Hydrocarbon Processing-may 2009

MAY 2009

HPIMPACT

SPECIALREPORT

TECHNOLOGY

Petrochem: China’s new capacity

MAINTENANCE & RELIABILITY

Planning for heat recovery projects

Europe’s refinery utilization trumps US

Techniques to improve plant availability

Sustainable cost cuts in capital spending

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MAY 2009 • VOL. 88 NO. 5 www.HydrocarbonProcessing.com

SPECIAL REPORT: MAINTENANCE AND RELIABILITY What’s new in vertical enclosed shaft-driven sump pumps

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Advanced designs incorporate axial-spiral design casing internals and fully recessed impellers H. Bloch and R. Franklin

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Risk-based inspection, a panacea for plant failures?

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Proper gasket removal and replacement can reduce maintenance and increase uptime

Cover Image courtesy of Mieko Mahi, www.energyimages.com.

Understand the limitations for an effective implementation S. K. Pullarcot

Follow these guidelines for trouble-free performance T. Hurley and D. Burgess

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Improve cooling tower gear drive reliability Applying commodity products instead of engineered solutions can cause premature failure J. DeBaecke

HEAT TRANSFER Rethink planning for heat-recovery systems

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Better early design of steam generators can save lots of money in operating cogeneration plants V. Ganapathy

SAFETY/LOSS PREVENTION Facility siting—balancing risk vs. cost

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Companies should take a second look at identifying and analyzing hazards associated with temporary buildings B. A. Walker

PETROCHEMICAL DEVELOPMENTS Consider new feedstocks for dimethyl ether production

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HPIMPACT 15 China: New domestic capacity to shrink some petrochem imports 17 US refiners’ utilization down 5%; East Coast plants ‘most vulnerable’ 17 Demand for plant asset management shows surprising resiliency 17 Renewed interest for US IGCC, carbon-capture coal power plant

This methanol-based petrochemical has growing options within energy markets S. K. Ansari and S. Ansari

INSTRUMENTATION How to select the better liquid-level measurement system

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Here is a closer look at commonly used sensors L. Aiken

PIPING/FLUID FLOW New explicit friction factor equation for turbulent flow in rough pipes

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It is more reliable and accurate than existing equations A. Sasan-Amiri

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Explicit friction factor correlations for turbulent fluid flow in noncircular ducts and polymeric fluids New equation provides highly accurate estimates C. T. Goudar and J. R. Sonnad

PROJECT MANAGEMENT Sustainable cost cuts in capital spending

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A reduction program based on your company’s unique nature can ensure that budget slashes implemented today will not jeopardize the ability to deliver projects tomorrow A. Siddiqui

ENGINEERING CASE STUDIES Case 50: Gearbox input shaft failure analysis

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Make sure the same failures are not repeated at your affiliated plant sites T. Sofronas

DEPARTMENTS 7 HPIN BRIEF • 15 HPIMPACT • 19 HPIN CONSTRUCTION • 86 HPI MARKETPLACE • 89 ADVERTISER INDEX

COLUMNS 9 HPIN RELIABILITY Getting all the facts is more important than ever 11 HPINTEGRATION STRATEGIES Creating a sustainability culture in HPI plants 13 HPIN ASSOCIATIONS The US refining industry is still alive and vital 90 HPIN WATER MANAGEMENT Got risk? Cut costs safely

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If you would like to have a recent article reprinted for an upcoming conference or for use as a marketing tool, contact 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 [email protected] HYDROCARBON PROCESSING (ISSN 0018-8190) is published monthly by Gulf Publishing Co., 2 Greenway Plaza, Suite 1020, Houston, Texas 77046. Periodicals postage paid at Houston, Texas, and at additional mailing office. POSTMASTER: Send address changes to Hydrocarbon Processing, P.O. Box 2608, Houston, Texas 77252. 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.

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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

EDITORIAL Editor Les A. Kane Senior Process Editor Stephany Romanow Managing Editor Wendy Weirauch 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)

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HPIN BRIEF WENDY WEIRAUCH, MANAGING EDITOR

[email protected]

Saudi Aramco plans aggressive downstream investment, according to Abdulaziz M. Judaimi, vice president of new business development for the company. Speaking at a global petrochemical conference held recently in Houston, he presented an oil market perspective and shared his corporation’s strategy. The company manages 260 billion barrels of crude oil and 254 Tscf of natural gas. The future appears to offer price support, he said, with a resumption in demand growth, further non-OPEC supply constraints and low inventories. “Saudi Aramco remains committed to rapid expansion,” he reported, with plans for 2-million bpd (MMbpd) upstream production capacity development, 1.5 Bscfd of sales gas, 1.2-MMbpd domestic and international refining expansion and 13 MMton in domestic petrochemicals growth.

Suncor Energy Inc. and Petro-Canada propose merger. On completion of the transaction, the combined entity will operate corporately under the Suncor name, while maintaining the brand presence of Petro-Canada in refined products. “The combined portfolio boasts the largest oil sands resource position, a strong Canadian downstream brand, solid conventional exploration and production assets, and low-cost production from Canada’s East Coast and internationally,” according to Rick George, president and CEO of Suncor. He will assume the same role with the merged entity. The new company will have a refining capacity of 433 thousand bpd (Mbpd). Year-to-date oil sands production at the end of March averaged 278 Mbpd. The company is targeting average oil sands production of approximately 300 Mbpd in 2009. New nanocoatings developed for power-generation applications. The US Department of Energy and power generation companies are interested in achieving greater power plant efficiency by increasing steam temperature and pressure. However, the combination of high steam temperature and pressure promotes coal ash corrosion and increases corrosion rates. To improve reliability and availability of fossil-fired boilers, scientists with the Southwest Research Institute (www.swri.org) applied computational methods to design and assess potential Fe-Cr-Ni-Al systems to produce stable nanostructured coatings that form a protective, continuous scale of alumina or chromia. These advanced coatings are claimed to maintain long-term stability and corrosion resistance by forming a diffusion barrier layer that prevents Cr or Al loss from inward diffusion.

World valve and pump markets to be flat in 2009. World sales of industrial valves will remain at $47 billion this year, according to a new forecast from McIlvaine Company. A 3% increase in demand is projected for 2010. Some industries in China will show fairly robust growth. For example, the replacement valve market in Chinese coal-fired power plants is now twice as large as that in the US and accounts for more than 30% of the world market. Global sales of pumps in 2009 are forecast to remain at the 2008 level of $32 billion. Centrifugal pumps will be the biggest product group. Rotary pumps will edge the diaphragm segment with $1 billion more in revenues. Reciprocating pump sales are expected to be slightly lower than sales of diaphragm pumps.

Global Web attacks in the HPI increasing. A new report from ScanSafe, a provider of Web security solutions, finds that the energy and oil sector is the most at-risk vertical for Internet threats. Other sectors in the top five most threatened industries are pharmaceuticals and chemical, engineering and construction, transportation and shipping, and travel and entertainment. “Today’s malware is all about stealing and harvesting data. Cyber-criminals have moved away from defacing sites or merely designing malware as a prank, and it is now created with commercial and criminal intent,” according to Mary Landesman, the report’s author. The aim appears to be a large-scale data harvesting operation that is targeting corporate intellectual property assets. “This gives rise to the likelihood that cybercrime is proving to be a viable business opportunity in a climate where legitimate opportunities are becoming increasingly more limited,” says Ms. Landesman. HP

■ US refiners ending maintenance season By April, refiners in the US are typically coming out of maintenance and ramping up production of gasoline for the summer driving months. However, the industry isn’t usually at full production until sometime in May or June. Frequently, the balance between supply and demand tightens during this spring transition. But this year, the US has less need for petroleum products from domestic refineries than usual. Falling petroleum consumption, high gasoline import availability and increasing use of ethanol in gasoline have reduced demand for US refinery output. Consider gasoline and distillate, which together represent over 70% of refinery output from crude oil. Energy Information Administration (EIA) data indicate that, for the first quarter, demand for gasoline declined 1.5% and distillate fell 6.7%. Distillate demand, which is mainly driven by heavy-duty trucking, has been hit hard by the slowing economy. Gasoline from domestic refineries is slowing due, in part, to increased supply from gasoline imports, much of which comes from Europe. In this weak market, some refiners have chosen to shut an entire refinery down while maintenance is being done, rather than continue partial operations at higher cost. Even so, on the East Coast, which experienced very large refinery outages in March, gasoline inventories grew from 53 million barrels early in the month to over 56 million barrels by early April. “In all, the refinery maintenance program this spring is likely going to have little impact on the supply-demand balance, and seems to be providing opportunities for refiners to do extra maintenance,” says EIA’s analysis (www. eia.doe.gov). HP HYDROCARBON PROCESSING MAY 2009

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

Getting all the facts is more important than ever An old friend once told me that even the thinnest pancake has two sides. He meant to say there are at least two sides to any argument and listening to only one will be a mistake. In harmony with this thinking, we believe maintenance and reliability professionals must learn to make decisions based on solid facts. Industry already pays a heavy price for lack of critical thinking and not acting on facts. As a result, fortunes are spent on “unexplained” repeat failures of mechanical equipment. Old products are rapidly superseded by modern technology. Although named as the coinventor of a bearing housing protector seal (US patent number 5,161,804, issued 10 November 1992), I no longer recommend this outdated design for the simple reason that superior products are available. Know your bearing protector seals. Our example point

about old vs. new bearing housing protector seals could be expanded. Note there are old styles of noncontacting bearing protector seals (isolators) where the gap between rotating and stationary components is bridged by an O-ring or wedge ring (Fig. 1). If an elastomeric O-ring or wedge ring simultaneously touches both a stationary and nonstationary component, this elastomeric ring will either drag and wear, or lift off and not wear. In the nonwear mode the isolator will have an air gap that permits an interchange between the ambient air and whatever oil–air mixture exists inside the bearing housing. We can even ascertain how much dirt is in the air and determine the extent to which bearing life is affected by dirt and moisture. Researchers have published these effects as life extension factors.1 As to the behavior of an elastomeric ring, we can reason that only one of two scenarios is plausible at a time: The ring either contacts, or it does not contact. If it makes contact with the sharp edge of a groove, it is more likely to shred than if it contacts a much wider surface. Simply remember that force equals pressure times area (or pressure = force divided by area contacted or “pounds per square inch”), and a given force acting on a small area will result in an undesirably high pressure.

Beware of those who market outdated stuff. While

reasonable people believe that we should all do more reading and less listening to sound bites, we must also be careful and not believe everything we read. Some of our readers alerted us to a Website where a marketing guru recently labeled oil mist “hype.” We assume he wanted his clients to know that compressed air for oil mist lubrication, plus the force needed to overcoming seal friction, consumes power. Why would that be news to a reasonable person? Ten years ago (1998) it was pointed out that the volume of air needed by a system with 167 application points costs $6,600/year.2 Yet, avoiding a pump failure was then already worth about $6,000. What the uninformed either do not know, or elect not to mention, are the associated benefits of oil mist. These benefits include the preservation and corrosion protection of standby equipment, energy savings due to reduced bearing friction, extremely low maintenance requirements, elimination of abrasion-prone and immersion-sensitive slinger rings and deletion of constant-level lubricators. With modern oil mist application, plant downtime risk is reduced and other revenue-favoring factors come into play as well.3 Contrary to the aspersions cast against oil mist, every single rolling-element bearing applied in oil refineries can benefit greatly from oil mist so long as the application points, vent locations and mist reclassifier configurations are correctly chosen. That said, the right mist reclassifier might be one that converts mist to a spray and is oriented to direct this oil spray into the bearing cage. In other instances, the best reclassifier might be a plain orifice that simply meters mist into a cavity.4 And if you want a besttechnology, environmentally acceptable closed oil mist system, you must choose a suitable face-type bearing isolator. The above examples are among the many that illustrate the need to sort out what advice is complete and correct. Unbiased facts are rarely contained in the anecdotes and foggy recollections of people who make it a habit to quote data out of context and spend much of their life spreading partial or false information. HP 1 2

3 4

LITERATURE CITED Bloch, Heinz P., “Well worth the cost,” Uptime Magazine, August/September, pp. 26–28, 2008. Bloch, Heinz P. and Abdus Shamim, Oil Mist Lubrication: Practical Applications, Fairmont Publishing Company, Lilburn, Georgia (ISBN 0-88173-256-7), pp. 152, 1998. Bloch, Heinz P. and Don Ehlert, “Get the facts on oil mist lubrication,” Hydrocarbon Processing, August 2008, pp. 41–49. Bloch, Heinz P., Machinery Reliability Improvement, Gulf Publishing Company, Houston, Texas. Also, revised 2nd & 3rd editions (ISBN 0-88415-663-3), 1982, 1998.

The author is the Equipment/Reliability Editor of HP. A practicing engineer and FIG. 1

Bearing protector seals with O-ring or wedge ring separating stationary and rotating components. Only a single O-ring is clamping the rotor to the shaft in these older-style configurations.

ASME Life Fellow with close to 50 years of industrial experience, he advises process plants on maintenance cost reduction and reliability upgrade issues. His 16th and 17th textbooks on reliability improvement subjects were published by John Wiley & Sons in 2006. HYDROCARBON PROCESSING MAY 2009

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HPINTEGRATION STRATEGIES DICK HILL, CONTRIBUTING EDITOR [email protected]

Creating a sustainability culture in HPI plants Most companies are looking to contain costs and preserve Measure the results in dollars and cents. Chances are cash. At the same time, manufacturers are being pressured to you’ve already implemented metrics such as “energy consumed per reduce energy usage and greenhouse gas (GHG) emissions. Most unit of product made.” But, do you measure it in real time and process manufacturers that have been around for a long time have provide this information to the production workers that can make already done the “big” things. They have taken action on most a difference? Probably not. Chances are this metric is buried somelarge critical processes such as fired heaters, utility power boilers where within a monthly report for the plant manager. But if you or steam generation units. Most likely, they have added automatic can measure energy consumption in real time, trend the informadamper controls and burner management technologies to their tion and then display it right on the operators’ consoles, they can fired heaters, load-shedding strategies to their utility boilers, and begin to get an idea of how their actions impact energy usage. implemented steam and energy balance monitoring and reporting Better still, since most front-line workers are probably not engitools to keep a close eye on these items. Many manufacturers have neers, and thus do not generally relate to engineering terms, put this also begun installing variable-frequency in terms of dollars (or euros, yen, etc.) saved drives on selected pumps and motors to ■ According to ARC research, to get their attention. save electricity. Creating a healthy competition between The energy-saving benefits to be gained most industry leaders have a shifts might provide some benefits beyond from approaches such as these are now wellthe normal good work that your operations documented, and each, no doubt, started safety culture that encourages and maintenance staffs do. If you operate with an employee having a great idea. By new ideas to improve several facilities, why not report, on a regular developing a “sustainability culture” in basis, which facility has improved its energy their plants and across their organizations, workplace safety. So why not footprint the most over the past month (and HPI companies can create an atmosphere perhaps even provide a tangible incentive?). extend this to sustainability in which all employees are encouraged and Most, if not all, process manufacturing motivated to contribute ideas—both big and energy conservation? is controlled by operators who use digital and small—that can help reduce the comdisplays that tend to show information in pany’s energy consumption and, with it, its carbon footprint. engineering terms. The modern idea is to present KPIs in a perforRecognizing the importance of embedding safety into the mance dashboard configuration. ARC has written extensively about minds of every employee, most of these same companies have had real-time performance management strategies, explaining that pera strong safety culture in place for many years. According to ARC formance-related metrics don’t have to be on a separate device; they research, most industry leaders have a safety culture that encourjust need to provide a different way of looking at information. ages new ideas to improve workplace safety. So why not extend In the HPI, many potential cost-saving opportunities related to this to sustainability and energy conservation? power and energy consumption are ignored simply because people in refineries and petrochemical plants don’t have the appropriate visibility or control. Creating an energy conservation culture. The same As the saying goes, “employees are our most important asset.” kind of thinking used to create a safety culture can be applied to When it comes to improvements for sustainability, this clearly a culture that looks for opportunities to lower your company’s holds true. Creating a culture of any kind is not easy. The process costs through energy conservation and related activities. For most industries have worked very hard to create a culture for safety. Crecompanies, creating a safety culture has to be the number one ating a sustainability culture is perhaps the next challenge. HP objective. However, in today’s business climate, having an energy conservation culture could rank a close second. The first step is to engage employees and make them aware of The author is vice president of ARC Advisory Group, Dedham, Massachusetts, the impact they have on energy conservation. A successful proresponsible for developing the strategic direction for ARC products, services and gram must first create continuing awareness among all employees geographical expansion. He is responsible for covering the advanced software business worldwide. In addition, he provides leadership for support of ARC's automaof how their actions can impact the company’s ability to operate tion team and clients. Mr. Hill has over 30 years of experience in manufacturing and in a profitable, yet sustainable, manner. Just as well-placed “safety automation. He has broad international experience with The Foxboro Company. first” signs can help remind employees that safety is everyone’s job, Prior to Foxboro, Mr. Hill was a senior process control engineer with BP Oil, developprograms to promote universal energy conservation awareness ing and implementing advanced process control applications. Prior to joining ARC, he was the US general manager of Walsh Automation, a major engineering concould be started. sulting firm and supplier of CIM solutions to the pulp and paper, petrochemicals, A successful program should also encourage employees to think pharmaceutical, and other process and manufacturing industries. He is a graduate creatively and contribute their ideas about measures that the company of Lowell Technological Institute with a BS degree in chemical engineering. can take to further reduce energy consumption and/or emissions. HYDROCARBON PROCESSING MAY 2009

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HPIN ASSOCIATIONS BILLY THINNES, NEWS EDITOR

[email protected]

The US refining industry is still alive and vital The 107th NPRA Annual Meeting took place in San Antonio, Texas, last month. Global economic and political events helped steer the conversations at the meeting in a variety of directions. During a press conference kicking off the meeting, Kevin Brown, the executive vice president of Sinclair Oil and NPRA’s current chairman, said, “In these difficult economic times, the industry is seeing hardship and is being tested by policymakers. But I think the industry is confronting the economic and credit crisis in a very responsible way, which is a testament to our ability to adapt.” Attendance at this year’s annual meeting was down from previous years, approximately 12–14%, according to Charles Drevna, NPRA’s president. The relatively high turnout given current market conditions showed that “this industry is still alive and vital,” he said. “Now is the time for industry to show what makes it work and help drive the economic recovery,” Mr. Drevna said. “We are part of the solution, while the inside the Beltway rhetoric looks at us as the problem. We believe solutions to future energy challenges lie in establishing the most diverse fuel supply possible and we intend to work closely with the new administration.” “The average American doesn’t understand the economics and complexity of the refining business,” Mr. Brown added. “We need to do a better job of educating the country about our business.”

Charlie Drevna and Kevin Brown field questions from reporters at the NPRA’s annual meeting.

it doesn’t know what prices really are and what assets are really worth.” The positive that Mr. Karlgaard sees in this scenario is that networks can go down fast but they can also come up fast. “I think economic recovery will take place faster than people think,” he said. “All the indicators are screaming to me that the recession fears have been oversold and these fears have saturated our culture,” he said. “I think what we are living through is the 1970s. In 1973 and 1974, stocks fell 48% and we had a recession. Trust completely evaporated in American culture and the national mood was sour.” Mr. Karlgaard believes the US will see positive economic growth by the 4th quarter of this year. The country won’t see typical growth. It will be more like 1 to 2%. However, if a cap and trade program passes, it will knock recovery down by ½ to 1 point. Safety. A portion of the meeting was

General session. Education, specula-

tion and optimism for a better future were a focus of the meeting’s general session. Rich Karlgaard, the publisher of Forbes, led off the opening session with a brisk talk regarding the American economy. “In my view, we are not suffering an economic collapse. It is a network blackout. It is not a blackout of electricity or bandwidth. It is a blackout of prices and credit,” Mr. Karlgaard said. “We simply don’t know what the prices are for certain sets of assets right now. Credit is not flowing. $4 trillion sits on the sidelines in money market accounts because

also dedicated to recognizing safety. The NPRA’s highest accolade for member companies is the Distinguished Safety Award. It is presented only to facilities with an unparalleled commitment to safety. Before the final selections are made, a panel of experts examines safety records using a strict screening criteria. According to Mr. Brown, a facility must be exceptional just to apply for the award. The 2009 Distinguished Safety Award winners were recognized in a brief ceremony before the general session. The first recipient was ConocoPhillips’ refinery in

Billings, Montana. Larry Ziemba accepted the award on behalf of ConocoPhillips. The other award recipient was ExxonMobil Chemicals’ polyolefins plant in Baton Rouge, Louisiana. This is the seventh year in a row the plant has been recognized with an award, an unprecedented occurrence, according to NPRA Chairman Brown. The honorable mention winner was ConocoPhillips’ WRB Refining LLC refinery in Borger, Texas. These and other safety award winners will be recognized May 13, 2009, at the NPRA Safety Conference in Grapevine, Texas. Hospitality wrap-up. A big part of the NPRA annual meeting is the networking that takes place during the hospitality suites in the evening. Some highlights: KBC’s suite was all about the soft chatting murmur punctuated by the clarity of four choices for pristine martinis that helped the conversation flow without effort. CB&I employed some three dimensional theatrics with cameras and big screen TVs and protective sunglasses to project visitors into an alternate reality of dancing television heads. Shaw’s suite was rocking late to the musical alchemy of the band known as the Texas Tide, who summoned forth the spirit of Otis Redding and unified all in a sing-along version of “Sitting on the Dock of the Bay.” Criterion took over the conveniently located second floor restaurant at the host hotel and transformed it into an elegant and relaxing atmosphere for discussing business and reflecting on the events of the day. BASF Catalysts was quite welcoming in its suite as the band was not afraid to jam off into tangents of a flamenco jazz fusion style, the two guitarists plucking their acoustic axes with dexterity while the band’s drummer mined the softly syncopated style of the Bill Evans Trio. It was Buffett overload over at Albemarle, as the Jimmy Buffett songbook was cranked up to 10 on the stereo and everyone was feeling fine. Haldor Topsøe welcomed guests and cornered the market on refined conversation punctuated with laughter. HP

HYDROCARBON PROCESSING MAY 2009

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Revamp, retroļt and upgrade Consultation and feasibility studies Start-up and operator training Spare parts and technical services

Selas Fluid Subsidiary of The Linde Group Headquarters: Five Sentry Parkway East Blue Bell, PA 19422 USA • Telephone: 610-834-0300 • Facsimile: 610-834-0473 Texas Ofļce: 16225 Park Ten Place, Suite 250 Houston, TX 77084 USA • Telephone: 281-717-9090 • Facsimile: 281-717-9091 www.selasĽuid.com Select 100 at www.HydrocarbonProcessing.com/RS

HPIMPACT WENDY WEIRAUCH, MANAGING EDITOR

[email protected]

China: New domestic capacity to shrink some petrochem imports

In addition, Shenhua and The Dow Chemical Co. are planning to invest in a large-scale coal-to-chemicals project in West China. “Nonetheless, the current weak energy market makes coal-based chemical investment much less attractive now. The Chinese government recently tightened the control on coal chemical investment,” Mr. Pang said.

Project activity. One aim of the overall stimulus package is to help boost domestic demand for petrochemicals. The majority of new projects will be developed by China’s two state-owned firms, Sinopec and PetroChina. By 2013, Sinopec will add six major new naphtha crackers and aromatics complexes. PetroChina will also build six major naphtha crackers and aromatics complexes in Northeast and West China. Beside these two majors, CNOOC is emerging as the third petrochemical major by adding a new large aromatics complex next to its existing cracker in South China. There are also projects invested by private companies in North and South China. Coal-to-chemical projects in China have also drawn a lot of attention, according to Mr. Pang’s analysis. During the high crude price environment over the past two years, a wave of coal chemical projects has been developed. Investments have been made in coal-to-methanol, PVC and olefins. Among all of the coal chemical projects, the most important ones are probably coal-to-olefins projects. Shenhua Group, another state-owned energy enterprise, started to build three large-scale coal-toethylene and coal-to-propylene projects in 2006. All three projects will be started up in April 2010. By mid-2010, total olefin production from coal is forecast to reach 1.5 million tons/year (MMtpy).

Product outlook. For the plastics sector, domestic demand is expected to recover slightly this year from a major slump in 2008 (Fig. 1). The infrastructure and housing projects under the economic stimulus package will help create some new demand. Consumption related to finished goods for export will continue to be depressed this year and the following year. A major demand recovery “will likely occur in 2011,” according to Mr. Pang. From the supply side, with around 15 million tons of new capacity coming onstream from this year to 2011, the average operating rate will drop to 70% before it can recover in 2012. With increasing domestic production, imports will shrink to 6 MMtpy from 10 MMtpy—the average during the past five years. Thus, for international exporters, selling products into China will become more competitive in the coming years. The scenario for the aromatics industry is very similar. Mr. Pang’s projections show that demand will grow very modestly this year and the following year (Fig. 2). “The demand growth will start picking up after 2010, when the global economy recovers,”

30

100

40

80

25

80

30

60

20

40

10

20

0

0 03

04 05 06 PE production Total net import PP production

07 08 09 10 PVC production Total capacity Total demand

11 12 13 Operating rate

Source: CMAI, 2009 World Petrochemical Conference

FIG. 1

China’s plastics supply and demand: a recovery in domestic consumption is forecast for 2011.

20

60

15 40

10

20

5 0 03

04

05

06

PX production PX equivalent PTA import

07

08

09

10

Net Bz/PX import Bz production Operating rate

11

12

13

Operating rate, %

100

Million ton

50

Operating rate, %

Million ton

After 17 years of continuous strong growth, China has become the world’s third largest economic power and the country’s economy has been more integrated into the global economy than ever in its history. However, the recent economic crisis in the West is impacting certain industrial sectors in that nation by a very large magnitude, according to Paul Pang, managing director of CMAI China. Speaking at the company’s recent World Petrochemical Conference, he presented his analysis of the state of China’s general economy and import/export outlook. As demand from overseas consumers turned weak early last year, export-oriented manufacturing industries such as textiles, toys, electronics and home appliances have been hit particularly hard. Many factories have either closed or reduced their throughput. Approximately 40% of Chinese GDP in 2008 was contributed directly and indirectly by export. To cope with weak export demand, in November 2008, the Chinese government laid out a plan for a 4 trillion RMB economic stimulus package, equivalent to $585 billion. The whole package is to be implemented in the next two years. The direct investment in the petrochemical industry from this package is only about $15 billion, and the investment is expected to be mainly used for

upgrading refineries and building new petrochemical facilities.

0

Total capacity Total demand

Source: CMAI, 2009 World Petrochemical Conference

FIG. 2

China’s aromatics industry: new capacity additions reduce operating rates to 70% until 2011. HYDROCARBON PROCESSING MAY 2009

I 15

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HPIMPACT he said. On the supply side, several major paraxylene (PX) complexes are expected to be brought onstream in the next two years. The total production capacity for benzene and PX will increase by 11 MMton from this year to 2011. This large amount of new capacity will bring the average aromatics industry operating rate down to 70% till 2011. The operating rate will recover after 2011 as the demand picks up and new capacity additions slow down. However, even with the massive domestic production growth, China will continue to import a large quantity of PX and PTA, according to Mr. Pang. The combined import for PX and PX equivalent PTA is forecast to remain at around 6 MMton. For the international players, China will maintain its position as the largest PX and derivative import market.

US refiners’ utilization down 5%; East Coast plants ‘most vulnerable’ US refineries, particularly those in the East Coast and Gulf Coast regions, are most vulnerable to utilization cuts and will have to reduce throughputs further as a result of the economic downturn, according to a new report from Wood Mackenzie. The report examines refinery utilization in Europe, the US Gulf Coast and US East Coast and finds that European refiners have seen the smallest reduction in utilization rates at 0.5%. However, both Gulf Coast and East Coast refineries in the US have seen much larger falls in utilization of around 2.5% (excluding the impact of the hurricanes in September 2008) and 5%, respectively, year-on-year in 2008. “Although we expect demand to stabilize by 2010, utilization is expected to remain on a downward trend, because nonrefinery supply (e.g., NGLs and biofuels) continues to grow and we also expect new refining capacity to come onstream,” according to Alan Gelder, head of the company’s Downstream Oil Americas. Overall, demand is forecast to decline by around 1.1 million barrels/day (MMbpd) in the US and Europe between 2008 and 2010. At the same time, nonrefinery supply in the US and Europe is projected to grow by a combined 0.4 MMbpd over the same period, mainly because of increased biofuels use. Refining capacity in these regions is also forecast to grow by 0.9 thousand barrels/day due to expansions of refineries,

which will result in additional pressure on throughputs at existing capacity. Historically, many refineries in the US have been geared up to maximize gasoline production, but Wood Mackenzie says that a potential global surplus of gasoline and falling US gasoline demand leaves them more susceptible to utilization cuts than their European counterparts. The report concludes that new trade flows are being established across the Atlantic basin, with a structural export of diesel and gasoil from the US emerging. The big change in 2008 was that gasoil (and diesel) moved from being at broadly similar prices in the two markets, to a marked premium in North West Europe versus the US Gulf Coast. The US became the marginal source of European diesel/gasoil imports. European middle distillate prices continued to rise, until they were high enough to attract US refiners to switch yields to increase middle distillate exports to Europe. “We believe that this trend will continue in the future and that European middle distillate prices will remain at a premium to the US,” Mr. Gelder says.

Demand for plant asset management shows surprising resiliency The worldwide 2008 market for Plant Asset Management (PAM) systems has grown an average of over 13%/yr since 2006. The PAM system market expanded over $400 million dollars since 2006, according to a new ARC Advisory Group study. The recent massive worker layoffs have thrust many organizations into precarious positions that threaten both plant performance and safety. “As dark clouds loom over the economy, PAM systems will continue to grow going forward, albeit at a slower rate,” says ARC Research Director Wil Chin, the study’s principal author. According to the study, the value proposition for PAM systems remains intact and— when combined with safety and other drivers associated with the decline in the workforce— PAM adoption will not fall-off nearly as much as other automation investments. Navigate minefields. Despite the ability to work as a niche solution for specific areas of the plant or be dedicated to certain asset classes, PAM systems require supplier domain and industry expertise to be successfully deployed. PAM also continues to evolve. Exam-

ples include new systems that are more intelligent with self-learning capabilities, deploy multiple diagnostic technologies for a greater number of assets, and employ enabling technologies for online communication and remote offline analysis from anywhere in the world. Knowledge regarding PAM system suppliers, available solutions, and adoption and operational strategies is increasingly important for end users and suppliers alike. “To be able to navigate the minefield-filled landscape, PAM end users need to understand how to get the most out of their capital assets; suppliers need to fine-tune their solution offerings and delivery mechanisms,” according to the study (www.arcweb.com).

Renewed interest for US IGCC, carbon-capture coal power plant A proposal to build a futuristic coalburning power plant in central Illinois that languished under the Bush administration has received a fresh look from the new US Energy Secretary Steven Chu. Supporters of the project have pitched FutureGen as a cutting-edge attempt to burn coal for power and trap CO2 emissions. Coal-fired power plants generate about one-half of US electricity and about onethird of its CO2 emissions. In 2003, the Department of Energy (DOE) initiated FutureGen—a commercial-scale, coal-fired power plant to incorporate integrated gasification combined cycle (IGCC), an advanced generating technology, with carbon capture and storage. The plant was to capture and store underground about 90% of its CO2 emissions. DOE’s cost share was 74%, and industry partners agreed to fund the rest. “Secretary Chu believes that the FutureGen proposal has real merit,” DOE spokeswoman Stephanie Mueller said in a statement after Dr. Chu met in late March with members of the FutureGen Alliance. The plant was to be built in Mattoon, Illinois, but the Energy Department halted plans after a faulty cost analysis put the price at $500 million higher than it should have been. Earlier this year, a Government Accountability Office report (www.gao.org) reinvestigated the viability of the project. The agency’s report recommended that the DOE should prepare a comprehensive analysis that compares the original program, incremental changes to the original plan and the restructured proposal. HP HYDROCARBON PROCESSING MAY 2009

I 17

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North America Mustang has completed its low sulfur gasoline project at Placid Refining Co. LLC’s refinery in Port Allen, Louisiana. Mustang provided the engineering, design, procurement and construction management for a grassroots 20,000 bpd FCC gasoline hydrotreater to make low sulfur gasoline. The new unit, along with other improvements, will enable the refinery to meet all applicable clean fuel standards for its products. The $63 million project is part of the refinery’s $300 million upgrade and expansion to increase the refinery’s capacity from 55,000 bpd to 80,000 bpd while reducing total air emissions by about 50%. Construction and successful startup of the new hydrotreater unit were completed in September 2008. Ivanhoe Energy Inc. has commissioned its new feedstock test facility (FTF) for the company’s proprietary technology for field upgrading of heavy oil to light oil (HTL). The HTL testing facility will be used by Ivanhoe Energy in coming years to support detailed engineering and design of commercial-scale HTL plants for Ivanhoe Energy’s Tamarack project in Alberta, Canada, and Pungarayacu project in Ecuador, and to test crudes associated with additional potential HTL projects. The FTF was installed at Southwest Research Institute (SwRI) in San Antonio, Texas, last December. The FTF is a very close analogue to a full-scale commercial HTL facility and is capable of operating under a wide range of conditions. The FTF is multi-purpose and will be used to support the engineering and design of commercial HTL facilities for the Tamarack project (Canada) and the Pungarayacu project (Ecuador); generate commercial product for marketing; test heavy oil from additional target projects around the world; optimize and enhance the HTL process; and generate new intellectual property and patents. The FTF will supplant the 1,000 bpd commercial demonstration facility in Bakersfield, California, which has served its primary mission of proving that the HTL process can be scaled up to a commercial size. The maintenance division of Shaw’s Power Group has been awarded a main-

tenance, small capital construction, turnaround support and specialty services contract by Marathon Oil Corp. for its Texas refining division, located in Texas City, Texas. Shaw will immediately assume current maintenance and small capital construction work supporting Marathon’s 76,000 bpd refinery. Additional turnaround, specialty and engineering services may be provided as needed. PEMEX has awarded GTC México (GTC) an EPC contract to revamp their ethylene oxide plant. As part of the agreement, GTC will provide major distillation columns, mass transfer equipment, reactors, chemicals, field engineering and installation work. This project will conclude the final phase of the 250,000 Mtpy ethylene oxide plant revamp.

South America CB&I has an approximately $50 million contract with Flota Petrolera Ecuatoriana (FLOPEC) to design and build storage facilities for a grassroots liquefied petroleum gas marine terminal in MonTREND 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: [email protected].

teverde, Ecuador. CB&I’s scope of work includes the engineering, procurement, fabrication, and construction of several refrigerated storage tanks and spheres with a total capacity exceeding 650,000 barrels. The project will provide Ecuador additional options for importing LPG. The project is scheduled to be completed in 2010.

Europe BASF has idled the smaller of its two steam crackers at its site in Ludwigshafen, Germany, due to continuing weak demand. The temporary shutdown of the cracker, which has a capacity of 220,000 metric tpy of ethylene, was planned for the middle of April and expected to last at least three months. Overall, a total of five production lines are currently idled at the Ludwigshafen Verbund site, and an additional 60 production lines are operating at very low capacity utilization rates. BASF has reduced its production capacities worldwide by more than 25%. ExxonMobil recently inaugurated its newest cogeneration plant at its Antwerp refinery in Belgium. In addition to generating 125 megawatts, the new plant will reduce Belgium’s carbon dioxide emissions by approximately 200,000 tpy, the equivalent of removing about 90,000 cars from Europe’s roads. With the inauguration of the Antwerp facility, ExxonMobil now has interests in about 4,600 megawatts of cogeneration capacity in about 100 individual installations at more than 30 sites around the world. This is enough capacity to supply the needs of more than 5 million homes in Europe. Additional new facilities under construction in Singapore and China will increase ExxonMobil’s cogeneration capacity to more than 5,000 megawatts in the next three years. TurboSonic Technologies, Inc. has a $2.3 million order from a European refinery. The refinery will incorporate TurboSonic’s technology for controlling particulate emissions as an integral part of an upgrade of its physical plant. The upgrade will facilitate the production of low-sulfur fuels in response to environmental legislation. TurboSonic expects that delivery will be completed in its 2010 fiscal year. HYDROCARBON PROCESSING MAY 2009

I 19

HPIN CONSTRUCTION Middle East Chiyoda and Technip joined with Qatargas to celebrate the inauguration of the Qatargas 2 project in Ras Laffan, Qatar. The recently completed trains 4 and 5 have a unit capacity of 7.8 million tpy. Chiyoda and Technip were involved in all aspects of the engineering, procurement and construction of Trains 4 and 5 from front-end engineering to startup. These are the first two of six LNG trains to be inaugurated within the framework

of the three projects (“Qatargas 2”, “Qatargas 3 and 4” and “RasGas 3”) ongoing at the Ras Laffan Industrial City. 240 million man-hours have been expended to-date in the construction and commissioning of Trains 4 and 5. Fluor Corp. has received notification from Kuwait National Petroleum Co. to stop work on the utilities and offsites for the al-Zour refinery. Fluor has approximately 300 employees performing engi™

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neering work on the project. The remaining contract value of approximately $2.1 billion will be removed from the company’s backlog in the first quarter. The Shaw Group Inc.’s Energy & Chemicals Group has been selected to provide engineering services for Sonatrach’s planned 24 million m3/d grassroots liquefied petroleum gas (LPG) recovery facility in Algeria. The facility, located near Hassi Messaoud, is expected to be completed in the first half of 2012. Shaw performed the front end engineering design work and will be a subcontractor to Saipem S.p.A. for this subsequent phase.

Asia-Pacific Mangalore Refinery and Petrochemicals Ltd. (MRPL) has awarded Larsen & Toubro (L&T) two large project orders for Rs 1344 crores, including a 3.7 MMtpy diesel hydrotreating unit and a 70,000 tpy hydrogen generation unit (HGU). The projects, located in India, will enhance capacity and upgrade fuel quality to meet Euro IV specifications. With this announcement, L&T has booked large orders valued at Rs 5177 crores this week. The Linde Group has a contract with Sinopec Sichuan Vinylon Works (SVW) to jointly build gas plants and produce industrial gases for the long-term supply to SVW’s chemical complex. This collaboration will result in an initial investment of approximately €50 million. This partnership will establish a joint venture between Linde Gas (Hong Kong) Ltd. and SVW in Chongqing Chemical Industrial Park (CCIP), China, by June 2009. SVW in Chongqing is mainly engaged in producing natural gas-based chemical and chemical fiber products, and is currently expanding its vinyl acetate monomer (VAM) production capabilities.

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Jacobs Engineering Group Inc. has a contract from Hindustan Petroleum Corporation Limited (HPCL) to provide project management consultancy services for a diesel hydrotreater (DHDT) project at HPCL’s refining complex in Mumbai, India. Officials estimate the overall total installed cost for the DHDT at $650 million. Jacobs will perform front-end engineering design and supervise the lump-sum turnkey contracting for the DHDT project. Work includes the installation of a DHDT and associated facilities in HPCL’s Mumbai refinery. HP

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MAINTENANCE AND RELIABILITY

SPECIALREPORT

What’s new in vertical enclosed shaft-driven sump pumps Advanced designs incorporate axial-spiral design casing internals and fully recessed impellers H. BLOCH, HP staff; and R. FRANKLIN, Emile Egger & Cie, Cressier, (Neuchatel), Switzerland

V

stand that recessed impellers promote vortex flow. The impeller is of the semi-open type; the vanes are integral with the disk and there is no impeller shroud. On the side away from the vanes the disk incorporates integrally cast back pump-out vanes (balancing vanes). Recessed-impeller designs are particularly suitable for handling free-flowing slurries and sludge. A modern impeller design can handle solids with dimensions essentially equal to the diameter of the discharge port. However, explosion-proofing measures sometimes require a spark arrestor in the pump discharge (Fig. 1) and, when fitted, this arrestor restricts the permitted solids size. Selecting an appropriate suction strainer will limit the solids-size to allowable diameters. Most recessed-impeller pumps rotate the liquid and solids inside the casing until the solids reach a velocity at which they exit the casing. Recirculation of solids will occur below this exit velocity; it creates wear in the casing and also increases damage to soft solids. This problem has been overcome by designing and casting the pump casing with an “axial spiral”. Visualize an automobile Examining modern vertical pump designs. Several tire to represent the basic design of a recessed-impeller casing. other design features deserve to be highlighted after first examinCutting the tire at the top and then twisting it yields a spiral. In ing a fully recessed impeller cross-section view (Fig. 2). Underlike manner, the spiral contour helps guide solids out of the casing; it prevents pump internal recirculation of solids. It has been demonstrated on many occaSpark Maximum Pipe Pipe sions that this design substantially improves arrestor liquid level support support the true overall pump hydraulic efficiency. probe Additionally, the axial-spiral twist has greatly reduced component wear and damage to solids being pumped. As a further point of interest, the minimum flow capaZone 1 Ball valve bility of a recessed-impeller pump is much Zone 0 lower than that of conventional radial-spiral Minimum liquid level probe casing design pumps. On the minus side, By-pass top centerline discharge implies a measure Minimum liquid level of vulnerability when pumping large hard solids. Solids such as rocks might, on rare Vortex pump type Strainer occasions, smash through the casing neck. In some rock feed applications, tangential discharge might be viewed as an advantage. Where solid size is reduced (such as with the FIG. 1 A modern vertical enclosed shaft-driven sump pump with a recessed impeller. Zone Zero pumps) this vulnerability is no longer applicable.

ertical enclosed shaft-driven sump pumps are selected in many processes where safety and reliability concerns prompt the reliability-focused to question certain lesswell-designed pumps. We now find vertical enclosed shaft-driven pumps applied in chemical, petrochemical, gas production, fuel storage and other industries. They are especially important in explosion-proof areas where only the best-engineered pumps merit closer consideration. One such thoughtfully engineered pump design (Fig. 1) is comprised of a single-stage, end-suction “back-pull-out”-type casing. Its hydraulic end is located below the liquid level and connected to the motor by means of an extended shaft. This shaft is housed and supported in a rigid tubular intermediate pipe. The design described here is certified for explosion-proof areas that are classified as “Zone Zero”. Its drive motor conforms to regulations found in the European Electrical Standards and described in EN 50014.

HYDROCARBON PROCESSING MAY 2009

I 23

SPECIALREPORT

85%

FIG. 2

MAINTENANCE AND RELIABILITY

15%

Recessed impeller principle. FIG. 4

FIG. 3

Impeller mounting provisions include washer and O-rings to reduce risk of product seeping into the impeller bore.

So, reliability professionals are encouraged to look for unique casing design features in an advanced vertical pump. Only the most modern vertical pump casings incorporate an internal semiaxial spiral; this contour contributes to improved hydraulic efficiency while maintaining open and free flow throughout the internal spaces of these advanced recessed-impeller pumps. Look for completeness of installation. For ease of main-

tenance, all machined mating faces must incorporate locating registers or rabbeted fits. A tapered adapter piece forms the transition from pump to drive motor; it too has locating tabs to ensure correct and fully aligned centerlines of both motor and pump. Access ports to a nonsparking flexible coupling are provided on opposite sides of the adapter piece. These ports are designed with perforated metal safety covers or personnel guards; the operator’s hands stay out of rotating parts’ range. Locating tabs and rabbeted fits goes a long way toward simplifying and speeding up maintenance. Thus, when a modern vertical pump is reassembled, its components are self-aligned by design. Impellers 24

I MAY 2009 HYDROCARBON PROCESSING

Weld-neck flange detail illustrates attention to userfriendly installation.

are typically fastened to the shaft by a parallel key and locked into position with an impeller screw and sealed washer (Fig. 3), thereby completely sealing the shaft end from the pumped liquid. Note the large sole plate in Fig. 1; it also serves as a pit cover, which facilitates mounting the unit on top of a tank. The discharge pipe is secured to the sole plate by a weld-neck flange (Fig. 4); the pipe passes through the sole plate and terminates in a loose flange above the sole plate. This provision both ensures and simplifies matching the pump discharge pipe to the customer’s piping. Compliance with many existing industry regulations mandates fitting the pump with a minimum flow bypass. The bypass pipe branches off from the discharge pipe and is led back into the tank through the sole plate. The design highlighted in Fig. 1 also includes two explosion proof-rated minimum liquid level probes mounted on the sole plate. One probe monitors the liquid level in the tank, the other monitors the liquid level in the column pipe. The spark arrestor was mentioned earlier; note that ball valves are fitted on either side of the arrestor. Modern vertical pump designs are typically provided with a single mechanical shaft seal behind the impeller and seals are often mounted on a replaceable shaft sleeve. A bottom journal bearing is used and it, too, is mounted on a separate, replaceable shaft sleeve. When necessary to accommodate greater pump lengths, intermediate bearings are employed and located between the flange joints of the intermediate pipes. As was done with the bottom journal bearing, these intermediate bearings are also mounted on separate, replaceable shaft sleeves. The intermediate column pipe is filled with oil; this liquid column provides lubrication to the journal bearings and also encases the drive shaft. Two angular contact ball bearings are fitted at the drive shaft end. Whenever more than one shaft section is required to accommodate the pump length, rigid intermediate flange couplings are used. To prevent fluid traveling up the shaft, a liquid thrower (flinger disk) is fastened to the shaft. Why recessed impellers are used. Many processes require handling free-flowing slurries, sludge and fibrous materials. If used in these services, a standard centrifugal pump may clog, become vapor-bound or wear excessively. In contrast, fully recessed impellers (Fig. 1) exhibit “gentle pumping action”. Only an estimated 15% of the total throughput makes contact with

MAINTENANCE AND RELIABILITY the fully recessed impeller. These pumps are typically available in flow capacities approaching 100 l /sec (1,580 gpm) and heads ranging to 130 m (430 ft). Recessed-impeller pumps have been around since the 1930s. Unfortunately for the user, a number of manufacturers offer recessed-impeller pump configurations that have not advanced from their respective configurational or hydraulic performance constraints for 40 or more years. It is also fair to point out that some models require maintenance involvement to an extent that was considered acceptable decades ago, but is no longer tolerated in today’s best-of-class facilities. In essence, a number of important characteristics and advancements separate one make or design of recessed impeller from another. The very best manufacturers of vertical enclosed shaft-driven sump pumps with recessed impellers have set themselves apart from the rest by important design advances. Good commercial models first became available in the mid-1950s. Since then, even the good original designs have experienced a number of seemingly small, yet important, upgrades. Only the overall vortex-type operating principle has remained the same for best-of-class manufacturers. Successive iterations have consistently advanced relevant efficiency and the ability to handle solids with minimum damage to either the pump or the material being pumped. It is thus worth understanding and considering how some recessed-impeller pumps command a slight premium in initial cost. These are the ones that quickly return the incremental outlay by lower operating, maintenance and life cycle costs. Beware of misunderstood efficiency quotes. In many cases users and engineering

design contractors elect to place emphasis on pump efficiency. When asked to define efficiency, they inevitably refer to power draw. That, unfortunately, is seriously wrong. Some pumps achieve seemingly high hydraulic efficiency by simply letting the impeller edge protrude into the casing. Protruding impellers, of course, limit unimpeded passage of solids through the pump. Reliability professionals are urged to re-think what is of true importance here: the efficiency with which both liquids and solids are being transported. Many “old style” recessed-impeller designs have simply not progressed much since their initial introduction to the marketplace. Their best operating points (BEPs) are typically in the range of 30 to 40%. On the other hand, advanced designs incorporating axial-spiral design casing internals and fully recessed impellers will have true and effective BEPs around 50 to 60%. Less energy goes into the liquid and less power is consumed to forward-feed the solids. In addition, there is less wear sensitivity with fully recessed impeller configurations. HP Select 153 at www.HydrocarbonProcessing.com/RS 䉴

SPECIALREPORT

Heinz P. Bloch is HP’s Equipment/Reliability Editor. A practicing engineer and ASME Life Fellow with close to 50 years of industrial experience, he advises process plants on maintenance cost-reduction and reliability upgrade issues. His 16th and 17th textbooks on reliability improvement subjects were published in 2006.

Ron Franklin is the export sales manager of Emile Egger & Cie (Switzerland) with whom he has been working for the past 22 years. During his 37 years in the pump industry, he has been involved in sales and marketing and by utilizing his “hands-on” experience has also contributed to decades of commissioning and after-sales support. Mr. Franklin initially spent 11 years selling pumps to industry in the UK and 22 years selling internationally with primary emphasis on North America and the Far East. www.woodgroup-esp.com

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MAINTENANCE AND RELIABILITY

SPECIALREPORT

Risk-based inspection, a panacea for plant failures? Understand the limitations for an effective implementation S. K. PULLARCOT, International Inspection Centre W.L.L., Kuwait

R

isk-based inspection (RBI) acquired momentum in the late 90s and is being implemented in almost all the industries across the world. RBI is a powerful scientific management tool in optimizing inspection manpower and equipment resources. However, its unscrupulous implementation without identifying the real limitations of the systems will only yield surprising results after a period of time, which will give the impression that RBI is not an effective tool. Therefore, RBI should be implemented with utmost dedication and sincerity, and by duly identifying and acknowledging the inherent deficiencies of the system which shall be given due consideration and remedied accordingly while implementing. I would like to highlight the various deficiencies associated with RBI. Consider the case of a pressure vessel in hydrocarbon service that operates at a certain temperature and pressure. What is the risk it poses to the surroundings? How can it be quantified? As such, the guidelines provided by the American Petroleum Institute (API) are general and not specific to any industry, leaving out the specifics that are unique to the said equipment for specific service. Moreover, the assessed risk of any operating vessel could be different when assessed by two different individuals. This becomes worse when these two individuals assess the risk with two different methods for arriving at a quantified risk figure. But what is reality? Under certain service conditions, the risk associated with an operating pressure vessel is the same irrespective of who evaluated the risk and what methodology was used. This eventually leads to two different risk figures that may be widely different, if based on different methodologies used for assessment as well as the level of competency of the evaluator. In such instances, the basis on which the RBI is built is bound to collapse at a later date. Though RBI is based on mathematical models that are sound and logical enough, the reliability and dependability of the same is affected by the basic input data. In all probability, the input data will be deficient because of the reasons stated which will question the very credibility of RBI itself, when failures occur contrary to predictions. In addition, during the equipment service life, deterioration of varying magnitudes takes place based on the severity of service such as the pressure and temperature conditions, cyclic loading, corrosion rate of fluids contained, etc. The guidelines for RBI, API 580 and 581, list various damage mechanisms operating in the oil industry. However, those mechanisms may not be the only ones contributing to deterioration. For example, a stainless steel vessel situated near a seashore experiences external deterioration from a chloride atmosphere prevailing in that area in addition to the usual deterioration mechanisms acting inside the vessel or

piping. So a more judicious thinking and application of logic by the evaluator of the failure mechanisms are required. Therefore, any RBI methodology that relies only on API guidelines is not going to provide a realistic picture of the actual deterioration taking place in the vessel. The resulting error that can creep into the system further affects the credibility of RBI which may only be realized 10 or 15 years after introducing RBI. An overview of the typical RBI implementation strategy adopted by the oil and gas industry is shown in Fig. 1. The principal areas of concern in RBI are shown in Fig. 2. To improve the reliability and dependability of RBI as an effective and rewarding program, serious consideration shall be given to aspects identified as “A” and “B” in Areas 1 and 2 respectively. Therefore, every industry implementing RBI has to pay attention to the areas of concerns and the following approach is proposed to alleviate the issues to a great extent. As desired in RBI guidelines, this shall be applied to all static equipment and piping to make it comprehensive for the entire plant. As mentioned earlier, the impediment to a reliable RBI is the subjectivity of the individual assessing the risk (initial/in-process) associated with equipment and piping. The only way to reduce the subjectivity is by increasing the database and to arrive at the

Baseline data collection

Probability of failure

Risk ranking

Consequence of failure

Inspection program

Mitigation program (if any)

Maintenance inspection data

Reassessment FIG. 1

Typical RBI implementation strategy.

HYDROCARBON PROCESSING MAY 2009

I 27

MAINTENANCE AND RELIABILITY

Process description Process and inst. diagram

Material of construction

initial/in-process risk figure of the equipment and piping and so also the consequences of failure. The first step to achieve this is to list the various risk elements associated with the equipment/piping under study. Upon listing all the risk elements, severity of each element should be rated in a numerical scale. This numeric figure shall be based on a qualitative quantification made by the evaluator based on guidelines to be developed for the purpose depending on the unique process peculiarities. As the number of parameters identified increases, the reliability, and thereby the dependability of the figures improves, resulting in more reliable risk values. Since the whole RBI scheme is built on these figures, the reliability of the primary risk values plays a vital role in the reliability of the RBI system itself, which can be termed as a semiquantitative methodology. Therefore, asset owners should carry out a risk evaluation associated with each vessel in a detailed manner that shall be worked out based on the working parameters, design philosophy and construction of their plants. For example, the risk associated with a vessel is different when a safety valve is provided compared to another vessel operating at the same operating parameters without it. Similarly, when a trip system from a DCS is enabled, its risk value reduces considerably. Such a study requires the involvement of a learned engineer who is conversant with the design/operating considerations and parameters. The group has to develop a questionnaire with multiple-choice answers based on these considerations. The question and answers shall be designed in such a fashion that any engineer or operator with a bit of experience (two or more years) shall be

Configuration of eqmt./piping

SPECIALREPORT

Process data sheet Eqmt./piping data sheet

Initial risk assessment A Likelihood of failure

Consequence of failure Risk assessment

Development of RBI program

Area 1

Area 2 Inspection

Corrective action

Findings

B

Apply D factors

Apply E/D factors B

Risk assessment Modified likelihood of failure FIG. 2

Modified consequence of failure

Principal areas of concern in RBI.

able to feed in the required data with reasonable accuracy. The documents they need to answer this questionnaire are the data sheet and drawing pertaining to the equipment and also the material specification and isometric drawings for the piping. However, for answering a few questions, they may need the help of the operations group which can be concluded quickly, provided they consult with the right operating staff. Since the subject proposed involves many disciplines from engineering and management, the expertise of all these groups is required. However, if the questions are broken down into the simplest possible level, answering them can be made very simple. Moreover, because of the extended database questionnaire generated against each vessel/piping loop, the subjectivity of the individual is reduced considerably in the assessed component risk values, thereby resulting in improved reliability of the assessed risk. Increasing the database of attributes to risk alone would not improve reliability of the risk figures for equipment and piping. Therefore, the obvious second step shall be to arrive at a realistic weighting factor for these attributes that also have significant bearing on the risk figures arrived at for each vessel and piping loop. This is not easy since it involves concerted efforts of process, mechanical and instrumentation engineers from disciplines like operation and technical services, maintenance, inspection and instrumentation. This has to be accomplished in the study Select 154 at www.HydrocarbonProcessing.com/RS 28

MAINTENANCE AND RELIABILTIY through a sample survey to be carried out by qualified and experienced engineers/technicians from these disciplines. When steps 1 and 2 are completed, one can arrive at realistic risk figures (initial risk) for all process equipment and piping systems. As the third step, the risk figures shall be revalidated periodically based on inspection findings from routine and periodic inspection activities. For example, the actual corrosion rate observed during periodic inspection may be less or more than that predicted initially. Therefore, this rate has to be revalidated based on inspection findings. Lastly, the inspection methodologies proposed for each equipment and piping loop shall be critically evaluated to ensure that they are capable of revealing the deteriorations predicted. Past experience with similar equipment/piping and an awareness of the predominant damage mechanism in such systems would be an added advantage in this regard.

SPECIALREPORT

Mr. Pullarcot has more than 27 years’ experience in the manufacture and QA/QC of pressure vessels, heat exchangers, storage tanks, plant and offsite piping and construction activities of fertilizer, chemical, petrochemical and oil/gas projects. He is a Fellow of the Institution of Engineers, and a member of the Nondestructive Testing Society of India and the Indian Institute of Welding. Mr. Pullarcot received a BSc degree in 1981 in mechanical engineering from the University of Kerala, India, and an MTech degree in production engineering in 1990 from the Cochin University of Science and Technology, Kerala, India. He is the author of the book Practical Guide to Pressure Vessel Manufacturing, published by M/s Marcel Dekker Inc., New York, in January 2002 under ISBN 0-8247-0740-0. His second book, Practical Guide to Construction, Inspection and Testing of Above Ground Storage Tanks, is in an advanced stage of publishing. He is a well-known trainer on QA/QC, welding and NDT, and is recognized as a global instructor by the American Society of Mechanical Engineers (ASME).

■ Since the cost involved

in implementation is only the additional manpower required, the benefit by way of increased plant reliability is expected to be much in excess of the cost. If these RBI aspects are taken care of in a detailed manner, it would definitely improve plant reliability. However, it shall be noted that every requirement has its implications with regard to money and time. Since the cost involved in implementation is only the additional manpower required, the benefit by way of increased plant reliability is expected to be much in excess of the cost. Therefore, this proposal is a worthwhile exercise by which RBI reliability can be substantially increased. I am in the process of developing such a system for a surface production facility in oil and gas. The system thus developed shall be more or less applicable to almost all surface production facilities across the world with minor modifications to customize it to the specific environment of individual producers. HP

Sunil Kumar Pullarcot works as a specialized inspection consultant with the inspection and corrosion team of Kuwait Oil Company (KOC). Prior to this, he worked with FACT Engineering and Design Organization (FEDO), India, a premier consultancy organization in South India in various capacities. Select 155 at www.HydrocarbonProcessing.com/RS 29

Select 101 at www.HydrocarbonProcessing.com/RS

MAINTENANCE AND RELIABILITY

SPECIALREPORT

Proper gasket removal and replacement can reduce maintenance and increase uptime Follow these guidelines for trouble-free performance T. HURLEY and D. BURGESS, Garlock Sealing Technologies, Palmyra, New York

T

he gaskets that keep flanged joints in piping systems from leaking are relatively low-cost but highconsequence components that can spell the difference between efficient, profitable operations and unscheduled outages, lost production and penalties for noncompliance with environmental regulations. However, they often do not receive the attention they warrant from plant operations and maintenance personnel. Gaskets perform two basic functions— creating an initial seal and maintaining that seal over an extended time. To perform these functions effectively, they must retain their integrity during handling and installation, and be sufficiently deformable to flow into imperfections in flanges. And, they have to be strong enough to resist crushing under applied loads and blowouts under system pressures. Moreover, gaskets in flanged joints have to be chemically compatible with system fluids, withstand extreme temperatures, and be resilient and creep-resistant to maintain adequate load. It is important that they not contaminate the system or promote corrosion of the seating surfaces, and can be easily and cleanly removed at the time of replacement. Removal of spent gaskets can be a tedious, laborious and often time-consuming task that can damage equipment and extend outage schedules. Flanged joints are often in difficult-to-access areas. In addition, flanged joints can be hard to separate, making it difficult to see where the gasket is located and remove it with flange gaps of ½ in. or less. Under such conditions, it is small wonder there have been instances, however ill-advised, of new gaskets being installed directly over old ones—with predictable results.

Even a small fragment of gasket left on a flange can make it impossible for the new gasket to conform properly, resulting in an immediate leak. Or it might produce a high stress point, around which sufficient load cannot be developed to maintain an effective seal for the useful life of the gasket. Besides causing premature gasket failure, such fragments can break loose from the flange and contaminate the fluid in the system or impair performance of downstream equipment such as pumps and valves.

■ Removal of spent

gaskets can be a tedious, laborious and often timeconsuming task that can damage equipment and extend outage schedules. Avoid use of lubricants. In some cases, installers apply bolt-thread lubricants to gaskets to facilitate removal. If the gaskets contain nonoil-resistant binders, such lubricants can chemically attack them, softening the binders and reducing their crush strength. These lubricants also reduce the friction between the flange and the gasket, causing the gasket to extrude and eventually blow out. Metal in the lubricants can bond to flanges and fill in surface serrations that bite into the gaskets and hold them in place. In addition, the lubricants can enter the process stream and contaminate the system fluid, and they can bake off at elevated temperatures, leaving a problematic void between the gasket and flange.

Some installers use caulk to affix gaskets to flanges or to compensate for damaged or irregular flange surfaces. However, some caulks contain acetic acid-based cure systems that can attack elastomeric gaskets and gaskets containing rubber binders. Because of their lubricity, caulks also can cause gaskets to shift within the flange assembly and, as with the lubricants, can lead to the same loss of friction, crush strength and blowout resistance. Gaskets should be installed as received, or using only products specifically designed to hold them in place. Any flange inconsistencies should be corrected prior to installation of the gasket. Many gaskets, except those made of PTFE which do not require it, are coated with antistick agents. If it is necessary to apply more of these compounds to a gasket before installation, it is always advisable to use dry materials, such as talc, graphite or mica. Metallic-based agents should never be used because, as with certain lubricants, metal particles may accumulate in surface serrations, making the flange surface too smooth to be effective. A proprietary, antistick agent is now available to speed removal of gaskets from flanged joints. The new material is a high-temperature, inorganic coating that dramatically reduces the time and effort required to remove gaskets after extended service—in most cases seconds versus hours and with just a fraction of the force required to remove untreated gaskets. Unlike most antistick agents, the material is fused to the surface of the gaskets and does not contain chemicals that can cause them to crack or otherwise degrade. In the process of developing the material, it was learned the binders in compressed HYDROCARBON PROCESSING MAY 2009

I 31

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sheet gaskets act as visco-elastic materials that tend to flow at elevated temperatures and pressures. As the binders “wet out” and make intimate contact with the metallic flange face, chemical adhesion, mechanical interlocking and other modes of adhesion come into play. The new antistick compound acts as a barrier that prevents the binders from “wetting out,” and because they can be removed intact, gaskets treated with it are easier to dispose of properly. Proper gasket removal. Replacing used gaskets begins with removing all flange fasteners, including bolts, studs, nuts and washers, and replacing any that are worn, corroded or otherwise damaged. The flanged joint should be carefully opened using a special flange-spreading tool or soft wedges so as not to damage the flange seating surfaces. The old gasket can then be removed. This is best accomplished by using an aerosol gasket remover or, if necessary, a brass scraper that will not nick, scratch or gouge the flanges, the surface of which is critical to achieving the necessary friction for an effective seal. After removing the old gasket, the flange facings should be inspected for imperfections that can adversely affect the new gasket’s ability to seal. If surface damage exists, it may be necessary to re-machine or replace the flange. Acceptable surface finishes should range between 125 and 250 micro-in. Flanges should be free of foreign material. Residual debris can be removed from the serrations by scouring the flange surface with a brass wire brush in a rotary, not linear, motion. After the old gasket has been removed and the flange faces cleaned and conditioned, the replacement gasket can be installed. Selecting the new gasket depends upon a number of variables. Whenever possible, thinner gaskets should be used unless the flanges are warped, bowed or severely pitted, in which case a thicker gasket will be needed to compensate for these irregularities. It should be noted, however, that thicker gaskets require higher compressive loads, which may not be obtainable in the application. Use of ring gaskets is preferable to full-face gaskets, which typically cover twice the area. This extra material also requires greater torque to compress. Where one or both flange faces are flat and made of soft or brittle material, a full-face gasket might be needed to prevent flange rotation. Once the replacement gasket has been selected, it should be inspected for correct ID, OD and appropriate thickness. If it has

cracks, gouges, folds or other surface damage, it should not be used. For ease of installation, all fasteners should be lubricated with an oil-and-graphite mixture or other suitable thread lubricant, being careful not to allow it to come into contact with the gasket. Flanges with vertical seating surfaces should have at least two fasteners inserted into the bottom holes to support the gasket. Proper gasket replacement. The gasket can now be inserted between the flange seating surfaces, however, care should be exercised to avoid damaging the gasket. The flange spreader can then be carefully removed, allowing the flanges to come together, and the remaining fasteners inserted and tightened or “snugged.” The pattern in which the bolts are tightened is extremely important. If done improperly, the flange can move out of parallel. Refer to the gasket manufacturer’s literature to determine the appropriate bolting pattern for the application. Using calibrated torque and box-end type wrenches, tighten each fastener to no more than one-third of the desired torque value to uniformly compress the gasket. Repeating the same pattern, increase the torque wrench setting to two-thirds of the desired value. To achieve the final torque value, repeat the pattern again at the target torque value, and finish with a circular “check pass,” moving from one fastener to the next in a counter-clockwise sequence to ensure each fastener is applying the same load. The gasket should now be properly installed and capable of operating at a high performance level. The process of removing and replacing used gaskets is every bit as critical as initial gasket selection and installation. Antistick agents, aerosol gasket removers and specialized tools all can facilitate gasket removal without damaging flanges. Provided flanges have been cleaned, repaired or replaced as needed and the replacement gasket has been installed properly, the flanged joint should provide trouble-free performance until the next changeout is scheduled. HP Tim Hurley is senior product manager, gasketing for Garlock Sealing Technologies.

Dave Burgess is senior applications engineer for Garlock Sealing Technnolgies.










 

 


 


 


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MAINTENANCE AND RELIABILITY

SPECIALREPORT

Improve cooling tower gear drive reliability Applying commodity products instead of engineered solutions can cause premature failure J. DeBAECKE, Philadelphia Gear Corp., King of Prussia, Pennsylvania

C

ooling tower applications can present a unique dilemma. Large cooling towers typically contain a number of cells; each cell contains a fan unit or fan “train” made up of a drive motor, gearbox and the actual cooling fan assembly (Fig. 1). Because they are identical, the motor-gearbox-fan trains in a given cooling tower are sometimes collectively viewed and treated as mass-produced “commodity” items. Suffice it to say that commodity items often differ from thoughtfully engineered and reliability-focused products. The focus of this article is primarily on larger multiple-fan cooling towers that employ double-reduction enclosed gears (called “gearboxes”) in each train. The gearing in a train receives its input from the motor and the gears reduce this speed to fan speed. Multicell cooling towers and their respective equipment trains are primarily found in power plants and refineries. The gearbox typically consists of a first-stage reduction-bevel gear set and a second-stage reduction parallel-shaft gear set. This doublereduction configuration transmits rotational torque from a horizontally oriented motor to a vertically oriented fan shaft. However, many of the concepts and ideas discussed are also applicable to single-reduction cooling tower gear drives. These consist of a single-reduction bevel-gear set that transmits power from a horizontally oriented motor directly to a vertically oriented fan shaft. Either way—most cooling tower applications are quite demanding. The service often requires unique component capa-

bilities to meet a number of environmental and operational objectives. Yet, with price being the key factor, the various parties (seller, user and purchaser) often concentrate on low-cost and quick-fix product solutions. In most cases, these solutions conflict with the user’s ultimate need for high reliability and long equipment life. Operational challenges explained. Almost all fan drive

systems or “trains” are mounted at the top of the cooling tower structure—well above ground level. The gearbox is located in the center of the cooling tower cell and directly under the large fan (Fig. 2). In addition to being relatively inaccessible, the gearbox is enveloped in water vapor. On commodity-style equipment, even the simplest preventive maintenance activity (such as checking the oil level in the gearbox) can be difficult. Moreover, the oil level cannot be monitored while the fan is operating and much of the train is difficult to access even if the fan is stopped. Another operational challenge that the drive components may have to face is weather related. In some geographic locations the fan blades may end up covered with ice. Therefore, the gearbox and other parts will have to be sized and designed for the additional loads attributable to substantial weight increase and/or mass unbalance. The same gearbox that was primarily designed to be cost-competitive is now subjected to actual operat-

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FIG. 1

A cooling tower with nine identical cells. Each cell contains a fan and double-reduction gear; the electric drive motors are situated outside the cells (Source: Lubrication Systems Company, Houston, Texas).

Note: Any “SAG” left in the “breather” line will result in trapped condensate and positive pressure in the reducer. FIG. 2

The gearbox is located directly under the fan.

HYDROCARBON PROCESSING MAY 2009

I 35

SPECIALREPORT

MAINTENANCE AND RELIABILITY

Groove in shaft from lip seals

FIG. 3

Evidence of moisture intrusion and lip seal damage. Rotary seal position

ing conditions that are beyond the range of initial expectations and specifications. Visual determination of shaft seal integrity. Com-

modity gearbox designs operating at relatively low speeds, i.e., 900–1,800 rpm input speeds and output speeds not exceeding 100 rpm, will usually contain lip-type shaft seals on both input and output shafts. The inside diameter of a lip seal tapers to a point where the stationary rubber lip rides on the rotating shaft. A circumferential spring is employed to exert pressure on the

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Lip seal (upper portion) and modern rotating labyrinth seal (lower portion).

rubber to seal against the shaft. The key to obtaining maximum lip seal life is to ensure that it is always lubricated. Lip seals are cost effective and, when properly applied, can last for two years. Yet, they are susceptible to several possible failure modes. If they do not receive a constant minimum amount of lube oil or grease (grease would have to be applied externally), the seals will wear and begin to leak (Fig. 3). Unless the leakage is stopped, the oil level in the gearbox will drop and gear and bearing failures may result. If the leaking shaft seal cannot be seen from ground level or from the drive motor location, gear or bearing failure will occur before lack of lubrication can definitely be identified as having caused the problem. Fortunately, superior seals with dual O-rings doing the clamping to the shaft and a special dynamic O-ring sealing against a generously contoured stationary surface (Fig. 4, lower portion) are now available. Protector seals with these design features are more stable and will last longer than lip seals or earlier-vintage rotating labyrinth seals. Advanced bearing housing seals are certainly very often considered by reliability-focused users. Operating with dirty oil. Low-speed commodity gear drive designs are often splash lubricated. With splash lubrication, a gear element or flinger disc attached to a rotating shaft dips in the sump oil and either directly throws oil to bearings and gear meshes, or splashes the oil into a series of oil troughs or flow passages that lead to bearings and gear meshes. Commodity gear drives also typically are not supplied with lubrication oil

MAINTENANCE AND RELIABILTIY filters. All submerged bearings need no further special attention other than maintaining lubrication oil in the gear housing because the rationale is that seals and breathers will keep out dirt, and periodic oil changes will remove any contamination generated within the gearbox. But typical lip seals will only function as designed if they are properly lubricated with clean oil. Neglecting to change gear oil on a regular schedule will lead to progressive increases in lube oil contamination. Due to the inaccessible location of the gearbox and compromises often made on its overall configuration, changing oil becomes difficult. Dirty oil will in time abrade the lip seal material and begin the leaking discussed and oil deprivation will cause lip seals to degrade even more rapidly.

SPECIALREPORT

changes in sound patterns. However, the operator has to be in reasonable proximity to the unit to hear relevant changes. It would not be practical for the operator to stand next to an in-service gearbox located four stories above ground level and operating under a set of rotating fan blades. With traditional ways of monitoring equipment noise being fruitless on cooling tower fan trains, one often waits until the fan blades stop turning or the drive motor trips out on overload. Short of these events it is typically reasoned that the gearbox must be in good working order. Remote equipment monitoring. Remote equipment

monitoring is among the best ways of assessing equipment con-

Water in the lubrication oil. Water in lubrication oil can generate a multitude of problems and Fig. 3 gave us a glimpse of corrosion damage. Water will adversely affect lubricant viscosity and its heat removal capability; it will also negatively influence oil film thickness and gear mesh and bearing component protection. Rust formation during downtime as well as temperature changes that promote moisture condensation on gearing, bearings and housing internal surfaces represent potentially serious contamination generators. They morph into a destructive presence that leads to drastically reduced gear life. There are several other conditions that, if combined with water, can shorten gear drive lifespan. If water is present at elevated operating temperatures in conjunction with an extreme pressure (EP) additive oil, there are many deleterious possibilities. Typical EP additives are phosphorous and sulfur. At sufficiently elevated operating temperatures a typical EP mineral oil may create a solution of water (hydrogen and oxygen), free sulfur and phosphorous. Molecular activity and ionization may take place. Even a small amount of salt water has the potential of generating different kinds of corrosive acids and compounds that can ruin a gear set in a period of only a few hours to a couple of days. Modern plants have often placed a blanket of oil mist in the free vapor space above the liquid oil in the gearbox sump. At a very slight positive pressure, the oil mist (a mixture of 200,000 parts of instrument-quality air with one part of oil) prevents influx of atmospheric contaminants. Together with well-engineered gears, couplings, support bearings and cooling fans, some gear units have successfully operated for 20 years. Noisy operation. Perceptive operators are among the most valuable plant assets. Operators who are consistently patrolling and monitoring noise from the same operating equipment can often hear subtle Select 158 at www.HydrocarbonProcessing.com/RS

37

SPECIALREPORT

MAINTENANCE AND RELIABILITY there are usually several fan drive trains and more than one piece of monitoring equipment may be required per train. We have discussed some of the more obvious challenges posed by cooling tower applications. Some of the remedies are costly and may not be good investments for the long term. However, there are many cost-effective actions that can be taken during the initial purchase of the cooling tower system; there are also some that can improve operation of units already purchased and presently in service. EXISTING COOLING TOWER GEAR DRIVES

Some of the components shown in Fig. 2 can be retrofitted and constitute important upgrades.

ut

ion s

Sinc e

1942

Proper enclosed gear drive breathing. Like living creatures, most enclosed gear drives need to breathe to attain their full lifespan. Included in the scope of supply of these gearboxes FIG. 5 Poor lubrication often affects the upper cooling tower is usually some sort of breather to permit internal gear casing gear drive output shaft bearing first. pressures to equalize with atmospheric pressure when the gear drive’s operating temperature causes the air in the gear housing dition. It pre-warns of impending problems and presents an to expand. If the expanding air volume cannot equalize with the opportunity to fix a small problem before it turns into a big one. ambient atmospheric pressure, or unless suitable face-type seals However, remote monitoring requires suitable sensing equipment, are provided, elevated internal gearbox pressures can cause certain vibration probes, temperature probes, etc., and the ability to read shaft seals to leak. To avoid this condition, the breather allows the measured parameters at a remote and safe location. Unfortucontinuous pressure equalization so oil leakage does not become nately, most cost-competitive commodity gear drives come with a problem. The type of oil breather chosen and how it is installed little to no monitoring equipment; there are no vibration sencan make a significant difference in gear drive long-term health. sors, no temperature probes and no pressure monitors. Another In most cases, commodity-type gearboxes are furnished with impediment to cooling tower gear drive surveillance is the cost commodity-type breathers. The breather does the minimum job associated with such instrumentation. As was brought out earlier, of allowing air pressures between the gearbox internals and the surrounding atmosphere to equalize. Any moisture in the air is permitted to enter or exit the gearbox based on prevailing conditions. Once moisture has entered the gear housing, it may condense on bearl ings, gear elements, housing surfaces, and So l a mic Safe Che into the lubricating and cooling oil itself. An upgrade from the commodity-type breather is the oil bath breather that forces the atmosphere through a small volume of oil. This oil s (EAVY$UTY)NDUSTRIAL s $EEP0ENETRATING s #LEANING$EGASSINGOF is located in a mesh at the bottom of a goose $EGREASER &OAMING#OIL#LEANER 2ElNERY0ROCESS6ESSELS neck; it will retain the moisture and prevent s 2EMOVES0ROCESS s 2EMOVES/ILS s !PPLIEDIN%ITHER it from entering the gearbox or gear housing. 3IDE(YDROCARBON #ALCIUM $UST $IRT #IRCULATIONOR6APOR The oil bath breather works well as long as the #ONTAMINANTS AND/THER$EPOSITS 0HASE!PPLICATIONS oil does not build up and spill back into the s &AST 3AFEAND s &AST 3AFEAND s &AST 3AFEAND gear drive housing. Because of the gearbox "IODEGRADABLE "IODEGRADABLE "IODEGRADABLE location, it is difficult to perform scheduled breather cleaning maintenance with ease. &ORTHEFULLLINEOF29$!,,PRODUCTS VISIT www.RYDALLDEGREASERSCOM There is, however, a simple piping arrangement that can make breather draining of moisture simple and safe. It is possible to pipe the breather through a pipe “tee” and angling a pipe run to drain from the unit 29$,9-%ISSPECIlCALLYDESIGNEDTODISSOLVETHE directly under the fan to an accessible area TOUGHESTWATERSCALE LIME MUDANDRUSTDEPOSITS near the externally located drive motor. A FROMVIRTUALLYANYPIECEOFWATER BASEDEQUIPMENT small petcock can be opened periodically near &OR MORE INFORMATION ON 29$,9-% VISIT the drive motor to drain accumulated moiswww.RYDLYMECOM ture that collects in the breather and drains into the angled pipe. The long pipe acts as 3HORELINE$RIVEs!URORA )LLINOISs  s&AX   both a reservoir for moisture collected by the breather and a gravity conduit to remove the Select 159 at www.HydrocarbonProcessing.com/RS 38

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moisture before it reaches the gear drive. Since the pipe run is fairly long, several days or weeks worth of moisture can be collected and stored by the pipe before the accumulated water might enter the gear drive housing. Of course, an oil-mist purge (see above) would be superior in some installations and locales; it, too, should be considered, if cost-justified. Maintaining lubrication oil. Operat-

ing the gear drive with dirty, low or no lube oil can reduce or drastically shorten gear drive service life and increase the chances of surprise catastrophic failure and unscheduled downtime. Such failures have often affected the upper cooling tower gear drive output shaft bearing first (Fig. 5). Chances are that a failed upper bearing was splash lubricated by either a flinger attached to a rotating element or a dipping gear that was no longer throwing or dipping because of low levels or no oil at all. How can we ensure that checking oil levels and replenishing lost or consumed oil is safe and practical? By running another pipe from a cooling tower gear housing tap in the bottom half of the housing out to the drive motor area, an oil sight gage and fill tap can be located in an area remote from the rotating fan blades where oil level can be checked and restored. With only minor piping modifications, operators can drastically reduce or at least partially neutralize the two major causes of cooling tower gearbox failure: lack of lubrication and water contamination of the oil. Using synthetic lubricants. Syn-

thetic lubricants offer several key advantages over typical refined mineral oil products, whether they are rust and oxidation inhibiting or EP additive mineral oil formulations. Synthetic oils are man-made synthesized hydrocarbon liquids that are extremely difficult to break down due to their strong molecular bonds. Ordinary mineral oils lose their structure and decompose at relatively low temperatures, as low as 325°F. State-of-the-art high-power-density gear drives run hotter by design. Because of their relatively low breakdown temperatures, mineral oils are not as good a choice for high-power-density drives. Compared to synthetic lubricants, mineral oils have a considerably reduced differential between maximum allowable operating temperature and oil breakdown temperature. Hightemperature operation and lubrication oil breakdown can lead directly to both shaft seal leaks and inadequate bearing and gear

lubrication. Needless to say, oil leaks can lead to shortened gear drive service life and catastrophic gear and bearing failures. Another advantage of using synthetic lubricants is their more favorable viscosity index as compared to the indices of corresponding mineral oils. Synthetic oils possess flatter viscosity indices. That is, the synthetic oil viscosity does not reduce as much as the mineral-based oil viscosity with the same corresponding increase in temperature. In other words, one type of synthetic oil can provide an acceptable operating viscosity range over a wider temperature range without sacrificing lubrication capability. Mineral oils that perform satisfactorily at 40°F will often be too thin to operate at 125°F. At the elevated temperature, they may no longer provide an oil film in bearings and gear tooth meshes that will be sufficient to prevent metalto-metal contact. Metal-to-metal contact relates directly to accelerated bearing and gear wear and a drastic reduction in service life. To guarantee long gear life, two different viscosity mineral oils would have to be used, depending on whether the temperature was 40°F or 125°F. The price for synthetic oil can approach four to five times as much as a corresponding mineral-based oil. However, as with all products, one must weigh cost versus value. Although synthetic oil is extremely resistant to high-temperature breakdown, it is still susceptible to particulate and water contamination, and often the most expeditious way to remove that contamination is via an oil change unless sophisticated centrifuging and filtration equipment is available. Again, and in conjunction with proper bearing housing protector seals, an oil-mist blanket tends to vastly reduce contamination risk and will often be easier to cost-justify than other alternatives. Case history. This case study represents several techniques that a resourceful user employed to keep very old cooling tower gear drives operating well beyond their expected service lives. This particular user was located in South America, far away from convenient technical support. The personal safety conditions in this particular area were also in serious question. Being resourceful, this user became very adept at gearbox maintenance. In this particular refinery, there was a large bank of double-reduction cooling tower gear drives, about 20 units. These units were originally supplied with independent sumps and shaft-driven lubrication oil pumps.

MAINTENANCE AND RELIABILTIY While walking through the repair shop, one would notice several low-speed output shafts and gear assemblies laying around. The gearing was all single helical, and both gear faces on many of the low-speed gear assemblies exhibited significant usage contact patterns. Of course, cooling tower drives are typically expected to rotate in only one direction. These gear patterns indicated many hours of logged operation on both gear faces. This user had discovered the trick of removing the single-helical gear from its shaft, turning the gear over and reinstalling it back on the shaft again to use the gear face that previously was the coast side. While this can be done, it also can be risky, especially if both gear flanks are not machined identically. The user had taken the chance of the flipped gear making insufficient contact with its mating pinion. However, given the situation surrounding this user, the risk was warranted. The user was fortunate in that the original gear came from a quality supplier; both gear element “loaded” and “coasting” side flanks were fairly consistent. In this instance, flipping the low-speed gears was successful most of the time. The user’s practice resulted in substantial service life extension and fewer spare parts orders. The refinery maintenance group had acquired much knowledge and was proficient enough to know the proper shrink fit between the low-speed gear and shaft. Among other appropriate work processes they had also determined suitable run-out tolerances between the low-speed gear and shaft. If someone inspected the cooling tower proper, it was evident that the refinery crew had used its knowledge to work on the lubrication oil supply system to all 20 gear units. The original units were each individually lubricated by their own shaft-driven lubrication oil pump, but there was a large centralized cooling tower lubrication system servicing all of the drives. This common lubricating system was conveniently located at ground level and was complete with multiple pumps, coolers and filters that supplied all units with cool and clean lube oil. The remote location of the system permitted easy access for maintaining clean filters and properly operating pumps, coolers, relief valves and other critical lubricating system components.

SPECIALREPORT

■ This article has explored some positive

action steps that the user can take on existing cooling tower gear drives that are now in service. Of course, the preceding paragraphs also dealt with things that can be done if a facility is fortunate enough to start with new equipment.

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This article has explored some positive action steps that the user can take on existing cooling tower gear drives that are now in service. Of course, the preceding paragraphs also dealt with things that can be done if a facility is fortunate enough to start with new equipment. In this instance, the user’s project team might combine forces with maintenance and reliability personnel to specify and allocate funding for an engineered fan drive train that will pay back the small incremental investment many times over. Certainly, the quality of such product greatly exceeds that of a commod-

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MAINTENANCE AND RELIABILITY

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ity product designed and manufactured to barely make it through the warranty period. What should such a specification address? Below we explore some of the more desirable cooling tower gear drive value-added features that have the potential to significantly reduce unit life cycle cost with only a modest up-front cost. Anticorrosion protection. Cool-

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ing towers with fan drives operating in an enclosed cell function in one of the worst environments. Hot moisture surrounds the train components like dense and almost impenetrable fog. Even the adjacent and occasionally nonoperating cells are affected by heat and moisture. Repairs often require cranes and hoists. Before the maintenance person gains access to the fan and gear, the large fiberglass enclosure has to be removed and planking must be placed inside the cell. Designing-out maintenance requirements and building-in failure avoidance pay sizeable dividends and much soul-searching should be done before ever buying commodity components for cooling towers. A stainless steel housing might be the ultimate answer if an unlimited budget were available, but a better value proposition might be utilizing a self-curing inorganic zinc paint system to avoid rust formation on gear drive externals. For a reasonable premium, a three-part paint system consisting of a zinc primer coat (two to three mils thick), an intermediate epoxy coat (four to six mils thick) and an epoxy finish coat (three to four mils thick) can be applied to provide many years of protection.

cially in the cramped space immediately under the cooling fan. Fragile external protrusions from the gear drive are undesirable. Think of small-bore tubing and how it is incapable of supporting the weight of a human being, or think of the damage that can be caused by careless hammer blows. Wherever proper engineering expertise has been used, all bearing and gear mesh lubrication and cooling oil paths will have been contained within the housing. There will be no external lines and the cost of providing such an advantageously designed gearbox or housing will reflect in a one-time charge. Once the design exists, the incremental cost of providing internal ported oil passages is relatively small. If a particular cooling tower incorporates several identical trains (as most do), the additional engineering development cost is amortized over the total number of assemblies. Its cost then becomes insignificant and the benefit-tocost ratio is overwhelmingly large. Redundant lubrication system. As

discussed, generally, low-speed gear drives are splash lubricated. Other, often larger, gear drives utilize a shaft-driven pump to force feed oil to bearings and gear meshes. For a nominal cost, the cooling tower gear drive lubrication system can be made redundant by employing a dual system consisting of dipping gears and/or flingers and a shaft-driven oil pump supplying oil under pressure. This setup could one day safeguard the long-term availability of a cooling tower gear drive system. If the pressurizing pump is arranged so that its oil suction port is at the extreme bottom of the housing sump, even a receding oil Avoiding external piping. External level would not cause an instant calampiping invites breakage and bending, espe- ity. With the suction port so located, oil would be supplied for the longest possible time. Since leaking seals are most often responsible for oil loss, oil levels in housings are sometimes just below the lowest point of the lower-most rotating shaft. If this ever happens the pressurized redundant pumping system will avoid catastrophic failure by continuing to supply oil to all FIG. 6 Some designs incorporate a built-in filter housing. critical components even though dipping

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SPECIALREPORT

MAINTENANCE AND RELIABILITY

gears and flingers are no longer performing their intended lubricant distribution duties. Filtration. Filtration is one good way to keep your oil clean.

Since user-purchasers have the option of specifying upgraded cooling tower gear housings, they also have the ability to require designs that incorporate in the gearbox enclosure or casting a built-in filter housing (Fig. 6). There would be associated oil ports with a stainless-steel cover plate accessible from the top of the housing for quick-changing purposes. Additionally, specifying entities and designers have the opportunity to make the filter size large enough so that periodic changing can be accomplished during scheduled tower maintenance. In addition, in case the filter does get dirty, they can install a filter with bypass capability. Dirty oil is certainly better than no oil at all. And never forget the merits of keeping dirt out altogether. Read about the many decades of highly successful service enjoyed by best-of-class oil mist users. Purge mist is used on the cooling tower gearboxes and pure (dry-sump) oil mist lubricates the drive shaft pillow block support bearings and all electric motor bearings. Cooling fins. Users should consider one more enhancement

beyond those mentioned. State-of-the-art enclosed drive gear designs are of the high-power-density variety. Use of highly loaded case-carburized and precision ground-tooth gearing in a housing sized to match the gears may mean that everything is operating up to maximum limits, whether it be tooth bending and contact stresses or housing operating temperature. A smaller housing

could mean there is less surface area available to dissipate heat generated by working gears and bearings, and reduced surface areas could result in higher housing skin temperatures. Higher housing skin temperatures often lead to hot lip seals and shorter lip seal life. Higher temperature could also lead to mineral oils having a much higher probability of breaking down prematurely and coke being formed. For a few extra dollars, cooling fins can be added to certain cast housing designs. With a relatively small addition of material, gear housing skin temperatures might go down, which would benefit lip seals and lubrication oil. Again, all of these beneficial steps work toward increasing equipment service life. The message: Small improvements add up. High-end shaft seals. Lip seals were profiled as being cost

effective but susceptible to several possible failure modes. In today’s market, single- as well as dual-face mechanical seal alternatives have potentially much longer service life and are significantly more tolerant of misalignment. In addition, they can seal where a positive head of oil exists or where oil is directly impinging on the seal. For a few hundred dollars, these seals can be easily incorporated, not only in new designs, but also retrofitted into designs originally containing lip-type shaft seals. A face-type seal typically consists of rotating and static members that are separated by an oil film. Usually one member is held against the other by a spring or magnetic force, the two members being separated by only the oil film. Due to the fact that magnetic and spring-loaded face seals don’t operate well under misaligned conditions typical of many cooling tower installations, they aren’t a preferred solution in these instances. We had also alluded to rotating labyrinth seals and the most stable and advanced configuration was shown earlier in Fig. 4. Its two-fold purpose is to keep out external atmospheric contaminants and to prevent lubricants from escaping. A series of labyrinth spaces and changes in the direction of escape or entrance routes create pressure differentials. In addition, fluid turbulence is promoted to restrict flow and control leakage. This type of seal relies on gravity, the weight of the fluid and centrifugal force to create the sealing function. Output shaft umbrella. Another design enhancement

that adds very little cost calls for incorporating an output shaft umbrella. Essentially a protective flinger disc, the umbrella rotates with the output shaft and shrouds the output shaft seal from any direct fluid impingement. Fluid impingement can take many forms and can originate at many spots. It might include hot and dirty air circulated by the cooling tower fan, water spray from cascading cooling water picked up and redirected by the fan, or perhaps a water hose pointed at everything in sight by an overzealous equipment cleaner. HP

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HEAT TRANSFER

Rethink planning for heat-recovery systems Better early design of steam generators can save lots of money in operating cogeneration plants V. GANAPATHY, Consultant, Chennai, India

H

eat-recovery steam generators (HRSGs) in cogeneration plants differ from those in combined cycle plants in several ways. Steam pressure levels, steam temperatures and reheat parameters for many large steam turbines are standardized. Thus, large combined cycle plants apply steam parameters. Result: HRSG designs are optimized to generate these steam parameters. However, in the case of cogeneration plants, steam pressure, flow and temperature can vary tremendously and there can be a wide range of operating pressure levels. Cogeneration plants have the flexibility to import or export steam to or from the HRSG to be superheated in or outside the HRSG. High-pressure (HP) and low-pressure (LP) steam parameters will vary depending on plant needs. Firing temperatures will differ depending on the turbine selected and on facility steam demand. Fresh air can be used to augment steam production should the gas turbine trips or part of the exhaust gases can be bypassed for other processing needs.

tube sizes, fin configuration, etc. The pinch and approach points for the evaporator alone can be applied to determine the gas/steam temperature profiles and duty for each heating surface. Case history. A cogeneration plant requires 200,000 lb/h of

steam at 600 psig and 700°F and LP steam of 25,000 lb/h at 150 psig saturated. The feedwater is at 230°F. A gas turbine with an exhaust gas flow of 1 million lb/h (MMlb/h) at 1,000°F is available. The question is whether the HRSG should be a simple, sin-

Site-specific evaluations. Cogeneration plants, refineries

and petrochemical/chemical plants acknowledge that HRSG configurations are very site specific. Plant engineers should evaluate the HRSG and site steam parameters. The engineering team should determine the type of HRSG required and its configuration before developing purchase specifications of the unit. Early engineering work on the HRSG will save substantial monies over the long-term operation of the unit.

FIG. 1

Design of a single-pressure HRSG.

FIG. 2

Design of a multiple-pressure HRSG.

Design and discovery exercises. Simulation is a valuable

tool; it helps engineers evaluate the gas/steam temperature profiles in a multiple-pressure unfired or fired HRSG units. Engineers can evaluate the design and off-design performance for complex HRSGs using simulation tools without specifically designing the HRSG.1 The plant engineer can rough out an HRSG configuration and optimize this configuration (whether single or multiple pressure) before sending bids to the HRSG suppliers. This exercise is typically not done by HRSG suppliers—they are busy with equipment bids and inquiries. Too often, HRSGs are built based only on specifications; the designers do not have the time to optimize system parameters or determine the unit’s configuration. The following example illustrates the design/optimization benefits for a cogeneration unit by performing simulation studies on the HRSG configuration during the conceptual design phase. The designers do not need to know the HRSG’s physical dimensions,

HYDROCARBON PROCESSING MAY 2009

I 47

HEAT TRANSFER HRSG performance-design case Project-study units-British case-case1d remarks- amb temp.-°F=70 heat loss- %=1 gas temp. to HRSG °F 1,000 gas flow-lb/h=1,000,000 % vol. CO2=3, H2O=7, N2=75, O2=15, ASME eff-%=70.14 tot dutyMM Btu/h=175.

HRSG performance: Off-design case Project-study1 units-British case-case2d remarks- amb temp.-°F=70 heat loss- %=1 gas temp. to HRSG °F 1,000 gas flow-lb/h=1,000,000 4 vol. CO2=3, H2O=7, N2=75, O2=15, ASME eff-%=80.54 tot dutyMM Btu/h=257.

Surf gas temp. in/out °F sh 1,000 930 evap 930 505 eco 505 345

Surf

wat/stm duty pres flow pstm pinch apprch US module in/out °F MMb/h psia lb/h % °F °F Btu/h°F no. 490 700 19.12 615 129,907 100 52,299 1 480 490 114.36 622 154,907 100 15 10 908,790 1 230 480 41.48 632 156,456 701,552 1

sh FIG. 3

evap

wat/stm in/out °F 0 0 491 700 640 587 453 491 333 453 333 366 230 333

duty MMb/h 69.82 35.98 0 149.7 25.42 22.54 23.31

pres psia 0 615 621.6 628.1 638.1 165 700

flow pstm pinch apprch US module lb/h % °F °F Btu/h°F no. 3,253 0 200,210 100 62118 1 6,190 0 194,020 100 68 37 598,632 1 195,960 216,574 1 25,278 100 9 33 600,344 2 221,491 481,933 3

stack gas flow=1,003,253 % CO2=3.55 H20=8.09 N2=74.57 O2=13.77. Fuel gas: vol% methane=97 ethane=3 LHV-Btu/cuft=934 LHV-Btu=21460 aug air-lb/h=0

eco

Unfired single pressure case—25,000 lb/h LP steam.

HRSG performance: Off-design case Project-study units-British case-case1d remarks- amb temp.-°F=70 heat loss- %=1 gas temp. to HRSG °F 1,000 gas flow-lb/h=1,000,000 % vol. CO2=3, H2O=7, N2=75, O2=15, ASME eff-%=78.22 tot dutyMM Btu/h=257. Surf gas temp. in/out °F burn 1,000 1,263 sh 1,263 1,138 desh 1,214 1,214 evap 1,138 512 eco 512 314

wat/stm in/out °F 0 0 491 700 638 589 449 491 230 449

duty MMb/h 79.12 35.55 0 170.29 51.14

pres psia 0 615 622.5 629.9 639.9

flow pstm pinch apprch US module lb/h % °F °F Btu/h°F no. 3,687 0 200,456 100 58,637 1 5,728 0 219,727 100 20 41 939,130 1 221,924 700,462 1

stack gas flow=1,003,687 % CO2=3.63 H20=8.23 N2=74.51 O2=13.61. Fuel gas: vol% methane=97 ethane=3 LHV-Btu/cuft=934 LHV-Btu=21460 aug air-lb/h=0

FIG. 4

burn sh desh evap eco evap eco

gas temp. in/out °F 1,000 1,237 1,237 1,110 1,187 1,187 1,110 559 559 462 462 375 375 284

Single pressure HRSG fired case—200,000 lb/h HP steam and 25,000 lb/h process steam.

sh FIG. 6

evap

eco

evap

eco

Multiple pressure-fired HRSG case-25,000 lb/h process.

HRSG performance: Off-design case Project-study units-British case-case4d remarks- amb temp.-°F=70 heat loss- %=1 gas temp. to HRSG °F 1,000 gas flow-lb/h=1,000,000 % vol. CO2=3, H2O=7, N2=75, O2=15, ASME eff-%=69.93 tot dutyMM Btu/h=173.1. Surf gas temp. in/out °F sh 1,000 926 evap 926 505 eco 505 347

wat/stm in/out °F 490 700 480 490 230 480

duty MMb/h 20.17 115.24 40.71

pres psia 615 622 632

flow pstm pinch apprch US module lb/h % °F °F Btu/h°F no. 137,040 100 55468 1 152,040 100 15 10 898,666 1 153,560 681,768 1

HRSG performance-design case Project-study units-British case2d remarks- amb temp.-°F=70 heat loss- %=1 gas temp. to HRSG °F 1,000 gas flow-lb/h=1,000,000 % vol. CO2=3, H2O=7, N2=75, O2=15, ASME eff-%=75.34 tot dutyMM Btu/h=186.5. Surf gas temp. in/out °F sh 1,000 925 evap 925 540 eco 540 468 evap 468 376 eco 376 295

sh FIG. 5

wat/stm in/out °F 490 700 475 490 350 475 350 366 230 350

evap

duty MMb/h 20.37 102.95 19.07 23.67 20.53

pres psia 615 622 632 165 700

flow pstm pinch apprch US module lb/h % °F °F Btu/h°F no. 138,366 100 56,054 1 138,366 100 50 15 578,395 1 139,749 215,049 1 27,022 100 10 16 598,320 2 16,742 481,035 3

eco

evap

eco

Multiple pressure HRSG unfired case—-25,000 lb/h process steam.

gle-pressure HRSG unit or a complex, multiple-pressure HRSG, which is more expensive. At first sight, a multiple-pressure HRSG unit would be suggested by any consultant. However, the purpose here is to show that it sometimes may not be economical to use a multiple-pressure HRSG when a single-pressure HRSG can perform well in this situation. 48

I MAY 2009 HYDROCARBON PROCESSING

sh FIG. 7

evap

eco

Single pressure HRSG-unfired case—15,000 lb/h process.

Options. In this example, the design options include:

Single-pressure HRSG. As shown in Fig. 1, a single-pressure HRSG unit should be considered. The steam required for process or LP steam may be taken off the steam drum and the pressure reduced. This may appear inefficient; however, depending on the plant parameters and the ratio of HP to LP steam pressures and flows, this may be a good and an inexpensive option. Multiple-pressure HRSG. Another possible solution is to use a multiple-pressure HRSG, as shown in Fig. 2, with the HP stage followed by the LP evaporator and a common economizer, which feeds the two modules. This is a more complex HRSG and it is more expensive. But this HRSG offers a higher efficiency and lower fuel consumption. In some cases, the multiple-pressure HRSG option may be the only choice. However, it is possible that the single-pressure HRSG is equally effective as the more complex multiple-pressure HRSG and is less expensive. Steam parameters and the ratio between HP and LP steam flows and pressures determine which design is the better

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HEAT TRANSFER HRSG performance: Off-design case Project-study units-British case-case4d remarks- amb temp.-°F=70 heat loss- %=1 gas temp. to HRSG °F 1,000 gas flow-lb/h=1,000,000 % vol. CO2=3, H2O=7, N2=75, O2=15, ASME eff-%=777.27 tot dutyMM Btu/h=246.4.

HRSG performance-design case Project-study1 units-British case3d remarks- amb temp.-°F=70 heat loss- %=1 gas temp. to HRSG °F 1,000 gas flow-lb/h=1,000,000 % vol. CO2=3, H2O=7, N2=75, O2=15, ASME eff-%=71.22 tot dutyMM Btu/h=176.3.

Surf gas temp. in/out °F burn 1,000 1,232 sh 1,232 1,106 desh 1,182 1,182 evap 1,106 511 eco 511 319

Surf gas temp. in/out °F sh 1,000 925 evap 925 540 eco 540 468 evap 468 411 eco 411 335

wat/stm in/out °F 0 0 491 700 637 589 453 491 230 453

duty MMb/h 69.69 35.4 0 161.38 49.62

pres psia 0 615 621.7 628.4 638.4

flow pstm pinch apprch US module lb/h % °F °F Btu/h°F no. 3,247 0 199,986 100 61509 1 5,576 0 209,409 100 20 37 928109 1 211,503 682311 1

wat/stm in/out °F 490 700 475 490 350 475 350 366 230 350

duty pres flow pstm pinch apprch US module MMb/h psia lb/h % °F °F Btu/h°F no. 20.37 615 138,366 100 56,054 1 102.95 622 138,366 100 50 15 578,395 1 19.07 632 139,749 215,049 1 14.67 165 16,786 100 45 16 211,245 2 19.26 700 156,703 236,999 3

stack gas flow=1,003,247 % CO2=3.55 H20=8.09 N2=13.77. Fuel gas: vol% methane=97 ethane=3 LHV-Btu/cuft=934 LHV-Btu=21,460 aug air-lb/h=0

sh FIG. 9 sh FIG. 8

evap

evap

eco

evap

eco

Multiple-pressure HRSG unfired case—15,000 lb/h process.

eco

Single-pressure HRSG-fired case—15,000 lb/h process.

choice. The plant engineer must understand the needs of the facility to make the best decisions regarding the HRSG configuration. Evaluating HRSGs. Using an HRSG simulation program, the

single-pressure HRSG was designed with a pinch and an approach point of 15°F and 10°F and the 25,000 lb/h steam was taken off

HRSG performance: Off-design case Project-study1 units-British case-case3P remarks- amb temp.-°F=70 heat loss- %=1 gas temp. to HRSG °F 1,000 gas flow-lb/h=1,000,000 % vol. CO2=3, H2O=7, N2=75, O2=15, ASME eff-%=80.54 tot dutyMM Btu/h=246.5. Surf gas temp. in/out °F burn 1,000 1,238 sh 1,238 1,110 desh 1,187 1,187 evap 1,110 559 eco 559 459 evap 459 407 eco 407 326

wat/stm in/out °F 0 491 700 641 587 451 491 327 451 327 366 230 327

duty MMb/h 69.99 36.06 0 149.93 26.07 13.52 20.96

pres psia 0 615 621.5 627.9 637.9 165 700

flow pstm pinch apprch US module lb/h % °F °F Btu/h°F no. 3,261 0 200,183 100 62,218 1 6,278 0 193,905 100 67 39 600,711 1 195,844 217,989 1 15,061 100 41 38 211,364 2 211,055 238,405 3

stack gas flow=1,003,261 % CO2=3.55 H20=8.09 N2=74.57 O2=13.77. Fuel gas: vol% methane=97 ethane=3 LHV-Btu/cuft=934 LHV-Btu=21,460 aug air-lb/h=0

sh FIG. 10

evap

eco

evap

eco

Multiple-pressure HRSG fired case—15,000 lb/h process.

from the drum. In the off-design fired case, the program computes the fuel input and firing temperature once the steam demand is set at 200,000 lb/h. The simulation results are shown in Figs. 3 and 4 for both unfired and fired cases. Figs. 5 and 6 show the design and performance with a multiple-pressure HRSG. To study the need for complex HRSG configurations, the process steam demand was reduced to 15,000 lb/h from 25,000 lb/h. The HRSG design and performance for a single-pressure unit is shown in Figs. 7 and 8. Figs. 9 and 10 show the simulation results for a multiple-pressure HRSG. Analysis. Table 1 summarizes the design and performance for all three operating cases. From the simulation results, when the LP steam demand is 25,000 lb/h, the multiple-pressure option provides a fuel savings of over 9.2 MM Btu/h on a lower heating value basis. Based on fuel cost of $10/MM Btu, the annual savings for this design is: Select 164 at www.HydrocarbonProcessing.com/RS 50

HEAT TRANSFER HRSG installations. Before developing specifications for the HRSG, the consultant should be aware of facility’s operating possibilities and options. Specifying a multiple-pressure unit without performing such analysis can yield high capital investments as well as higher operating costs for the plant. In situations such as when the ratio of HP to LP steam pressure increases, and if the ratio of LP to HP steam flow increases, a multiple-pressure HRSG is a better choice. However, for quantitative evaluation and analysis of results, the simulation program is extremely useful. HP

TABLE 1. Summary of design and off-design performance Single-pressure Unfired Fired

Multiple-pressure Unfired Fired

Single-pressure Unfired Fired

Multiple-pressure Unfired Fired

HP steam, lb/h

130,000 200,000

138,000 200,000

137,000 200,000

138,000

200,000

LP steam, lb/h

25,000

25,000

27,000

25,000

15,000

15,000

16,700

15,000

Firing temp., °F

0

1,263

0

1,237

0

1,232

0

1,238

Burner duty, MM Btu/h

0

79.2

0

70

0

69.7

0

70

Exit gas, °F

345

314

295

284

347

319

335

326

Case

Data: HP steam: 600 psig, 700°F; LP steam at 150 psig sat. Feedwater = 230°F, 1% blowdown. Exhaust gas flow = 1 MM lb/h at 1,000°F. % vol CO2 = 3%, H2O = 7%, N2 = 7%, O2 = 15%. Heat loss = 1%.

9.2!10!8,000 = $736,000, assuming the unit operates in the fired mode at all times. However, if the unit operates in the fired mode only part of the time, then it is possible that the singlepressure option with its lower capital cost is more attractive. When process steam demand drops to 15,000 lb/h, then the multiple-pressure option is not attractive. The single-pressure unit is as efficient as the multiple-pressure unit. A slight increase in LP steam is seen in the unfired mode. However, if we compare the complexity of the design and costs, the single-pressure unit can come out as the better choice. Optimize design and performance of HRSG. Design engineers should consider applying simulation models when choosing between multiple-pressure design or single-pressure

LITERATURE CITED Ganapathy, V., “Simplify heat recovery steam generator evaluation,” March 1990, Hydrocarbon Processing, pp. 77–82. 1

Viswanathan Ganapathy is a consultant on boilers and heat recovery and is based in Chennai, India. He has over 35 years of experience in the engineering of steam generators and wasteheat boilers, with emphasis on thermal design, performance and heat transfer aspects. He has also developed software on boiler design and performance. He holds a BS degree in mechanical engineering from I.I.T.Madras and a MS degree in engineering from Madras University. Mr. Ganapathy has published over 250 articles on steam generators and thermal design and has also authored five books on boilers, the latest entitled, Industrial Boilers and HRSGs, published by Taylor and Francis. He also conducts courses on boilers. Mr. Ganapathy has contributed several chapters to the Handbook of Engineering Calculations, published by McGraw Hill, and Encyclopedia of Chemical Processing and Design, published by Marcel Dekker.

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SAFETY/LOSS PREVENTION

Facility siting—balancing risk vs. cost Companies should take a second look at identifying and analyzing hazards associated with temporary buildings B. A. WALKER, Brad Adams Walker Architecture, P.C., Denver, Colorado

Previously, safety issues were considered to have little direct added value. The economic benefits of implementing safety are hard to measure. As a result of the British Petroleum (BP) explosions, the petrochemical industry recognized that it must do more to ensure that refinery employees are safe. But safety comes at a price, and the safety costs must be weighed against consequence costs. Facility siting—the process of identifying hazards in a refinery, assessing the potential consequences of those hazards and managing the risks of those hazards—provides refineries with the information they need to better balance risk and cost. REGULATING RISK

Anywhere there are flammable or explosive chemicals, there is a potential for catastrophic release of those chemicals that can kill people. In response to several serious explosions occurring in US refineries in 1989 and 1990, the federal Occupational Safety and Health Administration (OSHA) began regulating the use of these chemicals. In 1992, OSHA published 29 CFR 1910.119, the standard “Process Safety Management of Highly Hazardous Chemicals” (PSM) or more commonly referred to as the PSM standard. The requirements were designed to reduce injuries and fatalities to building occupants near explosion sites. Safety standards. The PSM standard requires companies to analyze the hazards associated with each aspect of their processing facilities. The standard does not, however, impose a specific methodology for doing this, nor does it define an unacceptable risk level. Therefore, a refinery was not required to take specific steps to mitigate identified risks. To help refineries identify the siting issues for process plant buildings, understand the associated hazards and manage these risks, the American Petroleum Institute (API) published a recommended practice in 2003 known as API RP 752, “Management of Hazards Associated with Location of Process Plant Buildings.” It was the guiding document prior to the Texas City incident. API RP 752 provided a methodology for evaluating hazards associated with process plant buildings and it included risk management decision-making concepts. It helped design engineers and managers to balance risk-reduction benefits with design costs without compromising overall safety. Although it helped identify hazards associated with process plant buildings, it did not specifically address temporary portable buildings and trailers. Buildings. Occupied permanent buildings such as control rooms and operator shelters are located near process areas and typically constructed to be blast resistant. In contrast, conventional portable buildings are light wooden trailers and usually not constructed to

ACCIDENT AT TEXAS CITY, TEXAS

In March 2005, the petrochemical industry was literally rocked by several explosions and a fire that occurred at the BP refinery in Texas City, Texas. During an isomerization process unit startup, flammable hydrocarbon liquid overfilled the blowdown drum and stack. The liquid erupted out of the stack top and into the atmosphere. As the flammable hydrocarbons fell to the ground, a vapor cloud formed and was ignited by a nearby truck. The blast pressure wave and resulting fires killed 15 workers and injured another 180. The fatalities and serious injuries occurred in and around temporary portable buildings and trailers. It is common practice for refineries to use temporary structures as office space for contract workers and support staff. These building types are not designed to withstand a blast, yet are usually located close to refinery processes. At the time of the accident, there were few regulations or best practices governing temporary building placement in a refinery’s hazardous-blast areas. The BP tragedy created a level of public and governmental scrutiny that galvanized the petrochemical industry to increase measures in protecting refinery personnel. The petrochemical industry recognized that, if such a tragic accident could happen to BP, considered a leader in refinery safety, then the potential of it occurring to other refineries may also exist. Until the BP incident, many companies, while not intentionally disregarding safety issues, placed safety behind other competing priorities, such as production. be blast resistant. Occupants of portable buildings are more likely to be injured by structural failures, building collapse and fallout from building debris than occupants in permanent buildings. Even buildings that are not blast resistant have better blast capacity and provide greater protection than trailers. API RP 752 did not prohibit trailer placement in close proximity to hazardous process units. In retrospect, this was a significant and deadly omission. API RP 752 allowed refineries to define their own risk and occupancy criteria for trailers. Prior to the 2005 explosions, BP regarded temporary trailers located close to a process unit as an acceptable risk. BP approved trailer locations at the Texas City facility (US Chemical Safety and Hazard Investigation Board, “Final Investigation Report,” Report No. 2005-04-I-TX, March 2007). Because BP conducted hazard analyses of its processes and buildings while regularly updating them, it met OSHA’s 29 CFR HYDROCARBON PROCESSING MAY 2009

I 53

SAFETY/LOSS PREVENTION 1910.119 requirements for facility siting. Since it identified the hazards to permanent buildings sited in blast areas and defined criteria for managing the risk to employees working in those buildings, it met the facility siting guidelines in API RP 752. The 15 deaths and 180 injuries that occurred in BP’s temporary trailers signaled a clear need for additional guidelines that would manage the risk to employees working in temporary structures. In response, API developed a second recommended practice in June 2007, entitled API RP-753, “Management of Hazards Associated with Location of Process Plant Portable Buildings.” This document specifically addressed temporary facilities, such as portable trailers and it: • Minimizes the use of occupied portable buildings in refinery

process areas • Establishes a portable building’s minimum safe distance from hazardous areas within a refinery • Provides step-by-step procedures for identifying hazards to people in portable buildings • Stipulates that nonessential personnel should not be near hazardous areas. In addition to the API response, on June 7, 2007, OSHA implemented its “National Emphasis Program” whereby it would regularly inspect refineries to determine if they were in compliance with the 1992 PSM standard. MEASURING RISK

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OSHA’s PSM standard requires a refinery to analyze its hazards and determine some measurement of the risk to employees, equipment and buildings. This analysis is referred to as risk assessment. The more detail a refinery is willing to put into a risk assessment, the closer the refinery can place its portable buildings to the processing units, as defined in API RP 753. Conversely, if the refinery chooses to do a simplified analysis, then it must be very conservative in trailer placement. This need for detailed information finally compelled refineries to measure the risk associated with their process areas to understand how to effectively manage the costs involved in minimizing that risk. There are many different approaches to doing a risk assessment, but all share these four general steps: • Identify hazards that may affect process plant buildings (e.g., toxins, fire and explosion) • Establish hazard scenarios and the likelihood of occurrence • Assess the buildings themselves (location, construction and function) • Assess potential consequences. Qualitative risk as s es s m e n t .

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Although the PSM standard describes what must be analyzed, it lacks specific details of how to measure the risk levels. That’s because the standard permits a qualitative analysis. A qualitative analysis evaluates the likelihood of an occurrence and the potential consequences by using descriptive measurements, such as “high,” “medium” or “low,” versus numeric measurements. If the analysis determines a low risk, then the company doesn’t need to do anything more; if there is medium risk, it may decide to study it further; if there is high risk, then changes need to be made immediately. This analysis type is very subjective and may not adequately identify unacceptable risk. Quantitative risk assessment. Refiners recognize that they need to measure risk

SAFETY/LOSS PREVENTION using more objective methodologies and they may prefer to use a quantitative risk assessment (QRA). A quantitative approach seeks to assign a numerical measurement to risk rather than the descriptive measurement used in a qualitative analysis. There are several different approaches to a QRA and often an analyst uses a combination of approaches in the risk assessment. The most common practice is to use a deterministic approach where one assumes that an explosion will occur and then evaluates the possible consequences numerically. This approach is commonly referred to as a consequence-based approach. For example, a refinery may analyze a processing unit by assuming that a 2-in. hole will open somewhere in the process and that flammable dispersion will occur. The analysis assumes that the resulting vapor cloud is ignited, causing a vapor cloud explosion. Flammable dispersion prediction will occur all over the plant for various line breaks, predict specific blast loads and analyze the building’s response using vulnerability functions such as pressure-impulse diagrams. These measurable predictions will indicate the degree to which the refinery must mitigate the risks to refinery personnel. Deterministic approach. Eliminates the need to explicitly define the probability of an occurrence. However, an analyst may still make decisions about the probability or frequency of an occurrence based on which scenarios the analyst selects for analysis. For example, the release of a process vessel’s entire contents or a break in a 6-in.-diameter line may be considered so unlikely as to be incredible (probability approaching 0) and thus would not be considered. In this way, the analyst is implicitly including probability of occurrence. Traditional approach. This approach to a QRA is a probabilistic risk assessment. Whereas the deterministic approach assumed an explosion will occur (probability = 1), a QRA actually computes the probability that an explosion will occur and provides a numerical estimate of the risk exposure. Risk, in this case, is the probability of a fatality or severe injury and may be computed for an individual or for a larger population. When evaluating the risk caused by a process or risk for an entire building, risk may be expressed in terms of the number of expected fatalities per year (aggregate risk). Here is a simple sequence included in a QRA analysis of a potential vapor cloud explosion: • Define scenarios in which flammable material leaks may occur • Assign a probability of occurrence to each leak scenario • Perform dispersion modeling of each leak scenario • Compute flammable mass • Perform blast calculations to determine loads on occupied buildings for each scenario using Baker–Strehlow–Tang (BST), TNO or computational fluid dynamics (CFD) • Analyze potential structural damage that might occur during an explosion • Determine potential fatalities or seri-

ous injuries that might occur • Compute individual and aggregate risk for each process or each building • Compare the result with risk acceptance criteria. If computed risk is greater than what was determined to be acceptable risk (risk tolerance criteria), then a company must decide how to mitigate the risk. Without tolerance criteria, a company cannot make rational risk decisions. The deterministic and probabilistic methodologies differ in the amount of detail required to perform the analysis and, thus in the level of conservativeness that a refinery must employ when using the analysis results. Deterministic methods are most commonly used because of the difficulty in determining probability of occurrence and the lack of risk tolerance criteria. Of the two risk approaches, only QRA develops a risk value that can be compared to tolerance criteria to determine if the risk is acceptable. Although QRA is more costly and time consuming to perform, the results offer a rational approach for determining if hazards are acceptable and if they are not, how much mitigation is required. Therefore, a refinery may find the QRA a better tool for determining cost-effective methods to reduce risk. BALANCING RISK VIA FACILITY SITING

To comply with OSHA’s PSM standard, a refinery’s primary challenge is to answer this question, “For the existing building that I have, do I have a problem?” The risk assessment will identify the hazards associated with a specific process or building and provide some measure of the inherent risk. A company must then evaluate various alternatives that will reduce the risk while balancing the cost of each alternative. In many situations, chang-

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SAFETY/LOSS PREVENTION ing the process itself may be the least costly alternative: For instance, a refinery could follow these guidelines: • Reduce the quantity of material available, thus reducing the potential blast load • Release a water spray if an explosion occurs, to reduce explosive output • Improve its maintenance program by inspecting the lines more frequently or conducting nondestructive testing • Improve training.

When these types of process changes are impractical or simply will not reduce risk to an acceptable level, a company may need to weigh the capital costs involved with changing the building that houses the process or moving its personnel away from the process altogether. Prior to the Texas City explosion and the 2007 publication of API RP 753, many companies, particularly the second- and third-tier refineries and chemical plants, simply put such projects on hold due to the costs involved. Whether

the BP explosion is seen as an it-could-happen-to-me event, or whether companies are reacting to OSHA’s new National Emphasis Program and ensuing inspections, companies are taking a much more proactive stance in terms of bettering their facilities and evaluating the merits of facility siting as a way to reduce risk to personnel. Mitigating explosion hazard risks can involve one or more of the following approaches: • Retrofitting an existing building in a blast area to make it blast-resistant • Building a new building in or near a blast area, using an appropriate level of blast design • Moving people to a different building out of the blast area entirely. Retrofitting. If the blast magnitude load

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exceeds what a building can handle, one relatively inexpensive approach is a simplified retrofit, such as wall strengthening. If the blast load is sufficiently high, then it may be necessary to build a blast-resistant shell around the entire building. This approach can reduce new construction and equipment costs while providing a safer environment for personnel. While retrofitting can often be done without shutting the facility down and disrupting the process, both events impact profitability. To understand the full impact of retrofitting an existing operation and the associated construction and equipment costs, many companies involve an architect who understands the complexity of moving and housing people and who may take a non-linear, non-engineering approach to building design. There has been an increase in retrofitting activity in the last year. In the past, the trend had been toward building new control rooms. A new control room is a big project and a long-range capital improvement plan. Since API RP 753 inception, companies recognize that they have to do something sooner rather than later. They will need to seek more short-term solutions, such as retrofitting an existing building to enable them to quickly move people out of trailers and into a safer work environment. Is retrofitting practical? Sometimes an analysis will indicate that retrofitting an existing building isn’t practical or isn’t a sufficient solution to reducing risk to personnel. Interruptions to operations can be another serious obstacle. The refining industry generally runs at full capacity. If retrofitting a building interrupts a refinery’s operations, the downtime can significantly affect profitability.

SAFETY/LOSS PREVENTION New construction. In such cases,

building an entirely new building may be the best alternative. A new building may enable a company to combine several functional areas in one building, making it a multi-purpose facility. A new building may be sited outside a blast zone, thus eliminating risk to personnel altogether. Centralized control rooms offer additional advantages, such as increased communication between process areas and, as a result of consolidating space and equipment, an opportunity to reduce costs by employing fewer operators. However, a new building probably will require new real estate. Adjacent land may not be available, may be too near or too far away from the primary processing area, and will certainly be very expensive. If a process has relatively modern control equipment, it may be fairly easy to move it, but if it uses older systems, it may cost more to purchase new control equipment than it would to build the new control room itself. Nevertheless, API RP 753 created an imperative need for companies to move all nonessential personnel away from blast zones as soon as possible. Building a new facility may be a sensible long-term solution, but realistically it will take at least two years to implement and may not provide the short-term risk reduction that is required. The capital expenses involved with constructing a new building and the length of time it takes, often make new construction an unaffordable option. Relocation. Since the publication of API RP 753, there is a substantial increase in the number of companies who choose to move their personnel out of temporary trailers altogether and into leased, off-site facilities. Their attitude is to get their employees into safe housing quickly and at any cost and then to take whatever time is necessary to figure out a longer-term strategy. One major US oil company responded to the new API RP 753 by committing its domestic refineries to full compliance by June 30, 2008. Based on the results of an exhaustive QRA, one of its facilities relocated 600 employees—half to a leased office building offsite and the other half to permanent structures inside the refinery or to other temporary structures outside the blast zone. Not all 600 people were nonessential temporary support personnel working in trailers. Management executives understood that moving these contractors would impact other support personnel working in field offices, control rooms, administration buildings and tech centers onsite. They fac-

tored the needs of this mixture of essential and nonessential personnel into the move. The company leased a five-story commercial office building nearby the refinery to house process and design engineers, senior management, maintenance planning resources and capital projects personnel. Their operations infrastructure, field maintenance employees, supervisors and construction resources remained on site. The company gutted the leased office building and rebuilt it into a professional new office environment with many amenities that weren’t previously available to employees. In addition to safely housing these relocated employees, the company reorganized its console operators, short-range planners, control engineers and master process engineers into more productive work groups. It housed cooperative groups of people on separate floors—one for capital projects and their accounting resources, one for maintenance planning resources, one for training and conference facilities, and one for futurefocused projects. Maintenance and operations personnel feel more valued as a result of being chosen to move to the new facility, providing an unexpected boost in moral.

Productivity increased because they were happy to be in a more professional and comfortable work environment than they were accustomed to. The company sees elevating this standard in the professional work environment as a long-term benefit to its recruitment of top-quality employees. Large-scale relocation. When this type of effort is made, there will be considerable disruption to employees’ workflow and a refinery must address change management and communications early in the planning stages. Many employees believe their type of work cannot be moved offsite. For instance, maintenance planning personnel who plan major plant turnarounds believe they absolutely cannot move offsite and still perform their duties. However, that may not be the actual case, and a company must balance its sensitivity to employee preferences with the reality that change is required and then manage the transition effectively. In addition to handling the facilities perspective of getting people moved, a company may need to change its meeting structures and communication vehicles to make sure that people are able to attend meetings and communicate via audio and video technologies. It may need

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SAFETY/LOSS PREVENTION to create a Web site, schedule the delivery of informative phone messages or provide “town hall” meetings to help educate employees and elicit their cooperation. These efforts will increase the costs involved with a relocation effort, but attending to the cultural needs of a workforce is critical to the project’s success. Type of costs. When balancing the relative costs of short-term lease arrangements with a long-term investment in a new onsite building, a company will likely base its decision on capital availability. Most refineries will lose money this year. Tight profitability margins will make it difficult to justify the costs that would be incurred in any capital project designed to mitigate risk to personnel. Although oil exploration and drilling projects are very active in response to the global demand for new resources of crude oil, the high cost for that raw crude oil makes it difficult for refineries to recoup their expenses in their downstream sale of refined product. In this age-old balancing act between capital investment and operating expense, a company must decide if it makes more sound financial sense to continue to lease office space long-term or to put its capital funding into pay-off projects and compliance-driven projects. It may be more

profitable long-term to extend an offsite facility lease for another 15 to 20 years and to channel capital funding to more immediate needs, such as plant automation and technology improvements in the refinery. For example, a new 400-seat administration building constructed onsite that would have an average 30-year life span would cost about $50 million. That same $50 million might yield only 12 to 15 years of lease payments for an equivalent building offsite. It might seem more sensible to invest in a new building that would last longer (but have no immediate payout). However, it may be wiser to spend that money debottlenecking a crude unit or building another cogeneration train that might pay for itself in three years. These latter types of capital constructions will create a long-term net income that may actually pay for the yearly lease expenses. Measuring ROI. When and how will a

company know if their efforts to mitigate the risk to their employees were successful? It is easy to answer if “success” is defined by simply moving people out of harm’s way in compliance with the new API standard. It is much harder to assign a value to the cultural, personnel productivity, and busi-

ness impact issues. From a learning development context, one method to measure the return on investment (ROI) of these relatively intangible factors is to approach the question in sequential levels. • Level 1 asks if people liked the change and how they feel about the change. That kind of emotional, experiential response will let management know if people are happy and satisfied with the solution that management chose. • Level 2 asks if employees “got it.” Is there evidence that the business or personal impact that a company was trying to elicit from its employees was achieved? For instance, in a relocation effort, the only thing an employee might be expected to “get” is an understanding of why he/she was moved. Measuring this kind of understanding may be difficult. • Level 3 measures the actual organizational impact—did the organization itself “get it”? Are there more meaningful contact points between engineers and operations supervision? Are there fewer unplanned shutdowns or process upsets? One can measure plant health performance and the human impact on those things over time, once the new operating posture has settled.

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SAFETY/LOSS PREVENTION • Level 4 measures the money that was spent and can identify whether there is a measurable ROI. To do this, management must develop a method for determining direct and indirect impacts of an event. Perhaps it can identify what the productivity increases are, or the savings that result from fewer unplanned shutdowns. Unfortunately, in practice, companies very rarely invest the time and resources necessary to identify the actual ROI of its risk mitigation efforts. Safe environment. In most companies, high-level management is strongly committed to providing a safe working environment for their employees. Sometimes, however, that commitment appears only on paper. They may dutifully report their safety issues to OSHA, but shelve efforts to mediate the hazards identified in the reports because of budgetary concerns. When OSHA announced its implementation of the National Emphasis Program in directive number CPL 03-00-004 on June 7, 2007, it stated that “OSHA has typically found that these employers have extensive written documentation related to process safety management, but the implementation of the written documentation has been inadequate.” There is considerable disconnect regard-

ing risk and cost between upper- and midlevel management at many companies. Production managers and supervisors at the working level are often pressured to turn out product without being given sufficient funding or support for safety. This was the case at BP where supervisors were expected to work safely, do whatever was necessary to implement safety projects, and not let production levels drop. OSHA itself has been part of the problem. By not enforcing its 1992 regulations with regular inspections, OSHA relied almost exclusively on a refinery’s self-reports and risk assessment updates. In its March 2007 final investigation report, the Chemical Safety and Hazard Investigation Board concluded that the BP explosion was caused by OSHA’s failure to frequently inspect plants and by BP’s cost-cutting efforts and its organizational and safety deficiencies. There is an old saying that if you think safety is expensive, try an accident. Over 4,000 lawsuits have been filed seeking damages from the BP refinery explosion, and more than $2 billion is expected to be paid out in settlements (“Lawmakers Look at Injured Worker Ruling,” Associated Press, ABC Network Affiliate KVIA-TV, April 28, 2008).

Safety first. Numbers like that will most certainly motivate refinery owners to step-up efforts to ensure that their employees have a safe work environment. In addition, pending and existing governmental regulations provide additional incentives—OSHA fined BP $21 million for safety and health violations following the explosion investigation. Facility siting assesses process buildings in terms of location, construction and function based on the consequences to personnel in the event of a fire or an explosion. It can provide refineries with detailed information necessary to balance the costs of safety with the costs of the consequences. Over the long run, companies recognize that a safer operation has less downtime, less interruptions and less litigation. Those factors must weigh heavily in the balance of risk and cost. HP B. A. Walker co-founded Brad Adams Walker Architecture, P.C., (BAW) in 1992, located in Denver, Colorado. He is a licensed architect and has been working in the industry for 25 years. BAW has a concentrated expertise in the design of command and control centers, including ancillary facilities. Mr. Walker holds a BA degree from Colorado State University and an MA degree in architecture from the University of Colorado at Denver.

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K T I C O R P : F I R E D H E AT E R S & S C R S Y S T E M S

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PETROCHEMICAL DEVELOPMENTS

Consider new feedstocks for dimethyl ether production This methanol-based petrochemical has growing options within energy markets S. K. ANSARI, International Chemplast (Pvt.) Ltd., Karachi, Pakistan; and S. ANSARI, Karachi Institute of Economics and Technology, Karachi, Pakistan

T

oday, two main crisis capture the attention of the global economies. They are 1) petroleum supply/demand imbalances, and 2) the environment. Alternative fuels, other than refinery products, are becoming essentials as global governments seek energy independence and energy security. High crude oil prices ($100+/bbl) has strengthen this position held by many nations. New energy developments promoting “clean” energy, mitigating pollution emissions and protecting the environment have become urgent. China is dependent on foreign oil. Yet, this nation has vast coal reserves—the largest in the world. More importantly, China is developing coal-based alcohol, fuels, liquids, etc. The direct and indirect substitution of alternative feedstocks is an important strategic development direction. Coal-based fuel alcohol ethers (referring to methanol, dimethyl ether, etc.) are being fast-tracked by the Chinese government as part of its alternative energy source programs. The long- and medium-term energy demand in the Asian region is increasing. In fact, the growing energy demand/supply and potential environmental problems will create substantial obstacles when achieving sustainable development in this region. Reserves of oil and natural gas (NG) resources in China are only 5%, and there are very few large-scale NG fields that are adequate to support liquefied natural gas (LNG) installations. This region (China) is richly endowed with coal reserves—31% of the world’s coal reserves. However, most of China’s coal reserves are considered low-value coal such as sub-bituminous coal or lignite. These coal grades have high moisture content and have a tendency to spontaneously ignite during drying. Such qualities curb their demand and usage.

Future ‘clean’ fuel. Dimethyl ether (DME) is an innovative

clean fuel; its properties are similar to liquefied petroleum gas (LPG). At present, DME is primarily used as an alternative fuel for power production in home heating, a replacement for LPG as a transportation fuel and as a diesel-fuel substitute or combustion supplement. Basically, DME can be produced through both direct and indirect methanol (MeOH) dehydration routes. In the indirect route, conventional MeOH production technology is used. Next, the MeOH is dehydrated in a separate reactor where DME is synthesized and then purified in a distillation column. In the

direct DME synthesis route, which is under commercialization proceedings, synthesis gas is directly converted into DME via one step. DME would be an innovative clean fuel. From the global perspective, the increasing share of NG in the energy market is one good reason for DME to be considered as an alternative fuel. Fuels for the future. Tighter environmental regulations,

especially in Europe and Japan, have provided a good platform to promote new “clean” fuels. Supply limitation coupled with increasing LPG demand is another reason for DME to be considered as a substitute for LPG, especially in Southeast Asian countries, including India and China. For Iran, production, domestic utilization and export of DME is another way of monetizing NG along with other options including gas-to-liquids (GTL) and LNG. The physical properties of DME are very similar to LPG. Its molecular structure, physical properties and fuel performance, as well as its ability to be converted into other chemicals such as olefins, has created a unique position for this petrochemical. Conversely, DME is nontoxic with a short half-life in the troposphere and has very low reactivity. After combustion, DME does not produce soot and has low emissions of NOx , hydrocarbons and carbon monoxide (CO). Natural gas. World NG reserves are larger than the oil reserves, and are currently estimated at 368x1012 m3, or 3,390x1012 kWh. These proven reserves amount to 1,380x1012 kWh. In 1995, 39%

TABLE 1. World methanol demand in million tpy World methanol demand by usage Petrochemicals, MMtpy

2003 2004 2005 2006 2007 2008

2009 2010

Formaldehyde

12

14

14

14.5

16

17

17

17

MTBE

7

6

6

6

5

4.5

4.5

4.5

Acetic acid

3

3.5

4

4

5

5.5

5.5

5.5

MMA/DMT

2

2

2

2

2

2

2

2

Fuels

1

1.5

2

2.5

3

3.5

3.5

4

Other

6

7

7

7

7

7

7

7

Total

35

34

35

36

38

39

39.5

40

HYDROCARBON PROCESSING MAY 2009

I 61

PETROCHEMICAL DEVELOPMENTS 450

Global methanol demand

20

400

MeOH contract prices, US$/ton (US) MeOH contract prices, US$/ton (EU)

350 MeOH demand, MMtpy

300 15

250 200 150 100

10

1991 1993 1995 1997 1999 2001 2003 2005 2007 Year 5

FIG. 2

0 2003

2004

2005

2006 2007 Year

Formaldehyde MTBE Acetic Acid FIG. 1

2008

2009

2010

MMA/DMT Fuels Other

Global MeOH demand by petrochemical product.

of the NG reserves were located in the former Soviet Union (CIS), 14% in Iran, 5% in Qatar, 4% in Abu Dhabi and Saudi Arabia, and 3% in the US. The remaining 31% is distributed among all NG producing countries.

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Contract prices for MeOH shipments in US and Europe, 1991–2008.

TABLE 2. Methanol prices from 1990–2008 for US and European markets Year

MeOH contract prices, $/ton (US)

MeOH contract prices, US$/ton (EU)

1990

125

125

1991

175

175

1992

150

125

1993

150

125

1994

280

280

1995

200

269

1996

150

150

1997

200

200

1998

125

135

1999

115

115

2000

180

175

2001

200

190

2002

175

175

2003

240

260

2004

260

260

2005

300

275

2006

400

375

2007

400

400

2008

170

170

Based on the NG output for 1995 (25.2x1012 kWh), the proven worldwide reserves should last for almost 55 years. In 1995, North America and Eastern Europe are the largest producers and supply 32% and 29%, respectively, of NG globally. NG consumption has steadily increased over the last two decades. Until recent times, NG could only be used where the corresponding industrial infrastructure was available or where the distance to the consumer could be bridged by means of pipelines. NG transportation over greater distances from the supply source to consumption areas is being addressed through LNG. Both features, intercountry pipelines or LNG shipment and unloading, are very expensive. Methanol. MeOH is one of the most important industrial

petrochemicals. Worldwide, about 90% of the MeOH supply is used in the chemical/petrochemical industry, and the remaining 10% is used for energy. Table 1 shows the global MeOH demand. From this table, we can assume that China’s demand for fuels, Select 172 at www.HydrocarbonProcessing.com/RS 62

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

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Please visit www.kticorp.com for a complete list of our products, services, and contacts. Select 97 at www.HydrocarbonProcessing.com/RS

PETROCHEMICAL DEVELOPMENTS including DME, is about 3 million tons (MMton) in 2003, which is consecutively increasing as shown in Fig. 1. It may seem that MeOH capacity exceeds demand. This is true for the present. Using 2007 data, China is probably consuming about another 2 MM mton of MeOH for fuels than anticipated. Assume that MeOH demand will be about 40 MM mton in 2010. Table 2 and Fig. 2 list the methanol prices from 1990–2008. From Table 2 and Fig. 2, MeOH prices show a big variation, which approaches $170/mton.

17 2

1

3

9

CW

Distillation column

DME

12

WT

8 4

T 101

7

Waste treatment

CW

11

T 102

Dimethyl ether. DME is used primar-

ily as a propellant. It is miscible with most organic solvents and has a high solubility in water. Recently, this petrochemical has been used as a fuel additive for diesel engines due to its high volatility (desired for cold starts and high Cetane numbers.

16

CW

CW

T 103

10 Impurities distillation column

6 5

14

Ips Waste treatment

13

15

WT

Methanol distillation column

Production of DME from MeOH.

2CH3OH
CH3OCH3 +H2 O Under normal operations, there are no significant side reactions, and the equilibrium conversion for pure MeOH feed exceeds 92%. Therefore, the reactor is kinetically controlled within the normal operation temperature range. Above 250°C, the rate equation is given by Bondiera and Naccache as: 
Ea  P
rmethanol = k0 exp   RT  methanol Where k0 = 1.21!106 kmol/(m3 reactor h kPa) Ea = 80.48 kJ/mol Pmethanol = partial pressure of methanol, kPa. Note: Significant catalyst deactivation occurs at temperatures over 400°C, and the reactor should be designed so that this temperature is not exceeded anywhere in the reactor. Since the DME reaction is not highly exothermic, proper temperatures can be maintained by preheating the feed to 250°C and running the reactor adiabatically. The process was simulated using the non-random two liquids (NRTL) thermodynamic package for K-values, and Soave, Redlich, Kwong (SRK) values for enthalpy. Note: NRTL models and extensions use the Wilson equation and can be applied to mixtures that can form two immiscible liquid phases. The SRK temperature is in full-range and pressure (P, psia) range of