool and settle in the first two pits for two hours. The spent caustic was collected in a vessel from which it was pumped to the third half of the pit at a rate of 1 tpd. Sulfuric acid was added in the third half of the pit to neutralize the pH to 8. After neutralization, the water was settled in the third and fourth half of the pit before disposal. At the HCU, the surfactant-rich Chanda crude oil was diverted to a light-sweet crude pool. With this change, operations of the desalter oil and water separator improved. Fig. 3 shows the scheme adopted for treating boiler blowdown water and spent caustic. The revised treatment program was very successful and enabled 100% compliance to the National Environmental Qual-

WATER MANAGEMENT ity Standards for pH, TSSs, O&G and COD. Moreover, the total efficiency of wastewater treatment increased. Fig. 4 shows the improvements in wastewater pH and COD with the water management changes for the last two years. The boiler blowdown water, with high pH and TSSs, and plant spent caustic with high pH and COD levels were treated via an onsite neutralization pit. Whereas, the operational controls applied at heavy-crude-unit desalter controlled oil-and-water emulsion formation. Spent caustic that was earlier drained into the oily drain was diverted to non-oily drain after removing oil. The neutralization treatment was successful in many ways: • National Environmental Quality Standards limits were met for pH, O&G, COD and TSSs. • The strong oil/water emulsion was broken by removing the high pH spent caustic from the oily drain. • Efficiency of API separators increased with reduced loading on the treatment plants. Quality of ARL wastewater after the new treatment program is summarized in Table 6. Applying an in-house initiative can identify cost-effective solutions that can be implemented in a short time and reusing spare equipment. HP 1 2 3 4

LITERATURE CITED Pakistan Environmental Protection Council, “National Environmental Quality Standards,” December 28, 1999. The Gazette of Pakistan, “Pakistan Environmental Protection Act 1997,” December 16, 1997. Ahmed, I., “Merox catalyst impregnation,” Merox Operating Manual. Kirmani, Z. U., A. Khurshid, N. Alam, N. Ahmed and S. Gul, “Crude incompatibility problems at heavy crude unit desalter,” Hydrocarbon Asia, July/August 2007, pp. 68–70.

BONUSREPORT

Mansoor Shafique is the assistant general manager in operations, at Attock Refinery Ltd. He has 34 years of experience in plant operations and has done two master startups. His main interests are plant optimization and value addition with minimum investment. He holds a BE degree in chemical engineering from the University of the Punjab.

Zia Uddin Kirmani is the manager of health, safety, environment and quality at Attock Refinery Ltd. He has more than 20 years of diversified experience in petroleum refining, fertilizer and paper industries. He has authored seven research publications in environment, petroleum and chemical fields. Mr. Kirmani holds master degrees in chemistry and business administration.

Amir Khurshid is the senior chemist for environment and quality at Attock Refinery Ltd. He has more than nine years of diversified experience in the field of quality control and environment. Mr. Khurshid holds an MS degree in chemistry from Quaid-i-Azam University, Islamabad.

Naveed Alam is the senior chemist at Attock Refinery Ltd. He has more than 11 years of diversified experience in the field of quality control and environment. Mr. Alam holds an MS degree in chemistry from Peshawar University.

Naveed Ahmed is a senior engineer in operations at Attock Refinery Ltd. He has 10 years of experience in plant operations and troubleshooting. Mr. Ahmed holds a BE degree in chemical engineering from Punjab University, Lahore.

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HYDROCARBON PROCESSING NOVEMBER 2009

I 71

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PROCESS ANALYZERS

Fine tune accuracy in analytic measurement—Part 2 Follow these recommendations for correct analyzer calibration D. NORDSTROM and T. WATERS, Swagelok Company, Solon, Ohio

System design. One common problem in calibration is incorrect system configuration. In many cases, the calibration fluid is mistakenly introduced downstream of the stream selection valve system and without the benefits of a double block and bleed (DBB) configuration (Fig. 1). A better place to introduce the calibration fluid would be through the sample stream selection system illustrated in Fig. 2. The purpose of a sample stream selection system is to enable rapid replacement of sample streams without the risk of cross-contamination. In Figs. 1 and 2 in the sample stream selection system, each stream is outfitted with two block valves and a bleed valve (to vent) to ensure that only one stream is making its way to the analyzer one at a time. Over the years, stream selection systems have evolved from DBB configurations composed of conventional components to modular, miniaturized systems (New Sampling/Sensor Initiative, ANSI/ISA 76.00.02). The most efficient systems provide fast purge times, low valve actuation pressures, and enhanced safety characteristics, together with high-flow capacity and consistent pressure drop from stream to stream for a predictable delivery time to the analyzer. A stream selection system provides the greatest insurance against the possibility of the calibration fluid leaking into a sample stream. Nevertheless, some technicians will bypass this assembly and locate the calibration fluid as close as possible to the analyzer with the intent of conserving this expensive fluid. If a single ball valve is employed, as in Fig. 1, the attempt to conserve calibration gas may result in biased analyzer readings. The analyzer may be properly calibrated, but there is the risk that a

small amount of calibration gas may leak into the sample stream and throw off the measurements. In some applications, the US Environmental Protection Agency requires that the calibration fluid be introduced at an early point in the sampling system, usually near the probe. The reasoning is that the calibration fluid should be subjected to the same variables as the sample stream. This makes good sense, and such a set up will provide, in addition, a fair estimate of the amount of time it takes for a sample to travel from the probe to the analyzer. As noted in the first article in this series, that time period is often underestimated or unknown. However, a relatively large quantity of calibration fluid is required if it is to run through the entire sampling system. It is not surprising that many facilities cannot entertain this option. A good compromise is to run the calibration fluid through the stream selection system, dedicating one stream to the fluid. Here

Analyzer

Calibration gas

n many analytical instrumentation systems, the analyzer does not provide an absolute measurement. Rather, it provides a relative response based on settings established during calibration, which is a critical process subject to significant error. To calibrate an analyzer, a calibration fluid of known contents and quantities is passed through the analyzer, producing measurements of component concentration. If these measurements are not consistent with the known quantities in the calibration fluid, the analyzer is adjusted accordingly. When the process samples are analyzed, the accuracy of the analyzer’s reading will depend on the the calibration process accuracy. It is imperative to understand how error or contamination can be introduced through calibration; when calibration can—and cannot—address a perceived performance issue with the analyzer; how atmospheric pressure or temperature fluctuations can undo the calibration work; and when and when not to calibrate.

Sampling conditioning system

To vent Stream selection system

Sample stream #1 FIG. 1

Sample stream #2

Sample stream #3

In this configuration, calibration gas is incorrectly introduced downstream of the stream selection system without the benefits of a DBB assembly. HYDROCARBON PROCESSING NOVEMBER 2009

I 73

PROCESS ANALYZERS

Analyzer

Sampling conditioning system

Bias

To vent Stream selection system

Sample stream #1

FIG. 2

Sample stream #2

Calibration gas

FIG. 3

As shown in this configuration, the calibration gas is best introduced through the sample stream selection system, where a DBB assembly guards against the risk of contamination.

it stands the best chance of reaching the analyzer without being contaminated by the sampling streams, and, when not in use, two block valves will prevent it from contaminating the sample streams. With miniature modular platforms, the calibration fluid amount required will be minimal. Calibration limitations. To effectively calibrate an analyzer, the operator, technician or engineer should understand, theoretically, what calibration is, what it can correct and what it cannot. Let’s start with the difference between precision and accuracy. A shooter’s target is a good metaphor for explanatory purposes. In Fig. 3, the shooter has produced a series of hits (in red) on the target. Since the hits are very close together in one cluster, it can rightly be said that the shooter is precise. Time and again, the shooter is hitting the target in the same place. Precision yields repeatable outcomes. However, the shooter is not hitting the target center and, therefore, has low accuracy. If the shooter makes an adjustment and lands all of the hits in the target center, the shooter is both precise and accurate. The same terms can be applied to analyzers. An analyzer must first be precise. It must yield repeatable results when presented with a known quantity in the form of a calibration fluid. If it does not, then the analyzer is malfunctioning or the system is not maintaining the sample at constant conditions. Calibration cannot correct for imprecision. If the analyzer produces consistent results but the results are not the same as the known calibration fluid composition, then the analyzer is said to be inaccurate. This situation can and should be addressed through calibration. This is called correcting the bias. 74

I NOVEMBER 2009 HYDROCARBON PROCESSING

The shooter is precise but not accurate. If the bias is corrected, the shooter will be both precise and accurate.

Even if the analyzer is found to be precise and accurate when tested with calibration fluids, it is still possible that it will yield inaccurate results when analyzing the sample stream. If the analyzer is programmed to count red molecules and it encounters pink ones, what does it do? The pink molecules look red to the analyzer so it counts them as red, resulting in an inflated red count. This is called positive interference: A molecule that should not be counted is counted because, to the analyzer it looks similar to the molecule that should be counted. For example, in a system designed to count propane molecules, propylene molecules may show up as well. It’s possible that the analyzer will count them as propane because it was not configured to make a distinction between the two. No analyzer is perfect, but they all strive for “selectivity,” which means they respond to just the molecules you want them to and not to anything else. Some analyzers are more complex and are programmed to chemically inhibit certain types of interference. For example, a total organic compound (TOC) analyzer is designed to measure carbon content in waste water so it can be determined if hydrocarbons are being disposed of inappropriately. To do so accurately, the analyzer removes a source of positive interference—such as inorganic carbons, like limestone, which are present in hard water. Then, it measures the organic carbons only. Without this initial step, the analyzer would measure both organic and inorganic carbon, confusing hydrocarbons with hard water. Another type of interference is negative interference: A molecule that should be counted isn’t counted because another molecule is hiding it. For example, in fluorinated drinking water, an electrode is used to analyze the fluoride amount in the water. However, hydrogen ions, which are common in drinking water, hide the fluoride so the count is inaccurately low. The analyzer may read 1 ppm, which is a standard dose, but, in fact, the water may contain 10 ppm. The solution is to remove the interference source. By introducing a buffer solution, the hydrogen ions are removed and the electrode can accurately measure the fluoride. With an understanding of positive and negative interference, as well as precision and accuracy, we begin to grasp the formidable challenges we face in enabling analyzers to yield desired results. In the field, you will often hear something like this: “The analyzer is not working. It needs calibrating.” There is an easy assumption

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4,' IFMQFE B SFÂ¾OFSZ SFEFÂ¾OF JUT NBJOUFOBODF TUSBUFHZ GPS NFDIBOJDBM FMFDUSJDBM BOE TUBUJD FRVJQNFOU 5IF QMBOU XBT BCMF UP DVU NBJOUFOBODF DPTUT CZ GPVS NJMMJPO FVSPT QFS ZFBS BOE BDIJFWFE B JODSFBTF JO BWBJMBCJMJUZ

5IF 1PXFS PG ,OPXMFEHF &OHJOFFSJOH XXX TLG DPN IQJ

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PROCESS ANALYZERS that if the analyzer is not producing the desired result, calibration is the answer. But as we have just seen, calibration has its limitations. It is not the answer to all problems. Controlling for atmospheric changes in gas analyzers. Gas analyzers are essentially molecule counters. When they

are calibrated, a known concentration of gas is introduced, and the analyzer’s output is checked to ensure that it is counting correctly. But what happens when the atmospheric pressure changes by 5–10%, as it is known to do in some climates? The number of molecules in a given volume will vary with the change in atmospheric pressure and, as a result, the analyzer’s count will change. There is a common misperception that atmospheric pressure is a constant 14.7 psia (1 bar), but, based on the weather, it may fluctuate as much as 1 psi (0.07 bar) up or down. For the calibration process to be effective, absolute pressure in the sampling system during calibration and sample analysis must be the same. Absolute pressure may be defined as the total pressure above a perfect vacuum. In a sampling system, it would be the system pressure as measured by a gauge, plus atmospheric pressure. To understand the degree of fluctuation in measurement that may be brought about by changes in absolute pressure, refer to the perfect gas law: PV = nRT where P = pressure, psia; V = volume, in.3; n = number of moles (molecules); R = gas constant; and T = absolute temperature, °F. Rearranging this equation to read n = PV/RT shows that as temperature and pressure change, the number of molecules pres-

ent in the standard volume also changes. Pressure changes are more critical than temperature fluctuations. One atmosphere of pressure is defined as 14.3 psi. Therefore, a 1 psi variation in pressure can change the number of molecules in the analyzer volume by about 7%. Temperature, on the other hand, is measured on the absolute scale, keeping in mind that absolute zero is –460°F (–273°C), so a 1°F (0.5°C) temperature variation changes the number of molecules by only about 0.3%. In summary, it is probable that one might get a large change in pressure in percentage terms. It is not probable that one would get a large temperature change in percentage terms. If pressure is so critical, how does one control for it? Some analyzers, especially infrared and ultraviolet, allow atmospheric pressure to affect the reading but then later correct for it electronically. However, many analyzers, including nearly all gas chromatographs, do not correct for atmospheric pressure fluctuations; most systems do not correct for it, and many system engineers or operators are satisfied to ignore it. Some believe that atmospheric fluctuations are not significant. Others maintain that any atmospheric fluctuations are compensated for by other related or unrelated variables affecting the analyzer, and it all comes out in the wash. Nevertheless, atmospheric fluctuations can be extremely significant. Let’s suppose that, when you calibrate your analyzer, the atmospheric pressure is X, but, later, when you inject the process gas, the atmospheric pressure is X + 1 psi (0.07 bar). The answer may be as much as 7% off the measured value. With environmental regulations, most analyzer systems now vent to flare stacks or other return points. Since pressure fluctua-

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tions from such destinations will affect pressure upstream in the analyzer, there are vent systems, equipped with educators and regulators, designed to control for these fluctuations. Unfortunately, these systems employ regulators that are referenced to atmosphere. As a result, while these systems control for fluctuations from the vent, they do not control for fluctuations in atmospheric pressure, which, by far, could be the greater of the two sets of fluctuations. For such a system to control for atmospheric as well as vent pressure fluctuations, an absolute pressure regulator is required. Unlike a normal regulator, an absolute pressure regulator is not comparing pressure inside the system to pressure outside the system, which is itself fluctuating according to the weather. Rather, it is comparing pressure inside the system to a constant set pressure that does not fluctuate at all (or very little). Often, this set pressure is actually 0 psia (0 bar).

to perform this process properly. The operator, technician or engineer should understand how best to introduce the calibration gas into the system (i.e., through a DBB configuration so that the possibility of cross-stream contamination is minimized) and how to control for atmospheric fluctuations in gas analyzers (i.e., through an absolute pressure regulator). Further, the technician or operator should understand the calibration limitations—what problems it can address and what problems it cannot—and how frequent adjustments to the analyzer based on incomplete data can introduce error. If the analyzer is regularly validated with an automated system and is properly calibrated when a statistical analysis justifies it, then calibration will function as it should, and will provide an important service in enabling the analyzer to provide accurate measurements. HP Next month: Part 3. The article will

Validation vs. calibration. The best

method for calibration is one that employs an automated system of regular validation, with statistical process control. Validation is the process of checking the analyzer at regular time intervals to determine whether it is on or off the target. In validation, a reading is taken and that reading is recorded. It is the same process as calibration, except that no correction is made. An automated system will run a validation check at regular intervals, usually once a day, and analyze the outcome for any problem that would require an adjustment or recalibration. The system will allow for inevitable ups and downs, but if it observes a consistent trend—one that is not correcting itself—then it alerts the operator that the system could be going catastrophically wrong. A human being can manually validate a system at regular intervals, just like an automated system, but, more often than not, the human being will also make an adjustment to the analyzer, even if the system is just 1% off. The result is a series of occasional and minor adjustments that introduce additional variance and make it difficult to analyze trends and determine when the system is truly running off course. It is better to allow an automated system to run unattended until a statistical analysis of the results suggests that attention is required. Conclusion. Calibration is an impor-

tant process and an absolute requirement in analytical systems, but care must be taken

discuss major issues leading to an unrepresentative sample and provide recommendations on how to avoid a compromised sample. Items covered will be: dead legs and dead spaces; component design and placement; adsorption and permeation; internal and external leaks; cross contamination in stream selection; and phase preservation.

Doug Nordstrom is the marketing manager for analytical instrumentation at Swagelok Company, focusing his efforts on advancing the company’s involvement in sample handling systems. He previously worked in new product development for Swagelok and earned a number of Swagelok patents in products including the SSV and MPC. Mr. Nordstrom graduated with a BS degree in mechanical engineering from Case Western Reserve University and with an MS degree in business administration from Kent State University.

Tony Waters has 45 years of experience with process analyzers and their sampling systems. He has worked in engineering and marketing roles for an analyzer manufacturer, an enduser and a systems integrator. Mr. Waters founded three companies that provide specialized analyzer services to the process industries and he is also an expert in the application of process analyzers in refineries and chemical plants. He is particularly well known for presenting process analyzer training courses in Asia, Europe and the Middle East, as well as in North and South America.

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REFINING DEVELOPMENTS

Hydrocracking solutions squeeze more ULSD from heavy ends New processing alternatives enable upgrading vacuum residuals into higher-value products F. MOREL, J. BONNARDOT and E. BENAZZI, Axens, Rueil-Malmaison, France

espite the present economic crisis, demand for diesel fuels is forecast to increase through 2020, albeit at a slower rate. Various forecasts indicate that world demand for diesel fuels should reach about 28.2 million bpd (MMbpd) by 2020 as compared to the present demand of 24.3 MMbpd. It is foreseen that the gap between demand for diesel and gasoline, which during 2008 was 2.6 MMbpd, will double to approximately 5 MMbpd by 2020. Diesel market. There are two elements within the diesel market: off-road, and on-road sales. Off-road sales relate to diesel for marine inland waterways, for heating, and for locomotives and tractors. This market is expected to experience an annual 0.4% growth rate. On-road use of diesel fuel for light-duty vehicles (LDVs), heavy-goods vehicles (HGVs) and buses is anticipated to increase 1.8% annually through 2020. Off-road diesel consumption will decline as a proportion of total sales. By 2020, off-road diesel usage will represent only 40% of the global market, compared to 58% in 1990. This change is mainly due to reduced gasoil consumption for domestic heating (Fig. 1). Worldwide on-road diesel consumption is essentially due to freight movement via trucks. In 2008, HGVs accounted for 74% of diesel purchases, with buses and LDVs each consuming 13%

(Fig. 2). By 2020, demand is projected to expand by 24% and reach 16.8 MMbpd. Within this increase, fuel consumption by LDVs will have grown by 82%, and will account for 19% of total demand. Asia-Pacific and EU-25 regions’ fuel demand. The

highest demand growth for diesel is expected in Asia-Pacific and EU-25 regions, expanding by 0.7 MMbpd and 1.04 MMbpd, respectively, over a 12-year period (see Fig. 3). Consequently, the worldwide ratio of gasoline to on-road diesel will decrease from 1.9 in 2000, to about 1.3 by 2020. Europe will continue its established trend, falling to a very low ratio of 0.4. Conversely, North America will remain a gasoline-oriented marketplace. Specifications will continue to be tightened, with an on-road ultra-low-sulfur diesel (ULSD) with less than 10 parts per million (ppm), low polyaromatics content and high cetane. These requirements appear necessary to meet the environmental targets for nitrous oxide (NOx) and particulate matter (PM) imposed on engine emissions in regions such as Europe. During the next 15 years, sulfur will virtually disappear from all diesel fuels. To complete the fuel market picture, jet fuel demand will increase, while heavy-fuels demand will diminish. Differential price between diesel and heavy fuel oil will continue to make resid and vacuum gasoil (VGO) hydrocracking processes attractive opportunities. The challenge will be to produce more quality middle distillates, to convert refractory feeds and to upgrade lower-quality refinery streams.

Worldwide diesel/consumption, %

100 On-road diesel t -JHIU EVUZ WFIJDMFT -%7T t )FBWZ HPPET WFIJDMFT )(7T

t #VTFT

80 60

AAGR 08–20 +1.8 %/y

58% 40 20 0 1990

44%

Off-road diesel t .BSJOF t 3BJMXBZT t )FBUJOH PJM t 0UIFST 1995

AAGR 08–20 +0.4 %/y

2000

2005

2010

13%

2020

*LDVs = Passenger cars (PCs) + sports utility vehicles (SUVs) + light trucks (LTs) Source: Axens & other sources (2009)

FIG. 1

Worldwide on-road and off-road diesel consumption.

19%

13%

40%

2015

10%

Heavy goods vehicles (HGVs) Buses Light-duty vehicles (LDVs)

+24%

71% 2020: 16.8 MMbpd

74% 2008: 13.5 MMbpd *LDVs = Passenger cars + Sports utility vehicles + Light trucks Source: Axens (2009), World Business Council for Sustainable Development (2004)

FIG. 2

Worldwide on-road diesel demand.

HYDROCARBON PROCESSING NOVEMBER 2009

I 79

REFINING DEVELOPMENTS Technical way forward. Hydrocracking technology offers an excellent solution to these issues that can upgrade a variety of feedstocks to be upgraded, including VGO from conventional and heavy crude, deasphalted 0.10 MMbdoe oil (DAO) from solvent deasphalting (SDA) FSU unit of vacuum residue (VR), coker distil0.7 MMbdoe lates, light-cycle oil (LCO), and heavy-cycle 0.41 MMbdoe Europe oil (HCO) from fluid catalytic cracker (FCC) North America units and vacuum distillates from vacuum 0.46 MMbdoe resid (VR) hydrocracking units (Fig. 4). 1.04 MMbdoe 0.29 Middle East Depending on the feedstock impuriAsia Paciﬁc MMbdoe ties and conversion level required, several Africa 0.29 MMbdoe proven hydrocracking processes can proLatin America vide upgrading from low to medium conversion through high to full conversion and Global on-road diesel incremental yields of high-quality middle distillates. demand 2008–2020 + 3.3 MMbdoe Source: Axens There is no universal solution. So, different hydrocracking technologies are required to FIG. 3 On-road diesel incremental demand. meet various refinery conversion needs. Mild-hydrocracking. For example, a mild hydrocracking process integrated with a finishing middledistillate hydrotreater can upgrade VGO and DAO -based feeds, Crude Topping LCO and light and heavy coker gasoil (LCGO and HCGO) oil streams. This process increases the refinery’s ULSD production while minimizing capital expenditure (CAPEX). In addition, VGO unconverted VGO is an excellent FCC feedstock, having a lower CFHT* FCC MHC** sulfur and higher hydrogen content. High-pressure high-conversion hydrocracking processes. To Hydrocracking Vac. dist. achieve higher conversion levels, a high-pressure (HP) high-converLCO sion fixed-bed hydrocracking can provide full conversion of VGObased feedstocks, HCGO, or light C3 or C4-DAO, mainly to topquality middle-distillate products. This method can upgrade FCC Residue RDS*** effluents such as LCO and HCO. The technology can be engineered FCC Ebullated bed for liquid recycle, one-stage and two-stage processes. HP high-conhydrocracking VR version fixed-bed hydrocracking processes have successfully produced ULSD from VGO when integrated with a VR hydrocracking unit. DAO Ebullated bed SDA Ebullated-bed technology can be applied for deep conhydrocracking DAO version of high refractory feedstocks such as C5-DAO-based HCGO feeds—particularly difficult VGOs mainly converting them to *CFHT = Cat feed hydrotreating; Pitch **MHC = Mild hydrocracking middle distillates. ***RDS = Residual desulfrization unit In addition, new-generation hydrocracking catalysts have been FIG. 4 VGO and residue conversion processes. developed for a wide range of feedstock characteristics, product

Conradson Carbon Residue in feed, %

TABLE 1. Arabian heavy derived feeds Heavy DAO-based feeds MHC with guard bed

Ebullated bed hydrocracking

Integrated hydrocracking/ hydrotreating Low asphaltene VGO/DAO feeds

FIG. 5

40 50 60 70 Net conversion, %

VGO and DAO conversion mapping.

LCO

—

0.943

0.945

0.996

Sulfur, wt%

3.36

0.13

4.45

Nitrogen, ppm

1,550

100

2,600

Sp. gr.

Mild hydrocracking

VGO + HCGO Yield on VR, wt%

C5 DAO

Conradson carbon residue, wt%

< 0.1

Nickel + vanadium, ppm

< 0.1

< 0.05

< 0.05 529

C7 insolubles, wt% ASTM distillation, °C 100

T 5%

366

239

T 50%

459

281

T 95%

555

350

Note: The VGO–HCGO blend is a typical hydrocracking feed containing 24% HCGO.

I NOVEMBER 2009 HYDROCARBON PROCESSING

REFINING DEVELOPMENTS TABLE 2. The refractory nature of diesel from MHC is due to high nitrogen and aromatics contents Lights, naphtha

VGO

Diesel HDT

Diesel from CDU, FCC, VB, coker, etc.

FIG. 6

Low S VGO

10 ppm S diesel to stripping

Integrated MHC and diesel hydrotreater process.

SR diesel already hydrotreated

Converted diesel from MHC

Sulfur, ppm

265

340

4,6-DBT, % of total sulfur

37.4

35.7

Nitrogen, ppm

254

Aromatics, wt%

TABLE 3. Mild hydrocracking product results VGO section

Polishing section

0.9317

0.889 2.0

Feed Characteristics Sp. gr. Sulfur, wt%

2.67

Nitrogen, ppmw

1,392

TBP cut point, °C

350–570

200–360

Yields vs. feed, vol%

slates and quality targets. These catalysts can maximize diesel selectivity, improve diesel and jet fuel quality, as well as upgrade the quality of the unconverted bottoms for lube-oil production. Guidance for selecting these technologies is listed in Fig. 5. The X-axis represents the conversion level. The Y-axis defines the refractory level of the feedstock to be converted, expressed as Conradson Carbon Residue (CCR) content. VR hydrocracking and residue desulfurization technologies will not be discussed in this article. Integrated solution for ULSD production. Conven-

tional mild hydrocracking (MHC) has a low to medium conversion rate within typically 20% to 40% of the feedstock being converted mainly to diesel. Unconverted oil is a high-quality FCC feedstock producing higher gasoline yields, higher octane retention and low-sulfur products. Although providing remarkable improvements in FCC operations, MHC is not a panacea. The low hydrogen partial pressure (typically, 40 bar to 80 bar) do not achieve a ULSD below 10 wt ppm. The diesel obtained, owing to higher aromatics and organic-nitrogen content, is more refractory to hydrotreating than straight-run (SR) diesel and requires further hydrotreating. This has resulted in the integrated MHC development. The integrated MHC process resolves the problem by disassociating the quality of the diesel cut from the conversion level, thereby achieving ULSD specifications while avoiding the production of over-quality FCC feed. Table 2 shows the higher aromatics and organic nitrogen species between MHC and SR diesel, which inhibit hydrodesulfurization reactions, making it more suitable for refractory than for further hydrotreating.1 In the integrated MHC process flow diagram (Fig. 6), VGO feedstock is fed to the MHC reaction section. The reactor effluent is stripped and fractionated. The hydrotreated VGO cut is dispatched to the FCC unit or storage, while the MHC diesel receives the entire hydrogen make-up required for both reaction sections, after which it is polished with the reactor in a oncethrough mode. The highest hydrogen partial pressure within the polishing reactor enables to convert the highly refractory nitrogen and sulfur compounds remaining in the hydrocracked diesel cut. Regardless of operating variations in the MHC section, diesel quality is guaranteed to remain constant throughout the entire process

Naphtha

3.4

0.5

Diesel

28.7

99.0

Hydrotreated VGO

70.7

—

H2 consumption, wt%

1.17

1.08

HDT VGO (FCC feed) properties

Diesel properties

Sp. gr.

0.897

< 0.845

Sulfur, ppm

< 400

< 10

Cetane number

—

> 51

Hydrogen, wt%

13.0

—

cycle. Disassociating diesel quality from the MHC operation makes it possible to improve other characteristics such as density or polyaromatics content. In engineering terms, the integrated MHC process eliminates two compressors and an air cooler, while providing better heat integration than would two separate units. Systems can be designed to co-process other difficult refinery feedstocks, typically LCO, LCGO and visbroken GO. Commercial experience. Over 40 MHC units have been licensed four of which use integrated diesel hydrotreating techniques. CAPEX ranges between $1,700/bbl and $3,200/bbl depending on capacity, feedstock properties and conversion levels. Table 3 lists the results of a commercial integrated MHC unit using a blend of heavy VGO from Arabian/Russian crude, operating at 30% conversion and processing at the same time in the integrated polishing section a blend of heavy SRGO with LCO. The diesel cut exiting the VGO section is not inline with Euro V specifications. This diesel cut is then co-hydrotreated in the polishing section with a blend of LCO and heavy SRGO. The final diesel cut achieves Euro-V specification with a specific gravity lower than 0.845, a cetane number higher than 51 and a sulfur content under 10 ppm. The unconverted oil (UCO) is used as an FCC feedstock, with hydrogen content of 13 wt% providing a gasoline production boost to the FCC of about 14 wt%. Additional UCO hydrogen content would only lead to a small increase in gasoline yield. In that case, the integrated MHC technology can produce at the same time, optimum feed to FCC and Euro-V specification diesel stream while minimizing CAPEX and hydrogen consumption. HYDROCARBON PROCESSING NOVEMBER 2009

I 81

REFINING DEVELOPMENTS FG/LPG

FG/LPG

Naphtha CCR/Isom

Naphtha pool/CCR Feed

Integrated hydrocracking/ hydrotreating

HDT

Kerosine Jet A1 SEP

Feed

Diesel Euro V

Fixed-bed hydrocracking

HDT

Kerosine Jet A1 SEP

Frac

Diesel Euro V Frac

2nd stage Purge

Liquid recycle Single-stage high-pressure hydrocracking process once-through or with liquid recycle.

FIG. 7

HDT1

SEP1

FG/LPG

HDT2

Integrated reaction section

Hydrocracking

H2S + NH3

Feed

Fixed-bed hydrocracking FIG. 9

Kerosine Jet A1 Diesel Euro V

Frac

FIG. 8

Two-stage high-pressure hydrocracking process.

Single-stage once-through configuration. Feedstock flow is sent through two reactors in series containing hydrorefining and hydrocracking catalysts, respectively. Up to 90% feedstock conversion is attained, as shown in Fig. 7. When needing to process feedstocks with nitrogen content of 5,000+ ppm, the refining technology licensor proposed the addition of a hydrotreatment reactor and separator, to reduce ammonia pressure in the main process section, can be installed to maximize hydrocracking activity (Fig. 8). Single-stage with liquid recycle. By recycling unconverted residue to the hydrocracking reactor (Fig. 7) a full-conversion level can be reached. Conversion-per-pass is typically around 60 vol%, and higher selectivity to middle distillation is achieved compared to a once-through configuration. A small purge prevents heavy polynuclear-aromatics (PNAs) accumulating in the recycle oil loop. Two-stage hydrocracking. The first stage operates as a oncethrough process for a mild conversion, and the unconverted fraction is separated for second-stage processing (Fig. 9). The process offers a maximum yield of middle distillates, along with a good diesel vs. kerosine ratio.

Naphtha pool/CCR

SEP2

UCO Lube oil

Single-stage high-pressure hydrocracking process using once-through with intermediate separation.

High-conversion hydrocracking solutions. The HP

high-conversion, fixed-bed hydrocracking technology is appropriate when maximizing middle distillate production from VGO and light DAO, and it can provide excellent characteristics and high conversion rates for distillates. Twenty-five HP high-conversion, fixed-bed hydrocracking units, including all three configurations, have been licensed. Investment cost per barrel of feedstock is $4,100 to $6,700. The choice of configuration is determined by product slate and investment strategy.

Case study—three process configurations. The three

TABLE 4. HP high-conversion fixed-bed hydrocracking results Feed Scheme Conversion% Yields vs. feed, vol%

VGO + HCGO 1-stage Once-through

VGO+HCGO+LCO 1-stage Once-through

VGO + HCGO 1-stage Recycle

VGO + HCGO 2-stage

Full

Base Naphtha

30–35

Base -2

Base +0.5

Base -8

Middle distillate (kerosine + diesel)

65–70

Base +2

Base +15

Base +24

UCO H2 consumption, wt%

14–20

Base -3

2.5–2.9

Base +0.2

Base +0.1

Middle distillate properties (kerosine + diesel) Sp. gr.

0.820

0.829

0.823

0.826

Sulfur, ppm

< 10

Cetane number UCO properties

Sp. gr.

0.835

0.838

Sulfur, ppm

< 50

Hydrogen, wt%

14.3

BMCI

< 10

Viscosity Index after dewaxing

> 120

I NOVEMBER 2009 HYDROCARBON PROCESSING

Purge

different process configurations were compared using the VGO + HCGO feedstock, as defined in Table 1. In all instances, the middle distillate products, including kerosine, jet fuel and a ULSD cut, surpassed the international specifications. Table 4 lists the yields and product properties. Single-stage once-through configuration. This is the lowest-cost configura-

tion and it provides high yields of naphthaplus-middle distillates along with UCO. With a typical octane of 80, the light naphtha is sent to the gasoline pool, while the heavy naphtha, with a naphthene content of over 50%, makes an excellent catalytic reforming feedstock. Middle distillates yield typically is between 65 vol% and 70 vol% and meets ULSD specifications. The product can be divided between on-specification kerosine with a smoke point of 25 mm, and heavy diesel with a cetane number higher than 60 (Table 4, column 1).

REFINING DEVELOPMENTS

THE

UCO with a Bureau of Mines Correlation Index number less than 10 is indicative of a highly hydrogenated product that can be used as a steam-cracker feedstock.2 After dewaxing, UCO exceeding 120 on the viscosity index is suitable as a Group III lube oil base stock. To meet middle distillates demand, some refineries maximize LCO production from the FCC unit, despite needing to upgrade the LCO before being blended with the diesel pool. One solution is to co-process LCO with a VGO-based stream in the same hydrocracker. LCO content in the feedstock depends on the capacity of the FCC and HP high-conversion, fixed-bed hydrocracking units. Column 2 of Table 4 indicates yields FIG. 10 Comprehensive reaction progressâ&#x20AC;&#x201D;3D gas chromatography. and products obtained when 20% LCO is blended with VGO+ HCGO, and hydrocracked in a once-through mode. Most of the LCO remains as able for full-feed conversion. Each produce similar volumes middle distillate, with the rest converted to naphtha. The overall of C5+, but the two-stage configuration yields a higher diesel/ gasoline quantity is reduced, with middle distillate yields increased kerosine ratio. as compared to the previous case. The cetane number of the With the single-stage and liquid recycle scheme, the middle middle distillate is lower, but it remains acceptable. Hydrogen distillates yield is typically 80 vol% to 85 vol%, and the qualconsumption is marginally higher, owing to the higher aromatic ity remains high. A small purge is needed to prevent heavy PNA level in the LCO stream. concentration in the recycle loop, and the purge can subsequently be processed as part of the FCC feedstock, or as feed for a steam Single-stage configuration with liquid recycle. cracker. Hydrogen consumption is slightly higher than consumpSingle-stage recycle and two-stage configurations are both suittion for the once-through configuration.

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HYDROCARBON PROCESSING NOVEMBER 2009

I 83

REFINING DEVELOPMENTS

Gas to hydrogen separation and puriďŹ cation 1st stage

2nd stage

3rd stage

Common HP To FG and MP amine PSA and MPU

Common makeup compressor

Catalyst addition Separator

H2 rich gas

Oil to separation and fractionation

VGO VDU

VGO full conversion ďŹ xed-bed hydrocracking

VGO separation and fractionation

Ebullated-bed hydrocracker reactor

Separation and fractionation

Ebullated-bed hydrocracker

Naphtha Euro V ULSD

VGO VR

FIG. 11

Naphtha and gasoil LSFO

Catalyst withdrawal

Ebullating pump

Hydrogen

Simplified scheme for ebullated-bed VR hydrocracking with VGO hydrocracking.

Feed FIG. 13

Ebullated-bed hydrocracking reactor system.

FG SRGO

CDU VGO

LPG

HDT

C3=

Integrated FCC

Fixed-bed hydrocracker

VDU

VGO

Ebullated-bed hydrocracker

Naphtha Gasoline Middle distillate LSFO

HCO Existing/revamped New

Middle distillate 52% FIG. 12

C3 1% LPG 7% LSFO 7% 33% Naphtha and gasoline

Refinery configuration selected.

better UCO characteristics in high VI base lube oil production. Very high activity and selectivity coupled with full conversion, even with refractory feedstocks, are provided by a new generation of zeolite-based catalysts (HYK series) as shown in Fig. 10. Product quality remains excellent throughout the cycle without a noticeable change in cetane number, or kerosine smoke point. Depending on the level of metal and other impurities in the feedstock, a demetallization catalyst could be required at the top of the first reactor to ensure long cycle length. Knowledge of inhibiting species, refractory compounds, and feedstocks is necessary to determine pretreatment operating conditions and select the most adapted catalysts. An understanding of the relative kinetic reactivity of feedstock molecules is desirable to accurately tune the hydrogenation/acidity balance, which improves middle distillate selectivity and qualities (Fig. 10). These are key parameters for a successful unit design and catalyst selection providing higher operability and profitability. Integrating high conversion VGO hydrocracking process with VR hydrocracking technology. Residue

Two-stage hydrocracking configuration. This configuration provides an optimum yield of middle distillates that can surpass 90 vol% with a maximum share of diesel in middle distillates. Product quality exceeds the fuel specifications. A limited purge is needed, and hydrogen consumption is similar to other configurations. Hydrocracking catalyst developments. A typical

hydrocracker can use three new-generation catalysts developed to treat a wide variety of feedstocks for the production of diverse product slates, with high quality outcomes.3 Hydrorefining catalysts are highly stable and promote hydrodenitrogenation (HDN) reactions to protect the downstream hydrocracking catalysts. They also ensure hydrodesulfurization (HDS) and aromatic saturation reactions.4 Amorphus hydrocracking catalysts (HDK series) offer high cracking activity and excellent selectivity, while being very active for removing the ultimate organic nitrogen compounds. These catalysts orient selectivity toward middle distillates, and create 84

I NOVEMBER 2009 HYDROCARBON PROCESSING

hydrocracking processes use ebullated-bed technology to manage heavy feedstock containing high metal traces, sulfur, nitrogen, asphaltenes and solids. They can achieve conversion without producing coke material. The VR ebullated-bed hydrocrackers reactor converts over 75% of residue, while producing high-quality distillate VGO, and unconverted bottoms that can be incorporated to low- or mediumsulfur fuel oil storage. Further hydroprocessing units are necessary to upgrade primary products from residue hydrocracking. Integrating HP high-conversion, fixed-bed hydrocracking methods with ebullated-bed technology is an interesting solution to convert both VGO resulting from residue hydrocracking and SR VGO into diesel (Fig. 11). This solution is based on an optimized management of the high-pressure pure hydrogen network feeding the two hydrocracking units and including the amine section. The developed solution can reduce CAPEX, while guaranteeing flexibility and independent operation. The VGO and VR hydrocracking units are both equipped with a separa-

REFINING DEVELOPMENTS tion and fractionation section, thus maxi- TABLE 5. Hydroconversion of mizing diesel production. This is owing to heavy DAO with ebullated-bed the full recovery of VGO coming from the hydrocracking process VR hydrocracking unit (no loss in the fuelC5 DAO oil cut), the absence of ammonia and light Feed technology hydrocarbons, and no asphaltene carryover from the ebullated-bed hydrocracking Yields vs. DAO Feed, vol% Naphtha 10.3 unit to the integrated hydrocracking/ Middle distillate (kerosine + diesel) 49.6 hydrotreating unit.

and will reduce low-sulfur fuel oil (LSFO) production to 7%. Hydrocracking DAO. Using DAO

streams from the SDA unit can increase product output. Blended with VGO, C3 to C5–DAOs can be processed using modified MHC and integrated hydrocracking/ hydrotreating technologies with adapted operating conditions. In case the heavier VGO 40.7 East European case study. The ebulC5–DAO contains high metal traces (often Vacuum residue – lated-bed/hydrocracking integrated con- H consumption vs. DAO feed, wt% above 50 ppm) and a the CCR exceeds 10 3.03 figuration was chosen by an East European 2 wt%, the ebullated-bed hydroconversion unit 33.5 refiner. The objective is to obtain a 70% VR Yield of asphalt vs. VR feed, wt% is more adapted to produce light products. Middle distillate properties conversion so as to maximize Euro V diesel The DAO ebullated-bed hydroconversion Sp. gr. 0.865 production and to produce a heavy fuel oil unit is the equivalent of the VR ebullated-bed with less than 1% sulfur. Sulfur, ppm < 300 hydrocracker unit. The ebullated-bed hydrocracking unit DAO ebullated-bed hydrocracking Cetane number 45 will process 43,000 bpd of VR with a sulfur VGO properties requires online catalyst replacement and is content of 2.9%, plus nickel and vanadium designed for both heavy VGO and DAO Sp. gr. 0.910 metal traces of approximately 350 ppm. The conversion. The typical investment is Sulfur, wt% < 0.20 approximately $4,500 to $5,500 per barrel integrated hydrocracking/hydrotreating unit Hydrogen, wt% 12.5 is designed to treat 36,000 bpd of a blend of feedstock. CCR, wt% < 0.5 of SR VGO and VGO produced within the The process uses one or several ebullatedebullated-bed hydrocracking unit. bed reactors in series with an upward fluid Nickel + vanadium, ppm < 0.1 Fig. 12 also shows the benefit of upgradflow (Fig. 13). A circulation pump maintains ing HCO produced by the existing FCC unit. The investment the catalyst in optimum mix and suspension, with a constant low will allow the refinery to increase its Euro V diesel and middle pressure drop. The bed is backward-mixed in terms of both catalyst distillates production, which represents 52% of the crude oil, movement and reactor liquid composition. Continuous move-

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HYDROCARBON PROCESSING NOVEMBER 2009

I 85

REFINING DEVELOPMENTS ment of the catalyst grains and the DAO to lighter products, VR DAO an isothermal temperature profile such as gasoline, diesel and Ebullated-bed (100) (89) Products (74) SDA at 75% inside the reactor mitigate cataVGO, with only a slight increase hydrocracker at DAO lift 85% conversion lyst bed plugging as compared in asphalt yield (Fig. 14). to a fixed bed. Higher reactor Asphalt (26) temperatures can be maintained Case study: Combining Overall conversion on Ural feed: 74% residual ebullated-bed in a moving bed system than in Unconverted DAO (15) hydrocracking and SDA. the fixed type, with the former achieving a higher conversion of FIG. 14 SDA plus residual ebullated-bed hydrocracking recycle Table 5 provides performance scheme. feedstock to light fractions. Condetails of C 5 -DAO derived version levels over 80% can be from Arabian Heavy crude proachieved by balancing operating cessed through an ebullated-bed temperature, residence time and catalyst replacement rates, and hydrocracker. The net conversion levels of 80% can be achieved hydrodesulfurization (HDS) levels of 90% to 98% are obtained. from a single-stage, once-through ebullated-bed hydrocracker. Controlling conversion and the HDS activity level in the reacHowever, unconverted DAO, using VR product, would not be tor is obtained by continuous catalyst renewal from the top of the highly upgraded, and could only be used as low-grade-sulfur reactor, and a discharge unit at the bottom. Adding small daily fuel oil. A more attractive option is to recycle the low asphaltene quantities of catalyst to the ebullated-bed reactor is a key feature content VR product to the SDA unit along with fresh VR feed. that promotes constant product quality. Unlike a fixed-bed system, This will lead to a slight increase in asphalt production from the unit’s operating period is not a function of catalyst activity or 30% to 33.5%. pressure drop across the bed; rather, it is is determined by inspecThe major benefit of the recycling scheme is the total elimition and turnaround schedules set at between 24 and 36 months. nation of heavy DAO and VR through conversion into higher Catalysts with high mechanical properties have been developed value products, as shown in Table 5. The small volume of availto minimize fines production; achieve high HDS activity, metals able naphtha is a good reformer feedstock. Although the middle removal and retention capacity; and ensure selective conversion distillate (50 vol% yield) has an acceptable cetane level, further of DAO into diesel-boiling fractions. treatment in an integrated hydrotreater is required to obtain a During the processing of C4 and C5–DAO, one option is to ULSD cut. With its low-sulfur content and a good hydrogen level, recycle unconverted VR fractions blended with fresh VR in the the VGO can be sent to the FCC or VGO hydrocracker to further SDA unit. This scheme succeeds in the near full conversion of increase middle distillate production.

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Heinz Bloch—Maintenance and Reliability Trends in the Refining, Petrochemical, Gas Processing and LNG industries Watch as Hydrocarbon Processing’s Reliability/Equipment Editor Heinz Bloch is interviewed by Editor Les Kane, in his first webcast on maintenance and reliability trends in the refining, petrochemical, gas processing and LNG industries. In these tough days of narrow refining margins, refiners have to do more with less and create greater efficiency with a smaller pool of capital expenditures. This is not impossible, but it is challenging. Heinz Bloch addresses these issues head on in this timely and informative webcast. Heinz advises participants on his belief system for effective reliability engineering, pulling no punches as he describes his view that adding value requires effort and doing the right thing is very seldom the easy thing. Heinz, as an editor for Hydrocarbon Processing for 10 years, has built a dedicated following worldwide in his area of responsibility. He holds six U.S. patents and has authored over 460 technical papers and 17 books on machinery. He was an Exxon Chemical Co. machinery specialist and held positions worldwide before retiring after 24 years with Exxon. He has a deep personal and technical understanding in the area of maintenance and reliability and current trends. To view this exciting, one-of-a-kind event for the HPI, visit www.hydrocarbonprocessing.com/blochwebcast0909 to register for the on-demand webcast that was held on September 10, 2009. For questions about future Hydrocarbon Processing Webcasts, contact Bill.Wageneck@Gulfpub.com. Sponsored by |

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REFINING DEVELOPMENTS Squeezing more from the bottom of the barrel. Dif-

ferent process alternatives are available for hydrocracking of VGOs, HCGOs and DAOs, wherein the options are a function of the demand for specific finished products and CAPEX constraints; 1. Mild hydrocracking with an integrated finishing hydrotreater can upgrade VGO-based feedstocks, enabling production of low-sulfur FCC feed while producing additional ULSD and constraining low-sulfur gasoline output. 2. The high-conversion fixed-bed hydrocracker produces near full conversion of VGO-based feedstocks to top-quality middle distillate products. 3. Integrated with a residue hydrocracker, the high-conversion fixed-bed hydrocracker can maximize ULSD throughput and reduce the refinery’s fuel oil output. 4. Ebullated-bed technology is adaptable for deep conversion of refractory feedstocks such as C5-DAO-containing feeds. Adding a SDA unit ensures nearly full conversion of the DAO into lighter products with only a marginal increase in asphalt yield. HP 1

LITERATURE CITED Sarrazin, P., J. Bonnardot, C. Guéret, F. Morel and S. Wambergue, “Direct Production of Euro-IV Diesel at 10 ppm Sulfur via HyC-10™ Process,” ERTC, Prague, Nov. 15–17, 2004. Fernandez, M., J. Bonnardot, F. Morel and P. Sarrazin, “Advantageously Integrating a High Conversion Hydrocracker with Petrochemicals,” ERTC, London, Nov. 17–19, 2003. Benazzi, E., L. Leite, N. Marchal-George, H. Toulhoat and P. Raybaud, “New Insights into Parameters Controlling the Selectivity in Hydrocracking Reactions,” Journal of Catalysis, Vol. 217, No. 2, pp. 376-387, July 25, 2003. Axens website—www.axens.net

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Frederic Morel is product line manager for VGO and resid conversion. Mr. Morel is working at Axens in technology department as a product line manager for VGO and resid conversion. He was formerly manager of Axens Hydroprocessing and Conversion Technical Services. He has 30 years of experience in oil refining, having worked previously with IFP Lyon Development Center as a research engineer, as a project leader of distillates and residues hydroprocessing and as development department manager. Mr. Morel holds a degree in chemical engineering from Ecole Supérieure de Chimie Industrielle de Lyon and a graduate degree from Institut d’Administration des Entreprises.

Jérôme Bonnardot is deputy product line manager for VGO hydroconversion. Dr. Bonnardot joined IFP in 1994 as research engineer at its Lyons Development Center. He moved to Axens in 2001 where he began as a process design engineer in the field of distillates hydroprocessing and hydroconversion, and technical manager for hydrocracking technology, before attaining his current position. Dr. Bonnardot is a graduate of the Ecole Supérieure de Chimie Industrielle de Lyon (ESCIL). He holds an MS degree in chemistry from the University of Notre Dame (USA) and received his PhD from the Université de Lyon (France).

Eric Benazzi is Axens’ marketing director. He has over 21 years experience in catalysis applied to fuels and petrochemicals. Dr. Benazzi joined Axens in 2004 as strategic marketing manager in charge of market analysis, business planning and acquisition evaluation. He started his professional career as a research engineer at IFP, where he worked in the field of catalysis, specializing in zeolites and in hydrocracking processes. Later, he moved to the economic department, where he was responsible for investment profitability studies for refining and petrochemicals projects. Dr. Benazzi holds a PhD in chemistry from the University of Paris, and he graduated as a chemical engineering from the ENCSP.

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BOXSCORE DATA BASE

ONLINE

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2009

NEW PROJECTS BEING ADDED AT A RATE OF 40 PER WEEK!

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ENGINEERING CASE HISTORIES

Case 53: Electrical faults can cause shaft and gear failures This technique allows transient torques in geared units to be determined T. SOFRONAS, Consulting Engineer, Houston, Texas

hen power disturbances occur such as grid switching or short circuits, motors or generators can experience a sudden speed variation due to unloading and loading.1 This event can cause a “braking inertia effect” on the machine system that can cause cracks in shaft keyways, coupling bolts or gear teeth. These may eventually become a fatigue failure due to normal loading. The model used here is for quick troubleshooting purposes on simple systems when a circuit is opened and quickly reclosed. It does not consider the electrical torsional vibration frequency torque. This analytical model is general enough for geared-motor– compressor or generator–turbine units that experience such a speed change. Knowing the magnitude of increase in the shaft torque allows stress calculations to be made. Fig. 1 is a two-mass torsional system with J1 being the motor that experienced the speed variation over time t and J2 is the compressor. C is the shaft stiffness between the masses. This is the simplified geared system2 described in Fig. 2. The coupling bolts had sheared and this required five times the mean torque.2 This model explains where the extra torque came from. In the analytical model J1 is not involved since no matter what size J1 is it has already resulted in the recorded speed change over a given time. All that needs to be done is to apply the twist to the shaft end at J1 and then by angular impulse and momentum equations solve for the twist at J2 . The torque in the shaft is simply the difference in these twists times the shaft stiffness. The resulting equation and an example of its use is: Tshaft = ( rpmt C /60)[1 C / (C + 2 J 2 /t 2 )] 51

In Fig. 1 the motor speed change was Δrpm = 60 and occurred in 0.05 seconds. The corrected shaft stiffness is C = 9.4 x 106 in.-lb / rad and the corrected J2 is 755 lb-in.-sec2. What is the torque increase in the shaft over the calculated mean shaft torque of Tmean = 14,850 in.-lbs? Tshaft = 89,200 in.-lb Tshaft /Tmean ≈ 6.0 A torque six times mean explains why the coupling bolts sheared. The cause was that a time-delay relay was wired incorrectly and the motor reaccelerated too soon after tripout. For troubleshooting, the author has found a Δrpm of 3% of the rpm in 0.05 seconds to be reasonable when no other data were available. In the several machines the author has investigated values of over six times mean torque resulted in some shaft or gear damage. It would be a good time to recommend a consultant who specializes in torsional vibration to be utilized. HP 1 2

LITERATURE CITED Nailen, R.L., “Avoiding Switching Transient Damage in Motor Circuits,” Consulting-Specifying Engineer, March 1987, Cahners Publishing Company. Sofronas, A., Analytical Troubleshooting of Process Machinery and Pressure Vessels: Including Real-World Case Studies, (p. 44, 128 ), ISBN: 0-471-732117, John Wiley & Sons.

Dr. Tony Sofronas, P.E., was worldwide lead mechanical engineer for ExxonMobil before his retirement. The case studies are from companies the writer has consulted for. Information on his books, seminars and consulting are available at the Website http:// www.mechanicalengineeringhelp.com.

Getting system to J1 rpm:

$52 = C $51/(C + 2J2/t 2) 52

rpm

Case where C2 >> C1 Tshaft C

$51 = P $rpm t/60 Motor FIG. 1

rpm2

C = C1 C2rpm / (C1 + C2rpm )

Tshaft J2 = J3 + J4 rpm + J5 rpm

Compressor Two-mass system analyzed.

J4 J2

C2 rpm = C2 (rpm2 /rpm )2 J4 rpm = J4 (rpm2 /rpm )2 J5 rpm = J5 (rpm2 /rpm )2

FIG. 2

Geared system reduced to Fig. 1 system.

HYDROCARBON PROCESSING NOVEMBER 2009

I 89

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(check one only): A B C F G H J P

䊐-Refining Company 䊐-Petrochemical Co. 䊐-Gas Processing Co. 䊐-Equipment Manufacturer 䊐-Supply Company 䊐-Service Company 䊐-Chemical Co. 䊐-Engrg./Construction Co.

JOB FUNCTION (check one only): B E F G I J

䊐-Company Official, Manager 䊐-Engineer or Consultant 䊐-Supt. or Asst. 䊐-Foreman or Asst. 䊐-Chemist 䊐-Purchasing Agt.

ADVERTISERS in this issue of HYDROCARBON PROCESSING Company Website

Page

RS#

ABV Energy SpA. . . . . . . . . . . . . . . .30 (153) ARC's Collaborative Mfg . . . . . . . . .40 (105) (53)

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Babbitt Steam Specialty Co. . . . . . . .65 (161) www.info.hotims.com/27224-161

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Belco Technologies Corp . . . . . . . . .63

(64)

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BJ Services . . . . . . . . . . . . . . . . . . .47

(52) (56)

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(55) (67) (60)

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Cudd Energy Services . . . . . . . . . . .48 (159) www.info.hotims.com/27224-159

(74)

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Gas Technology Products LLC. . . . . .14

(59)

Gulf Publishing Company Boxscore Online . . . . . . . . . . . . . .88 Circulation . . . . . . . . . . . . . . . . . .66 Events . . . . . . . . . . . . . . . . . . . . . .83 (165) www.info.hotims.com/27224-165

GPC Book . . . . . . . . . . . . . . . . . . .87 (170) www.info.hotims.com/27224-170

Video . . . . . . . . . . . . . . . . . . . . . .87 (169) (69)

(91) (78)

(97) (96) (71)

(73)

Maxon Corporation . . . . . . . . . . . . .22 (152)

www.info.hotims.com/27224-158 www.info.hotims.com/27224-152

MBI Leasing LLC . . . . . . . . . . . . . . .20 (100) www.info.hotims.com/27224-100

(58)

Roth Pump Company. . . . . . . . . . . .71 (162) www.info.hotims.com/27224-162

Samson GmbH . . . . . . . . . . . . . . . . .4 (151) www.info.hotims.com/27224-151

(81)

SKF . . . . . . . . . . . . . . . . . . . . . . . . .75

(54)

Spectro Analytical Instruments . . . . .42 (157) Spraying Systems Co . . . . . . . . . . . .68

(62)

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Swagelok Co. . . . . . . . . . . . . . . . . .28

(65)

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Thomassen Compressison System . .23 (106) (79)

M3 Technology . . . . . . . . . . . . . . . .44 (158)

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Rentech Boiler System . . . . . . . . . . . .2

T.D. Williamson . . . . . . . . . . . . . . . .95

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(74)

Finder Pompe SpA . . . . . . . . . . . . . .33 (154)

(76)

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(82)

www.info.hotims.com/27224-97

Linde Process Plants . . . . . . . . . . . .28

www.info.hotims.com/27224-160

Pittsburgh Corning Corporation . . . .55

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www.info.hotims.com/27224-82

Lectrus Corporation . . . . . . . . . . . . .26

Onis, Inc. . . . . . . . . . . . . . . . . . . . . .60 (160)

www.info.hotims.com/27224-81

www.info.hotims.com/27224-78

KTI Corporation . . . . . . . . . . . . . . . .50

www.info.hotims.com/27224-166

Siemens Ag . . . . . . . . . . . . . . . . . .43

www.info.hotims.com/27224-91

KTI Corporation . . . . . . . . . . . . . . . .53

Newton's . . . . . . . . . . . . . . . . . . . .76 (166)

www.info.hotims.com/27224-58

On-Demand Webcast . . . . . . . . . .86 (168)

HPI Marketplace . . . . . . . . . . . . 90-91 Hytorc . . . . . . . . . . . . . . . . . . . . . . .59

(86)

www.info.hotims.com/27224-76

HPI Market Data Book . . . . . . . . . .85 (163)

Haldor Topsoe A/S . . . . . . . . . . . . . .32

Merichem . . . . . . . . . . . . . . . . . . . .10 www.info.hotims.com/27224-86

www.info.hotims.com/27224-79

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(99)

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Dresser-Rand. . . . . . . . . . . . . . . . . .39 (156)

Feeney Wireless . . . . . . . . . . . . . . . .16

MBI Global . . . . . . . . . . . . . . . . . . .20

KBC Advanced Technologies Inc . . . .18

www.info.hotims.com/27224-67

Farris Engineering . . . . . . . . . . . . . .24

(93)

Inpro/Seal Company . . . . . . . . . . . . .8

www.info.hotims.com/27224-55

Curtiss Wright . . . . . . . . . . . . . . . . .24

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

www.info.hotims.com/27224-69

Buchen-ICS GmbH. . . . . . . . . . . . . .36 (155)

Criterion Catalyst & Technologies. . .12

RS#

www.info.hotims.com/27224-169

Borsig GmbH. . . . . . . . . . . . . . . . . .77 (164)

Chas. S. Lewis & Co., Inc. . . . . . . . . .78

Page

www.info.hotims.com/27224-168

www.info.hotims.com/27224-56

Burckhardt Compression Ag . . . . . .31

Company Website

www.info.hotims.com/27224-163

www.info.hotims.com/27224-52

Black & Veatch . . . . . . . . . . . . . . . .37

RS#

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Baldor Electric Company . . . . . . . . .72

Page

www.info.hotims.com/27224-93

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

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HPIN WATER MANAGEMENT LORAINE A. HUCHLER, CONTRIBUTING EDITOR Huchler@martechsystems.com

Are your decisions based on obtained data? Let’s talk about how operators and engineers make decisions over utility water systems. Take this short quiz; give your plant one point for each “true” answer and zero for each “false” answer: T F 1. __ __ The plant log sheets show specification limits. 2. __ __ Operators or central lab are responsible for validating accuracy of non-conforming test results. 3. __ __ All data are logged into an electronic database. 4. __ __ The operator or central lab chemist enter data into the database and validate accuracy of data. 5. __ __ All electronic data are stored on a server and accessible to all plant personnel. 6. __ __ Critical data are automatically tabulated into trend graphs in the centralized database. 7. __ __ The plant engineers have identified key performance indices (KPIs) and key operating indices (KOIs). 8. __ __ The plant engineers tabulate compliance statistics for KOI and KPI data. 9. __ __ The operations and tech-service personnel are trained to modify trend graphs and to conduct statistical analyses on the data. 10. __ __ Operations and tech-service regularly review and use data to troubleshoot and to optimize operations. __ __ Total Measuring up. A perfect score (10) means that your plant personnel are tracking the health of your utility water systems and making data-based decisions about changes and corrective actions. Plants with less than a perfect score should ponder whether they are relying on experience, judgment or just plain “guessing” to determine the proper corrective action instead of analyzing data. Date validation. Specification limits are analogous to speed

limits. Without written limits on the log sheets, it’s impossible for operators to have confidence that the process is in control. Most plants require an operator or central lab chemist to analyze a grab sample. However, most plants don’t have a procedure to confirm the accuracy of the analysis. Analyzing the accuracy of data is important when testing results fail to conform to the specification limits, e.g., validate by exception. Many strategies can be used to validate analytical test results. Here is an example for this very complex subject. First, it is reasonable to assume that the individual test results will follow a normal distribution. Second, the process engineer must specify the repeatability limit. Repeatability is a metric for test results when the same operator or chemist uses the same method on identical samples in the same laboratory using the same equipment in a short interval of time. The repeatability limit is the maximum difference between two test results. Process engineers establish a repeatability limit as “95%.” For a single pair of test results, there is a 95% 94

I NOVEMBER 2009 HYDROCARBON PROCESSING

probability that the difference between the two results will be less than 1.96 ! 2 ! (␴2)1/2 (see Eq. 1). In a normal distribution, 95% of all data is within 1.96 standard deviations (␴r) of the mean.

Repeatability limit = 1.96 2 r2

(1)

Data storage. In refineries and chemical plants, process units have electronic data storage in a location easily accessible to all plant personnel. But, surprisingly, many plants have not yet converted to the same system for data management of utility water systems. Collecting data from individual paper log sheets is so time consuming that most engineers choose not to invest the time and effort in creating the historical trend charts. Engineers who master the software tools (data trending, statistical analyses) can take advantage of the carefully-gathered-andvalidated data in the centralized database. Some plants create default trend graphs to simplify the user’s review; however, training operations and tech service personnel to modify trend graphs and conduct statistical analyses on the data is the key to making data-based decisions for troubleshooting and optimizing operations. Training operations and tech-service personnel to modify trend graphs and conduct statistical analyses on the data is the key to making databased decisions for troubleshooting and optimizing operations. Indices and specifications. Constructing KOI and KPI trends is a simple way for organizations to manage process improvement. Plant personnel are responsible for identifying operating (KOI) and performance (KPI) parameters that are necessary to maintain reliable waterside operation. In cooling water systems, a KPI may be a maximum limit for admiralty corrosion rates as measured by corrosion coupons, while a KOI may be a minimum limit and/or a maximum limit for cooling water conductivity. Plant personnel must establish specification limits for each KOI and KPI parameter based on industry standards, treatment program application guidelines and/or experience. Establishing a minimum acceptable compliance to the specification limits and tabulating compliance allows engineers and managers to focus on the “vital few” systems that require improvement. These benchmarks also provide clear targets for operator performance. Summary. Data and sound analysis of that data provide the

foundation for all improvement processes. Plant personnel must make a clear commitment to making decisions based on verifiable data, not assumptions and guesswork. HP The author is president of MarTech Systems, Inc., an engineering consulting firm that provides technical services to optimize energy and water-related systems including steam, cooling and wastewater in refineries and petrochemical plants. She holds a BS degree in chemical engineering and is a licensed professional engineer. She can be reached at: huchler@martechsystems.com.

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