HP_2011_11

NOVEMBER 2011

HPIMPACT

SPECIALREPORT

BONUSREPORT

EU chemical production grows slowly

PLANT SAFETY AND ENVIRONMENT

PROCESS CONTROL AND INFORMATION SYSTEMS

Safety relief valves, inlet piping and automated decoking

New technologies improve real-time control and monitoring

North America’s shale gas boom

www.HydrocarbonProcessing.com

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NOVEMBER 2011 • VOL. 90 NO. 11 www.HydrocarbonProcessing.com

SPECIAL REPORT: PLANT SAFETY AND ENVIRONMENT

29 31 37 41 47 51 59

The evolution of safety in the oil and gas industry C. Lyons

Mitigate refinery influent water supply contamination Resolving critical water supply and quality issues by managing risk and implementing successful solutions W. Garrison and L. Huchler

Tips on communicating LOPA results to management Communicate clearly and explain thoroughly G. C. Shah

Spent caustic management: Remediation review Proper disposal of spent caustic requires full understanding of waste components G. Veerabhadraiah, N. Mallika and S. Jindal

Cover The Sabine Pass Liquefied Natural Gas (LNG) terminal located in Cameron Parish, Louisiana, is one of the world’s largest facilities for turning LNG back into natural gas.

The facility is capable of regasifying 4 billion cubic feet of natural gas per day. Photo courtesy of Bechtel.

Automated decoking solves coker safety challenges The concept improves safety and efficiency and bolsters the bottom line I. Botros

Pilot-operated safety relief valves: A simple, effective plant upgrade

HPIMPACT

Replacing spring-loaded valves can be an important step in the quest to increase efficiency and output J. R. Scott and N. MacKinnon

13

EU chemical production grows ever so slowly

Relief device inlet piping: Beyond the 3 percent rule

13

World demand for water treatment products approaches $65 billion

14

Shale gas boom helpful to North American chemical producers

16

The quest for a common integration technology

With careful consideration, an engineer can be certain that an installation will not chatter D. Smith, J. Burgess, and C. Powers

NORTH AMERICAN TURNAROUND AND MAINTENANCE 2011—SUPPLEMENT

67

North American Turnaround and Maintenance 2011 ‘Lean thinking’ in maintenance can boost reliability, save time

BONUS REPORT: PROCESS CONTROL AND INFORMATION SYSTEMS

83 89

Improve material balance in high-purity distillation control Using dual-composition conserved energy efficiency, reduced reprocessing and allowed higher throughput S. Nino

Safety instrumented function design reduces nuisance trips Implementing low-cost best practices can provide peace of mind A. Kern

COLUMNS 9

HPIN RELIABILITY One pump fire per 1,000 pump repairs

11

HPINTEGRATION STRATEGIES Aging HPI workforce drives need for operator training systems

90

HPIN WATER MANAGEMENT Don’t let water be the reason for a turnaround

MAINTENANCE/HEAT TRANSFER

95

Investigation: Failure of a steam generator In this case history, engineers search for the root cause of water-side tube failures for a 23-year-old boiler A. Babakr and A. K. Bairamov

ENGINEERING CASE HISTORIES

101

Case 65: Taking risks and making high-level presentations Tips on how to communicate with managers T. Sofronas

DEPARTMENTS 7 HPIN BRIEF • 19 HPIN CONSTRUCTION 26 HPI CONSTRUCTION BOXSCORE UPDATE 102 HPI MARKETPLACE • 105 ADVERTISER INDEX

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HPIN BRIEF BILLY THINNES, TECHNICAL EDITOR

BT@HydrocarbonProcessing.com

Calumet Specialty Products has completed its previously announced acquisition of Murphy Oil’s refinery and associated operating assets and inventories in Superior, Wisconsin, for about $442 million. The Superior assets provide greater scale, geographic diversity and development potential to Calumet’s refining business, as Calumet’s current total refining throughput capacity will increase by 50% to 135,000 bpd, the company said in a statement. The Superior refinery produces gasoline, diesel, asphalt, bunker fuel and specialty petroleum products that are marketed in the Midwest region of the US, including the surrounding border states, and Canada. The refinery’s assets include inventories valued at approximately $220 million as of August 31, 2011, and various owned and leased finished product terminals.

Infrastructure investments for the shale gas industry are growing amid rising global demand for natural gas, with current levels likely to triple by 2020 to reach 12.6Tcf, according to a new report from energy research firm SBI Energy. In the US, shale gas production increased at an annual rate of 48% from 2006 through 2010, reaching 4.8Tcf and representing 23% of the total US natural gas production.

Shale gas processing assets are now regarded as an attractive form of investment, the report says. An increase in gas and natural gas liquid products from these shale plays over recent years has led to billions of dollars worth of investments in gas processing infrastructure. The current market for shale gas processing equipment and components is limited to the North American continent, specifically in the US and Canada. While the US market has grown exponentially over the past five years, production increases are also occurring in Canada, where unconventional gas accounted for 25% of the country’s natural gas production in 2010.

Neste Oil will spend about €60 million in 2012 on process safety improvements for its Porvoo and Naantali refineries in Finland. Investments will focus on further improving process, fire and personnel safety by modernizing process automation and automated safety systems, the company said. The latter are autonomous systems that are capable of automatically taking over control of a process in the event of equipment malfunction, for example, and ensuring that operations remain safe at all times.

Two process furnaces will also be replaced at Naantali, and new, safer office space for personnel will be built at Porvoo and the fire water system improved, according to the company. Neste Oil’s new automation and safety systems will be supplied by Finnishbased Metso, with which Neste Oil has recently signed a new framework contract.

Foster Wheeler Energy Ltd. (FWEL) has won the Five Star Health and Safety Management System Audit Award from the British Safety Council for the performance of FWEL’s UK-headquartered operation in Reading. The award follows a Five Star audit, in which the British Safety Council reviewed the health and safety performance of FWEL’s Reading home office operation. The British Safety Council Audit, encompassing the management of health and safety through to the implementation of associated systems in the workplace, results in an overall numerical score, or star rating, of the organization’s performance. Organizations are rated from one to five, with five being the top rating. FWEL’s Reading operation achieved a five-star rating, with an audit score of 93%.

A team of maintenance contractors at the ConocoPhilips Humber refinery in South Killingholme, UK, has achieved a period of five years (785,550 man hours) without an incident which led to a recordable injury. The team works for multidisciplinary maintenance services company Hertel, which carries out a broad range of tasks across the Humber site including specialist painting, insulation, access services and scaffolding. Hertel has been working on the Humber refinery site for eight years and this is the seventh time in that period that a 12-month injury free period has been recorded. HP

■ Biojet fuel grant Renewable chemicals and advanced biofuels firm Gevo has received a $5 million grant from the US Department of Agriculture (USDA) for the development of biojet fuel from woody biomass and forest product residues. The award is a portion of a $40 million grant presented to the Northwest Advanced Renewables Alliance (NARA), a consortium led by Washington State University (WSU).

“This is an opportunity to create thousands of new jobs and drive economic development in rural communities across America by building the framework for a competitively-priced, American-made biofuels industry,” said US Agriculture Secretary Tom Vilsack.

NARA includes a broad consortium of scientists from universities, government laboratories and private industry. The WSU-led grant aims to address the urgent national need for a domestic biofuel alternative for US commercial and military air fleets.

The NARA project envisions developing a new, viable, aviation fuel industry using wood and wood waste in the Pacific Northwest, where forests cover almost half of the region. The project will also focus on increasing the profitability of wood-based fuels through development of high-value, biobased co-products to replace petrochemicals that are used in products such as plastics.

Gevo believes that woody biomass can be used as a cellulosic feedstock to create petroleum replacements such as isobutanol. This project is a critical next step in proving its effectiveness.

Gevo intends to use its portion of the award to optimize its cellulosic yeast and fermentation process.

“The airline industry and the United States Department of Defense are eagerly looking for near-term alternatives to petroleum-based jet fuel,” said Patrick Gruber, CEO of Gevo.

Gevo previously announced its progress to airline engine testing using starch derived isobutanol to jet fuel. Gevo expects to receive full fuel certification by 2013 from the American Society for Testing and Materials (ASTM) for its biojet fuel. HP

HYDROCARBON PROCESSING NOVEMBER 2011

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

One pump fire per 1,000 pump repairs While performing reliability audits decades ago, pump-failure statistics were made available or could be recovered with relative ease. But even then, the sources were usually kept confidential because fire incidents are stressful, to say the least (Fig. 1). In 1974, it was known that, for every 1,000 pump repairs, there was a pump-related fire incident. More recently and in a facility with approximately 2,000 installed pumps, the acknowledged meantime between repairs (MTBR) was six years. This would allow us to calculate that approximately 333 pumps underwent repair each year. Since that particular plant experienced five pump-related near-disasters over a 14-year period, doing the simple math tells us that its rate of major pump issues tracked the “1 fire per 1,000 repairs” within 6% accuracy.

Failure statistics tell the story. An airplane has about

4 million parts; an automobile has approximately 10,000 parts and a centrifugal process pump has about 200 parts. It’s fair to say that if a machine is made up of a large number of parts, more parts could malfunction. However, this does not mean that more parts will, in fact, malfunction during an operational cycle. So, what’s the point of this reminder?

As we think about the reasons why the average process pump requires a repair after approximately six years, we realize that not all of its components are designed, fabricated, assembled, maintained, operated or perhaps installed with the same diligence as aircraft components.

It doesn’t have to be that way. Alloys can be upgraded, and better components are sold to owner-purchasers who insist on such upgrades. Advanced computer-based and reasonably priced design tools are available for the pump hydraulic assembly. It has been shown that computational fluid dynamics (CFD) can be used to define the improvement potential of impellers and stationary passages within pumps; Fig. 2 certainly attests to that.

But the mechanical assembly (drive end) of some pumps also deserves attention, especially since this portion of the pump has been neglected in some brands or models. Fortunately, expert advice is available for the specification and selection of better drive-end geometries for process pumps.1 Thoughtful specification and selection used to be par for the course at best-of-class companies, and there is really no reason why that thinking should have undergone change. What we see lacking today is an awareness of the precise steps that are needed for such specifying and selecting. Management has fallen prey to consultant-conceived generalities, including “lean and mean” and other similar, catchy utterances. HP 1

LITERATURE CITED Bloch, H. P., Pump Wisdom—Problem Solving for Operators and Specialists, John Wiley & Sons, 2011.

FIG. 1

Assets and human lives are at stake when there are pump fires in refineries.

FIG. 2

Relative velocity plot of an optimized vertical pump stage (Source: Pump Design, Development & Diagnostics; gregcase@pdcubed.net).

The author is Hydrocarbon Processing’s Reliability/Equipment Editor. A practicing consulting engineer with almost 50 years of applicable experience, he advises process plants worldwide on failure analysis, reliability improvement and maintenance cost avoidance topics. He has authored or co-authored 18 textbooks on machinery reliability improvement and close to 500 papers or articles dealing with related subjects.

HYDROCARBON PROCESSING NOVEMBER 2011

I9

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HPINTEGRATION STRATEGIES JANICE ABEL, CONTRIBUTING EDITOR JAbel@Arcweb.com

Aging HPI workforce drives need for operator training systems As a leading research and consulting organization focused on the process industries, manufacturing, infrastructure and other industrial sectors, ARC Advisory Group has been closely following the emerging skills crisis, its impact on industry, and potential solutions. In today’s business environment, hydrocarbon processing industry (HPI) companies push their plants to their limits, while, at the same time, both processes and control systems become increasingly more complex. Staffed largely with aging workforces, with many experienced operators getting ready to retire, companies need to ensure that they can continue to operate their plants in a safe, reliable and profitable manner. Operator training simulator (OTS) systems provide an excellent way to train new operators and refresh the skills of experienced ones.

Well-trained workforce. With current business demands, the need for well-trained operators continues to increase. Many plants now operate with feedstocks and energy costs that change frequently depending on the source and market conditions. In addition, satisfying rapidly changing demand creates constant fluctuations and potential instabilities in unit operations that challenge even the most adroit process plants.

The changing demographics complicate the need to improve operations. The US Bureau of Labor Statistics indicates that more than 25% of the working population will soon reach retirement age. This could result in a shortage of almost 10 million workers. By 2030, more than 70 million people in the US will retire, with only about 30 million people available to replace them. A similar scenario is playing out in the European Union and in other developed nations.

The loss of knowledge and the shortage of workers will seriously jeopardize a company’s ability to operate safely and profitably. Human errors are costly, not only in terms of off-spec product and unscheduled downtime, but also in equipment damage, environmental harm and worker safety.

Immersive 3D VR becomes a reality for operator training. Addressing the skills gap of younger workers requires

a host of techniques. These include classroom, on-the-job and computer-based training; site visits to similar plants; and use of high-fidelity training simulators. Most young operators have never experienced a plant maintenance turnaround or a critical situation. The only way to ensure that they will take the proper action during a crisis is to prepare them for one. Most good training simulators allow for hands-on, scenario-based training to teach operators how to deal with normal and emergency situations without compromising the actual plant, worker safety and the environment. Few other tools offer this type of training opportunity.

Simulators also provide a great way to keep the current workforce performing at a high level of proficiency. Preventable

human errors cause approximately 40% of all abnormal situations. Better-trained operators make fewer mistakes; recognize process upsets earlier; and can initiate the appropriate steps and actions to mitigate any potentially harmful, wasteful or detrimental effects.

In training, realism is very important. Model fidelity must be sufficient to replicate the response of the plant so that the operators cannot tell the difference between the simulation and the real thing. The more realistic the simulation, the more the trainees will accept the method and retain what they’ve learned from their experience with the simulator.

Virtual reality (VR) adds another dimension of realism to simulation. VR has been used with excellent results for many years to train astronauts, pilots and military personnel. Now, high-fidelity, 3D virtual reality simulators are available for the process manufacturing and energy industries. VR technology— whether 3D graphics with avatars that interact with the plant and each other or a host of other immersive technologies that use stereoscopic 3D goggles and gloves—has the potential to significantly change the way operators in the process industries train.

This is especially true for addressing the skill gap of younger workers, who tend to embrace the latest technology.

Experienced operators and engineers should also find immersive simulators appealing because of their high-fidelity process and control simulation capabilities, plus their VR capability that provides a realistic and safe training environment for improving efficiency and skills.

In one example, Invensys developed a VR training simulator for the US Department of Energy’s National Energy Technology Laboratory (NETL) that extends the training scope to both control room and outside operators, allowing them to coordinate activities and work as a team the way they would in a real plant. The simulator also allows them to see parts diagrams, work orders and examine the inside of vessels during training sessions. In the virtual world, trainees can perform routine tasks such as opening and closing valves and turning on pumps. It is even possible to practice extinguishing a virtual fire during a simulated emergency; a training routine that could not be attempted in a real plant. This type of experience reinforces learning by bringing virtual reality closer to reality in the process world. HP

The author is a principal consultant at ARC Advisory Group. She performs consulting services and research for ARC’s clients in the pharmaceutical, biotechnology, consumer products, food, beverages, chemicals, oil and gas, and other process industries. Ms. Abel earned a BS degree in chemistry from Clark University, and both an MS degree in chemical engineering and an MBA from Worcester Polytechnic Institute.

HYDROCARBON PROCESSING NOVEMBER 2011

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HPIMPACT BILLY THINNES, TECHNICAL EDITOR

BT@HydrocarbonProcessing.com

14,000 13,000 12,000 11,000 10,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0

14.4% year-on-year during July, and plastics were up 9.1%. The price of consumer chemicals continued to increase modestly, up 3.0% year-on-year for July.

World demand for water treatment products approaches $65 billion World demand for water treatment products is projected to increase 6.2% per year to nearly $65 billion in 2015, according to The Freedonia Group (Table 1). Although growth will be healthy across the globe, the drivers of growth will vary by region. China

Extra-EU exports

Extra-EU imports Extra-EU balance

June ’05 Aug. ’05 Oct. ’05 Dec. ’05 Feb. ’06 April ’06 June ’06 Aug. ’06 Oct. ’06 Dec. ’06 Feb. ’07 April ’07 June ’07 Aug. ’07 Oct. ’07 Dec. ’07 Feb. ’08 April ’08 June ’08 Aug. ’08 Oct. ’08 Dec. ’08 Feb. ’09 April ’09 June ’09 Aug. ’09 Oct. ’09 Dec. ’09 Feb. ’10 April ’10 June ’10 Aug. ’10 Oct. ’10 Dec. ’10 Feb. ’11 April ’11 June ’11

Trade flows, euro millions

Source: Cefic Chemdata International

FIG. 1

Trade data shows a €20.4 billion trade surplus for the EU chemicals sector in the first six months of 2011, down 13.6% when compared with the same period in 2010.

140 135 130 125 120 115 110 105 100 95 90 85 80 0 2000 2001

EU chemicals*; Total sales Sales index (2005=100), left hand side (LHS) Sales % change (y-o-y), right hand side (RHS) Jan.-June 2011, % change (y-o-y) 16.9

35 30 25 20 15 10 5 0 -5 -10 -15 -20 -25 -30

Sales % change (y-o-y)

European Union (EU) chemicals production in July grew by 0.8% compared with July 2010, according to the latest chemicals trends report released by the European Chemical Industry Council (Cefic). However, that figure continues a trend of slowerthan-expected growth, the group said.

Production moved back into positive territory in July after output in June had moved slightly into negative territory. The July production figure dragged down further year-to-date output growth, which now stands at 3.0% for the first seven months of the year, well below the 4.5% full-year 2011 forecast by the trade group in late June.

Data showed a near double-digit, yearon-year price increase in July, led by a 15.2% overall price increase in petrochemicals. For the first six months of 2011, the EU chemical sector net trade surplus reached €20.4 billion, off by €3.2 billion when compared with the same period in 2010.

“The July EU chemical production data show the pace of growth stalling a bit, continuing the trend seen during an unexpectedly moderate second quarter,” Cefic chief economist Moncef Hadhri said.

“After an impressive first quarter, the sector appears to have downshifted, in line with EU industrial growth. Despite slow growth in June, EU chemicals production levels remain 19.4% higher as compared with the December 2008 trough.”

Chemical output up. EU chemicals output rose in July 2011 compared with July 2010. The EU production index for July was up 0.8% compared with July the year prior. Petrochemicals output increased 1.4% in July compared with the year prior, while basic inorganics production rose by 5.1%. Year-on-year consumer chemicals production rose by 5.9% in July; specialty chemicals and polymers output fell by 2.2% and 0.8%, respectively.

Trade surplus. Trade data show a €20.4 billion trade surplus for the EU chemicals sector in the first six months of 2011(Fig. 2), down 13.6% compared with the same period in 2010. The EU-27 posted a €5.4 billion net trade surplus with the NAFTA region from January to June and a €3.3 billion sur-

plus with Asia, excluding Japan and China.

The EU sector ran a €1.3 billion net trade deficit with China. The EU net trade surplus with non-EU Europe reached €6 billion.

Sales level trending higher. The June sales level increased, remaining above the precrisis peak. June 2011 chemicals sales were 5.6% higher compared with June the year prior. For the first six months of 2011, total sales were 16.9% higher as compared to the same period in 2010. Sales values during first half of 2011 were 5.0% higher compared to the peak level reached in first half 2008.

Price increase for basic inorganics.

Basic inorganics prices pushed upward

Sales index, 2005=100

EU chemical production grows ever so slowly

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

Source: Cefic Chemdata International, *excluding pharmaceuticals, new Nace Rev2, C20

FIG. 2

June 2011 chemical sales were 5.6% higher compared with June the year prior.

HYDROCARBON PROCESSING NOVEMBER 2011

I 13

HPIMPACT will remain by far the fastest growing major market. In just a few short decades, China has gone from being a country in which water treatment was at best an afterthought to being the second largest water treatment market in the world. Nevertheless, growth in China will inevitably slow from the torrid pace set in the early years of the 21st century.

Shale gas boom helpful to North American chemical producers The US shale gas exploration and production boom continues to fuel significant cost advantages for North American

commodity chemicals producers as relative costs of natural gas and oil-based feedstocks remain far apart, according to a new report from credit-watch firm Fitch Ratings.

Fitch said it sees the increased availability of cheap natural gas liquids (NGL) feedstocks as a critical factor supporting the competitive position of North American commodity chemicals firms by pushing them down the cost curve versus global competitors. Innovation in drilling technology, including widespread use of horizontal drilling and hydraulic fracturing has sharply boosted liquids supply from unconventional shales in North America, in turn pressuring prices of North American NGLs.

TABLE 1. World water treatment product demand, million dollars Item

% Annual growth 2005–2010 2010–2015

2005

2010

2015

World water treatment demand

35,660

48,100

64,900

6.2

North America

14,630

18,055

22,700

4.3

4.7

Western Europe

8,370

9,925

12,310

3.5

4.4

Asia-Pacific

7,390

11,345

16,720

9

8.1

Central and South America

1,440

1,900

2,540

5.7

6

Eastern Europe

1,395

2,050

2,940

8

7.5

Africa/Mideast

2,435

4,825

7,690

14.7

9.8

6.2

Meanwhile, upstream exploration and production (E&P) companies such as Marathon Oil, Occidental Petroleum and Conoco Phillips have directed more capital expenditures to onshore liquids-rich shale plays in the US and Canada, paving the way for further supply growth.

For downstream producers of petrochemicals and plastics, access to lower-cost NGL feedstocks has boosted export competitiveness in products such as ethylene, polyethylene (PE), and other derivative products.

European producers, in contrast, which rely on heavier crude oil-based feedstocks such as naptha and vacuum gas oil (VGO), continue to see a feedstock cost disadvantage.

Since 2008, light feedstock (ethane) prices as a percentage of Brent crude oil have declined from approximately 43% to 27% at current market prices.

In response to these favorable input cost shifts, companies such as Dow Chemical, Chevron, Westlake Chemical and Nova Chemicals have announced major expansions of North American nameplate petrochemical production capacity, including various ethylene cracker projects.

In addition to expansions along the Gulf

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separation loves undivided attention The reliability of the gas separation unit is essential for the successful performance of the whole plant.

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HPIMPACT Coast, Shell Chemical has announced plans to build a facility in West Virginia, near the Marcellus shale in the Appalachians.

“The surge in shale liquids availability has been a game-changing event for downstream chemical producers dependent on inexpensive light feedstocks,” said Mark Sadeghian, senior director in Fitch’s corporate finance group.

Unconventional gas resources now account for approximately 25% of North

American natural gas supplies, and that share is likely to grow significantly in coming years, Fitch said.

The surge in shale gas availability has contributed to a halving of natural gas prices in the US compared with three years ago, when unconventional gas exploration began to accelerate.

Despite growing signs of a global slowdown and reduced growth rates in Asian export markets, North American chemical

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producers may still benefit materially from the shale gas revolution, with the differential between gas and oil-based feedstocks likely to remain at historically wide levels over the near to medium term.

The quest for a common integration technology The five major automation foundations (FDT Group, Fieldbus Foundation, HART Communication Foundation, PROFIBUS & PROFINET International, and OPC Foundation) have developed a single common solution for field device integration (FDI). These foundations decided to combine efforts and form a joint company. The new company is named FDI Cooperation.

This was made official when all the foundation executives signed contract documents in Karlsruhe, Germany, at the end of September (Fig. 3). The FDI Cooperation will be headed by a board of managers comprised of representatives from the involved organizations, as well as managers of global automation suppliers including ABB, Emerson, Endress+Hauser, Honeywell, Invensys, Siemens and Yokogawa.

Hans-Georg Kumpfmüller of Siemens will serve as chairman of the board. Achim Laubenstein of ABB has been nominated as executive director.

The purpose of the organization is: • To complete the standardization of FDI under the International Electrical Commission • Managing the FDI specification • Finalizing the FDI tool kits for system and device manufacturers.

FDI Cooperation originated from efforts at the EDDL Cooperation Team (ECT) to accelerate deployment of the FDI solution, which originated at the 2007 Hanover Fair.

Since then, the project has carefully shaped the technology direction for the converged FDI solution. FDI is a unified solution for the entire range of field devices, from simple to the most advanced, for the various tasks associated with all phases of their life cycle such as configuration, commissioning, diagnostics and calibration. HP

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Leaders from the five main automation foundations sign on the dotted line to create a new company called FDI Cooperation.

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From initial planning with the Oil and Gas Manager through engineering and life cycle management with COMOS to faster and better decision-making with XHQ, Siemens supports planners, builders, and operators along the whole oil and gas value chain.

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The Best Compressor for CO2?

Kobelco Captures Performance

For various CO2 applications, Kobelco oil-injected screw compressors provide valuable advantages – including a small footprint, high efficiency, outstanding reliability and tremendous cost savings.

But if your application has high pressures or large capacity requirements, the best solution may be centrifugal or reciprocating compressor designs.

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including combination packages such as oil-injected/oil-free screw, centrifugal/oil-injected screw and centrifugal/reciprocating. So we can engineer the ideal solution for you.

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HPIN CONSTRUCTION HELEN MECHE, ASSOCIATE EDITOR HM@HydrocarbonProcessing.com

North America Eastman Chemical Co. has announced a second expansion of its Benzoflex plasticizer line at the Kohtla-Järve, Estonia, site. The expansion will increase Benzoflex capacity by an additional 11,000 metric tons and is expected to be completed by the end of the second quarter of 2012.

The company also plans to expand the Benzoflex plasticizers and Admex polymeric plasticizer lines at its Chestertown, Maryland, and Kingsport, Tennessee sites.

The North America expansions, with a total capacity of approximately 9,000 metric tons, are expected to be completed by the end of the second quarter of 2012.

NOVA Chemicals has entered into three core agreements that support its Corunna cracker revamp to use up to 100% natural gas liquids (NGL) feedstock. The agreements include a transportation service agreement with Sunoco Pipeline L.P. for transportation of ethane feedstock from the Marcellus Shale Basin into the Sarnia, Ontario, region; a definitive agreement for long-term ethane supply from the Marcellus Shale Basin with Caiman Energy, LLC; and a definitive agreement for long-term ethane supply from the Marcellus Shale Basin with a wholly owned subsidiary of Range Resources Corp.

The company continues to work with other producers in the Marcellus region, including Statoil Marketing and Trading Inc., to secure additional ethane feedstock for its Corunna cracker.

Willbros Group, Inc.’s downstream segment has been awarded a multiyear contract to provide project engineering services at the HOVENSA refinery in St. Croix, US Virgin Islands. Willbros will provide front-end engineering and design (FEED) and detailed design for multiple projects throughout the facility.

Sasol has chosen the southwestern region of Louisiana as the site for a planned gas-to-liquids (GTL) facility. The project is reportedly slated to be the first plant in the US to produce GTL transportation fuels and other products. Sasol will embark on a feasibility study over the next 18 months

to evaluate the viability of a GTL venture in Calcasieu Parish, Louisiana. The feasibility study will consider two options: a 2 million-tpy and a 4 million-tpy facility.

Williams’ board of directors has approved an expansion of its Geismar olefins production facility. The facility’s ethylene production capacity will increase by 600 million lb/yr to a new annual capacity of 1.95 billion lb. It is expected to be placed into service in the third quarter of 2013.

The expected capital spending on the Geismar expansion is a range of $350 million to $400 million in 2012–2013.

Saipem has been awarded a new engineering, procurement and construction (EPC) lump-sum contract by Canadian Natural Resources Ltd. The project consists of the EPC of a secondary upgrader with a production capacity of 42,599 bpsd of hydrotreated gasoil, as part of the Horizon Oil Sands Project—Hydrotreater Phase 2 in the Alberta, Athabasca region of Canada.

The project scope includes three units, to be built within the existing complex: a gasoil hydrotreating unit, common facilities (substation and rib), a wash-water and rich-amine system, and the interconnecting pipe rack.

The complete project will develop oil sands resources on the Canadian Natural Oil Sands Lease, about 70 km north of Fort McMurray in a phased development.

At full capacity, the project will produce 250,000 bpcd of synthetic crude oil from 270,000 bpcd of mined bitumen. The project will be completed in 44 months.

ExxonMobil Chemical will build a world-scale facility to manufacture its metallocene polyalphaolefin (mPAO) synthetic lubricant base stocks at its integrated refining and chemical complex in Baytown, Texas. The facility will have the capacity to produce 50,000 tpy of high-viscosity (HiVis) SpectraSyn Elite mPAO. Engineering, procurement and construction (EPC) activities for the new facility have begun, and completion is expected in 2013.

South America Technip, within the framework of a cooperation partnership with Haldor

Topsøe, was awarded a contract to provide basic- and front-end engineering services on a Petrobras grassroots fertilizer complex to be located at Uberaba, State of Minas Gerais, Brazil. The fertilizer complex will include a 1,500 metric tpd ammonia unit based on Haldor Topsøe technology, and the complete utilities and offsite systems necessary for operating the complex.

The basic-engineering design will be developed by Haldor Topsøe and Technip at Technip’s operating center in Rome, Italy, while the Technip operating center in Rio de Janeiro, Brazil, will execute the front-end engineering design (FEED).

Overall engineering activities are scheduled to be completed within the first half of 2012. The complex is scheduled to be in operation within the second semester of 2015.

Europe Navum Energy Ltd. has signed a memorandum of understanding (MOU) with the Turkmenistan state-owned gas concern, Turkmengas, which will lead to the construction of a series of gas-to-liquids (GTL) and gas-to-ethylene (GTE) plants using European, US and South African technologies.

Navum Energy Ltd. and Turkmengas are aiming to establish a joint venture with

Trend analysis forecasting Hydrocarbon Processing maintains an extensive database of historical HPI project information. The Boxscore Database is a 35-year compilation of projects by type, operating company, licensor, engineering/constructor, location, etc. Many companies use the historical data for trending or sales forecasting.

The historical information is available in comma-delimited or Excel® and can be custom sorted to suit your needs. The cost depends on the size and complexity of the sort requested.

You can focus on a narrow request, such as the history of a particular type of project, or you can obtain the entire 35-year Boxscore database or portions thereof. Simply send a clear description of the data needed and receive a prompt cost quotation.

Contact: Lee Nichols P.O. Box 2608, Houston, Texas, 77252-2608 713-525-4626 • Lee.Nichols@GulfPub.com HYDROCARBON PROCESSING NOVEMBER 2011

I 19

HPIN CONSTRUCTION an anticipated 20-year operating life and two stages of development: first to establish a GTL plant to produce high-quality, environmentally friendly gasoline in western Turkmenistan and, later, a number of additional plants also producing diesel, jet fuel and ethylene-based derivative products. The parties also agreed to implement a parallel program for eliminating flared gas in Turkmenistan, aimed at lowering emissions of greenhouse gases.

Sasol, together with partners Uzbekneftegaz and PETRONAS, have signed an investment agreement with the Minister of Foreign Economic Relations, Investment and Trade for the Uzbekistan Government, for the development and implementation of a gas-to-liquids (GTL) project in Uzbekistan.

The conclusion of the investment agreement is an important milestone in the GTL project’s development in which Sasol and

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Uzbekneftegaz each hold 44.5% interest and PETRONAS an 11% interest.

Uzbekneftegaz will supply the feedstock, from the already developed Shurtan group of gas fields, and will offtake the majority of the production, under long-term arrangements. The GTL project’s front-end engineering and design (FEED) will commence before the end of 2011, and, depending on the final investment decision, the plant will be operational in the second half of this decade.

Reportedly, the first LNG terminal of its kind in the Netherlands has been opened in Maasvlakte, thanks to the joint capabilities of SENER and Techint Engineering and Construction, both integrated under the joint venture TS LNG. The Gate terminal has invested €800 million for a 12 billion-m3 capacity terminal built in less than four years. The highscale terminal is, in fact, able to fulfill the natural gas needs of the whole population in Holland.

Africa

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Technip was awarded a strategic engineering contract by Gabon Fertilizers Co. for a world-class, grassroots ammoniaurea fertilizer project to be developed at Port Gentil, Gabon. The proposed project includes a 2,200-metric-tpd ammonia plant and a 3,850-metric-tpd granulated urea plant with self-sufficient utility and offsite units and product export facilities.

Under this contract, Technip will perform the front-end engineering design (FEED) for the project, as well as the detailed cost estimate for the engineering, procurement and construction (EPC) phases.

Middle East L&T Hydrocarbon has a project order, valued around $150 million, from Petroleum Development Oman LLC (PDO).

The order is to set up a greenfield project planned to treat an average of 3 million standard m3/day of gas.

The concept, for the Lekhwair Gas Field Development Project, is a singletrain gas plant in the Lekhwair gas plant for exporting treated gas (CO2 removed and dehydrated gas) to the government gas plant in Yibal and unsterilized condensate and water to the existing Lekhwair production station.

The project includes a main gas treatment plant consisting of gas desulfurization and gas dehydration units with required util-

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HPIN CONSTRUCTION ities and supporting facilities, as well as flow lines, well pad piping, a remote manifold station, and liquid and gas export pipelines.

Foster Wheeler AG’s Global Engineering and Construction Group, through a collaborative agreement with Honeywell’s UOP, was awarded a contract by Oman Refineries and Petrochemicals Co. (Orpic). UOP/Foster Wheeler will provide a basic engineering design package for a sol-

vent deasphalting (SDA) unit at the Sohar refinery in Oman.

The SDA unit is a major part of the Sohar Refinery Expansion Project, which will increase the refinery’s production of petroleum products such as liquefied petroleum gas (LPG), naphtha, Jet A-1 fuel, gasoline, diesel and propylene. It will be designed to process 2.5 million metric tpy of vacuum residue of Oman export blend crude to produce deasphalted oil (DAO) and asphalt

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for road bitumen production. The unit is expected to be onstream in 2015.

Axens technologies have been selected

by Saudi Aramco for its Jazan Refinery and Terminal Project. The refinery, scheduled to be commissioned in December 2016, will have a capacity of 400,000 bpsd. The units under Axens’ design are: • Naphtha hydrotreating for feedstock purification • Aromizing—continous catalytic reforming (CCR) for aromatics production • C5/C6 isomerization unit to provide a high-octane component for the gasoline pool • ParamaX complex to produce highpurity paraxylene and benzene.

These units maximize the gasoline production and aromatics throughput for petrochemical use. The gasoil desulfurization hydrotreater (Prime-D) is also under Axens’ design. This Prime-D unit, reportedly one of the world’s largest, will produce ultra-lowsulfur diesel (ULSD) with less than 10 ppm of sulfur. The refinery will deliver gasoline and diesel that meet Euro V specifications.

Asia-Pacific Alfa Laval has won an order to supply its Packinox heat exchangers to a refinery in Kazakhstan. The order value is approximately SEK 55 million, and delivery is scheduled for 2012.

UOP LLC, a Honeywell company, has been selected by Fujian Meide Petrochemical Co. Ltd. to provide key technology to help meet the growing Chinese demand for propylene. The new propane dehydrogenation unit at the facility will use UOP’s C3 Oleflex technology to produce propylene. UOP will provide engineering design, technology licensing, catalysts, adsorbents, equipment, staff training and technical service for the project at Fujian Meide’s facility in Fujian City, Fujian Province, China. The unit, expected to start up in 2014, will produce 660,000 metric tpy of propylene. It will reportedly be the largest propane dehydrogenation unit in the world to date.

Cellier Activity of ABB France Process Automation Division has a contract with PT Krakatau Engineering for the supply of a new lube oil blending plant (LOBP) for PT Pertamina, Indonesia. The plant will be located in Tanjung Priok, sub-district and harbor of North Jakarta. Cellier Activity will be responsible for the engineering

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HPIN CONSTRUCTION studies, procurement, installation, commissioning and after-sales services. As technology provider, Cellier Activity will supply the core blending equipment and transfer systems for a cost-effective and environmentally friendly production. The plant will be fully automated—from metering of raw materials, blending and transfer to filling—and will be controlled by the Lubcel supervisory system to guarantee process reliability, flexibility and safety. The project startup is scheduled by the end of 2013.

INEOS Technologies has licensed its Innovene PP process for the manufacture of polypropylene homopolymers, random copolymers and impact copolymers to the Ningxia Baofeng Energy Group Co., Ltd., in Ningxia, China. The 300-kiloton/ yr Innovene PP plant will produce a wide range of polypropylene products to serve the growing market in China.

The polypropylene plant’s olefin feedstock will be produced using locally sourced coal via the methanol-to-olefins (MTO) process—an increasingly important route to olefins in China.

plants), and transportation systems in the fast-growing Indian market. Future plans call for MEIP to expand its business coverage to include the Middle East and Africa.

Petron Corp. has selected Axens to supply technologies for its Bataan Refinery Upgrading (RMP-2) Project. The project’s aim is heavier crudes processing for higherquality products and propylene production.

Axens’ technologies concern the following units: a 15,700-bpsd mild hydrocracker for processing heavy coker gasoil; a 35,900bpsd fluid catalytic cracker (FCC) unit; a 19,000-bpsd C4-cut purification system (Alkyfining); a 19,000-bpsd C4 olefins oligomerization unit (Polynaphtha); two FCC gasoline selective desulfurization units (Prime-G+)—8,000 bpsd and 17,600 bpsd; a 5,800-bpsd coker naphtha hydrotreater; and unsaturated LPG treatment units (Sulfrex)—25,000 bpsd and 3,600 bpsd.

The 35,900-bpsd FCC unit will convert heavy vacuum gasoil into higher value products: olefins, gasoline and diesel.

The FCC unit will maximize propylene production at over 250,000 tpy through a FlexEne integrated scheme. This solu-

tion enables the C4 olefinic streams issued from the FCC unit to be further converted to propylene through an Alkyfining unit (purification step) and a Polynaphtha unit (oligomerization step). The complex is due to come onstream in 2014.

Evonik Industries will build a plant in Marl, Germany, for producing functionalized polybutadiene. With this plant, which should go onstream in the fall of 2012, Evonik will be able to offer hydroxyl-functionalized polybutadiene for the first time to its customers in the adhesives and sealant industries.

Chevron Corp. has welcomed Australian Commonwealth Government approval for its Wheatstone Project in Western Australia.

The foundation phase of the project will consist of two liquefied natural gas (LNG) trains with a combined capacity of 8.9 million tpy and a domestic gas plant. It is scheduled to start production in 2016. The environmental approval allows the project capacity to increase to 25 million tpy. HP Expanded versions of these items can be found online at HydrocarbonProcessing.com.

Praxair India Private Ltd., a subsidiary of Praxair, Inc., plans to construct a new state-of-the-art air separation plant in the Pune-Mumbai industrial corridor of Western India. The plant, with a capacity of 300 tpd, will be located 60 km from Mumbai, at an industrial estate near Kalyan. It will supply liquid oxygen, nitrogen and argon to customers in the Maharashtra and Gujarat regions, the largest and fastest-growing merchant market in India. The plant is scheduled to begin operations in late 2012.

Mitsubishi Heavy Industries, Ltd. (MHI) and Suhail Bahwan Group (SBG) have established a joint-venture engineering company named MHI Engineering and Industrial Projects India Private Ltd. (MEIP) in India. MEIP will undertake business development, design, engineering, procurement, construction management, after-sale services and other functions for various industrial and infrastructure projects handled by MHI’s Machinery and Steel Infrastructure Systems Division, which is also responsible for the construction of fertilizer plants, methanol plants, petrochemical plants, and oil and gas production plants.

To start with, MEIP will develop businesses related to chemical and environmental plants (including carbon-dioxide recovery systems and flue-gas desulfurization Select 157 at www.HydrocarbonProcessing.com/RS

25

HPI CONSTRUCTION BOXSCORE UPDATE Company

City

Project CTL Dehydrogenation, Propane Phenol Offsites Ammonia Diesel, HDS Polyethylene, HD Urea (1) Ammonia (2) PMS LPG Urea Ammonia (3) PMS Urea Sulfur Recovery Unit Paraxylene

Ex Capacity Unit

Cost Status Yr Cmpl Licensor

Engineering

Constructor

ASIA/PACIFIC Australia China China India India India India India India India India India India India

Ambre Energy Ltd Fujian Petrochemical INEOS Phenol Tata Chemicals GNFC Ltd Nagarjuna Oil Corp Ltd ONGC Ltd Krishak Bharati Coop Ltd Indian Farmers Fert Coop Indian Oil Corp Ltd BPCL Rashtriya Chemicals Natl Fertilizers Ltd HPCL

India Indonesia South Korea

Matrix Serv Mobil Corp S-Oil Corp

Queensland Fujian Province Zhangjiagang Babrala Bharuch Cuddalore Dahej Hazira Kalol Mathura Sewri Thal Vaishet Vijaipur Visakhapatnam/ Visakh Refinery West Bengal Cepu Ulsan/Onsan Refinery

Petrom Rosneft CAD Nishnekamsk Sibur Refinería Balboa S.A. Enagas Sasol/Petronas/Uzbekneftegaz BP/JBF RAK LLC

Petrobrazi Angarsk Tatarstan Tomsk Los Santos de Maimona Villar De Arnedo Ustyurt Geel

Hydrocracker Hydrotreater, Diesel Alkylation Ethylene Complex Extremadura Refinery Gas Compression GTL Polyethylene Terephthalate (PET)

Uberaba La Cangrejera Madero Salamanca Tula Pointe-a-Pierre

Ammonia Styrene Monomer Diesel, ULSD Gasoline Desulfurization Refinery Alkylation, Sulf Acid

South Pars Muscat Muscat Jazan Shaybah

Sulfur Degasser Petrochemical Complex Refinery Refinery Gas Treating

Calcasieu Pr Geismar Texas City

Gas to Liquid Olefins, Alpha FCC, flue gas

EX RE RE RE RE EX

18 bbl 600 m-tpy 400 Mtpy bbl 123700 Nm3/h 1 MMtpy 340 kty 3325 m-tpd 1100 t/a 60 t/a None 2300 m-tpd 1520 t/a None None 30 tpd 900 Mtpy

50 221

335 1400

S U E E U U E U C C E E U U

2014 2013 2012 2012 2012 2013 2012 2011 2011 2012 2012 2012 2012

E E C

2012 2014 2011

E E U E E U E P

2014 2011 2012 2011 2011 2012 2014 2014

F E E E S U

2015 2015 2015 2015 2015 2012

U P F F E

2013 2012 2012 2015 2014

Samsung Eng

S P P

2012 2013 2013

Shell UOP

UOP INEOS Phenol PDIL Haldor Topsøe Samsung Eng Saipem Haldor Topsøe Jacobs Haldor Topsøe

Samsung Eng Axens

PDIL PDIL Samsung Eng Samsung Eng PDIL|Saipem PDIL PDIL PDIL PDIL PDIL PDIL

Samsung Eng Samsung Eng

PDIL Samsung Eng Samsung Eng

Samsung Eng Samsung Eng

Fluor|Vnipineft

Fluor

EUROPE Romania Russian Federation Russian Federation Russian Federation Spain Spain Uzbekistan Belgium

34 4 6000 370 110 10 1.3 390

m-bpd MMtpy bpd Mtpy Mbpd kW MMtpy tpy

2700 817

Haldor Topsøe ExxonMobil Stratco

Fluor|Vnipineft Shell|Technip|FW|WorleyParsons |UOP Tecnicas Reunidas Samsung Eng

Tecnicas Reunidas

LATIN AMERICA Brazil Mexico Mexico Mexico Mexico Trinidad

Undefined Pemex Pemex Pemex Pemex Petrotrin

EX

1500 m-tpd 150 Mtpy None 25 Mbpd 25 bpsd 10000 bpd

700 345 2800

UOP|Lummus Technology Axens CDTECH Stratco

Technip|Haldor Topsøe CB&I CDTECH Saipem Saipem Bechtel|Techint\Lummus Techint\Lummus

MIDDLE EAST Iran Oman Oman Saudi Arabia Saudi Arabia

Petropars Oman Oil Co Oman Oil Co Saudi Aramco Saudi Aramco

500 1.2 1.2 400 24000

t/a Bcfd 1200 Bcfd 1200 bpd 7000 MMscfd 605

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UNITED STATES Louisiana Louisiana Texas

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EX RE

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HPI VIEWPOINT The evolution of safety in the oil and gas industry Chuck Lyons, P.E., is KBR’s vice president of Global Quality, Health, Safety and Environment (QHSE). He coordinates the global QHSE strategy with senior leadership and oversees the QHSE support to projects globally. Mr. Lyons joined KBR in 2004. Prior to his current position, he served as director of KBR Onshore HSE. He holds a BS degree in chemical engineering from Texas A&M University and has more than 25 years of industry experience, including QHSE leadership positions at ConocoPhillips, ExxonMobil, Tenneco and Schlumberger.

As a safety professional with 25 years of experience in the hydrocarbon and chemical industries, I’ve had the unique opportunity to view first-hand the evolution of safety. Upon entering this field, much of the early drive for safety within organizations was centered on loss of physical assets and the moral issues around loss of life.

I remember hearing of a refinery in the early 1960s whose safety goal was to have only five fatalities during the coming year. This wasn’t because companies lacked a concern for the well-being of their employees. The oil business was simply perceived as dangerous, with injuries viewed as inherent to the nature of this business.

First job. I started as a safety engineer in 1986, working for a polystyrene plant. With the creation of Occupational Safety and Health Administration (OSHA) regulatory requirements in the mid-1970s, safety professionals in this era played an enforcement role, ensuring compliance with OSHA guidelines designed to train companies and employees on proper safety standards to reduce workplace injuries. The use of hard hats, safety glasses and other personal protective equipment was the primary focus of safety programs back then. While this era marked progress, the industry as a whole struggled to fully integrate safety into its core business and kept it separate as a compliance function.

Present day. We know the health, safety and well-being of employees should be of foremost importance to any company, and it is a fundamental part of successfully conducting business.

The mistake the industry was making was that safety professionals attempted to rank safety in a vertical order of importance. Safety professionals wrote policies with a primary focus on employee safety. Unfortunately, these policies failed to recognize the correlation between the guidelines and the operating impact of their content. This created unique challenges through the next decade.

Safety is a key business element. Even while companies fine-tuned safety procedures, safety remained separate from operations and it was primarily compliance-driven. Then, in the late 1980s, the industry was forced to reassess the role of safety after two major incidents—in 1988, a catastrophic fire and explosion on an offshore platform in the North Sea, and, in 1989, a fatal chemical plant explosion in Pasadena, Texas. Public and safety regulators began to see that the existing mechanism for policing the industry was not sufficient, and that additional influence was needed to improve workplace safety.

These two significant incidents in the energy business became the catalyst for a paradigm shift in the safety culture of organizations. Companies understood, more than ever before, the need to integrate safety and operations.

Today, the most successful safety programs are those recognizing that safety cannot be viewed in a vertical order of importance.

Rather, safety must be looked upon as a value which is inherent to every part of a company’s operation with an underlying commitment to creating an incident- and injury-free work environment for all employees.

Engage the workforce for an effective safety program. A good safety system in the workplace has tools to help

employees look out for themselves and their fellow workers. It takes more than just safety personnel to implement an effective safety program—an essential factor in the equation is the company’s safety practices. Perhaps the most important elements of an effective safety program are leadership support and visibility.

An organization that can look to leadership to actively support safety and engage employees, vendors, subcontractors and clients about the importance of safety in the business is most successful in the safety arena. In support of this idea, at KBR, key leaders take part in onsite safety leadership visits that have been effective in decreasing injury rates.

With leadership onboard, the next key element to an effective safety program is employee engagement. This involves a robust task analysis process as well as employee safety teams. An effective employee safety team should include all levels of employees to ensure a wide variety of input from the various groups on a job.

It is important for the teams to be led by operations and craft employees with safety representatives involved as an advisor or facilitator. Additional key elements to promote safety programs are those that address employee behaviors and employee commitment to safety in the workplace. At KBR, our Shaping Accident Free Environments (SAFE) program uses employee commitment to help drive behavior changes. Employees are encouraged to intervene when they witness an unsafe condition or see someone working unsafely. Every employee must embrace his or her obligation to intervene and stop unsafe activities.

Looking to the future of safety. Many companies place safety as a core value. Ensuring the safety of people—making sure each employee returns home daily as healthy, functional and productive as when they came to work—is paramount for the success of any business.

The hydrocarbons business will be a leader in safety improvement going into the future. We continue to find ways to improve safety and take performance to the next level.

The testament to the industry’s success lies in the performance of KBR and other companies that have achieved, and continue to achieve, record safety while executing megaprojects across the globe. To ensure our future success as an integral function of any business, we, as safety professionals, must continue to seek and implement new, innovative ways to identify and control the risks with which we are presented. HP HYDROCARBON PROCESSING NOVEMBER 2011

I 29

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PLANT SAFETY AND ENVIRONMENT

SPECIALREPORT

Mitigate refinery influent water supply contamination Resolving critical water supply and quality issues by managing risk and implementing successful solutions W. GARRISON, Valero Energy Corp., San Antonio, Texas; and L. HUCHLER, MarTech Systems Inc., Lawrenceville, New Jersey

F

reshwater supply is critical to refinery operations, although the centralized design makes it a potential single-point source of failure. Contamination of the freshwater supply to a refinery is a significant event because it creates the risks of derating or complete shutdown of the refinery, as well as damaged equipment.

Managing these risks requires pre-planning to anticipate potential hazards, as well as intensive management of the pretreatment water system during these events to reduce the negative impact on units that use purified water, such as evaporative cooling water circuits and steam generators. This article discusses two events that compromised the influent water supply to a major Gulf Coast refinery and the refiner’s response to these incidents.

BACKGROUND

This Gulf Coast refinery receives freshwater from two rivers via a canal system managed by the regional water authority. The refiner stores over 460 million gallons (MMgal)—20 days’ supply—in a holding pond that serves the refinery influent water treatment facility located approximately two miles away.

The first event, a structural failure of a transfer pipe in February 2001, released measureable concentrations of refinery wastewater into the influent water supply, compromising the entire pretreatment system. This event sent off-spec water to the cooling circuits. Despite the malfunctioning demineralizers, refinery personnel delivered on-spec, demineralized water to the steam generators (50–850 psig) and power turbines without interruption, and there were no permanent consequences to the pretreatment system’s clarifiers, filters or demineralizers. The cooling water circuit experienced tube failures in two newly installed heat exchangers approximately one year following this event. The root cause of the failures was microbiologically induced corrosion due to poor bacterial control.

In the second incident, which occurred in September 2008, the Category 3 Hurricane Ike caused a Category 5-equivalent storm surge that forced seawater into the refinery’s holding ponds and into the freshwater supply canal for 18 miles. The seawater surge deprived the refinery of freshwater and prevented a timely restart of operations. The refinery, protected by a levee system, was not damaged.

As shown in Fig. 1, the holding pond is an unlined basin with earthen banks that supports water hyacinths and other naturallyoccurring vegetation. The influent clarifier (Fig. 2) removes sus-

pended solids from the river water, typically processing approximately 15,000 gallons per minute (gpm). The majority of the clarified water flows to the cooling towers, while a smaller portion flows through gravity filters followed by pressure filters to remove suspended solids (Fig. 3). Demineralizers then remove dissolved contaminants from the water. The demineralized water flows to fired and process heat boilers that generate steam to heat the process and drive turbines for power generation and other equipment drivers, such as pumps and fans.

THE FIRST INCIDENT

In early February 2001, a wastewater transfer line suspended over the earthen holding pond developed numerous leaks, releasing partially treated wastewater into the refinery’s freshwater supply. Refinery personnel compared the conductivity of the contaminated pondwater with typical results to assess the severity of the contamination, and then used the ratio to predict the increase in the ion loading on the demineralizers.

Other impacts included poor performance of the influent clarifier, severe fouling of the gravity and pressure filters, contamination of the cation and fluidized anion units, and dramatic increases in the fouling and bacterial activity in the cooling water

FIG. 1

Holding ponds.

HYDROCARBON PROCESSING NOVEMBER 2011

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SPECIALREPORT

PLANT SAFETY AND ENVIRONMENT

circuits. Refinery personnel aggressively managed the operation of pretreatment system assets to prevent off-spec makeup water from entering the steam generators. However, controlling the risk of bacterial fouling in the cooling water circuit was not as successful.

Contamination of the freshwater holding pond continued for over a week while maintenance personnel repaired the numerous leaks. After the event, plant personnel replaced the entire wastewater transfer line.

Immediate response and corrective actions. The most

immediate concern was stopping the contamination by repairing the ruptured transfer line and maintaining a high-quality demineralized water supply for the steam generators. Refinery personnel decided not to flush the contaminated water out of the holding pond because the flushing procedure would have dramatically increased the concentration of suspended solids from turbulence created by high flowrates in an unlined earthen pond. This action could have compromised the influent clarifier operation.

A preliminary assessment of the plant indicated that the demineralizer run lengths would be one-sixth of the normal run

Influent clarifier.

Freshwater holding pond

LN

VA

Ca

na l

FIG. 2

Clarifier

Clearwell Gravity filters

Pressure filters

Boilers

Packed-bed demineralizers FIG. 3

32

Process flow schematic.

I NOVEMBER 2011 HydrocarbonProcessing.com

length, or four hours. This run length was slightly longer than the normal regeneration procedure, indicating that operators would have to continuously regenerate a unit to meet the current coldweather demand for demineralized water and steam generation.

Influent clarifier. The influent clarifier was performing poorly, with high effluent turbidity causing high pressure differentials in the downstream filters. The wastewater contaminants were interfering with the clarification process.

The most logical corrective action, feeding additional coagulant, was difficult due to a dysfunctional automated feed system that made precise feedrate adjustments difficult. Operations personnel depended on the automated system and had lost the skill and habit of conducting jar tests, the most common diagnostic test for manual feed control. Another complication was the lack of reliability of the online turbidity analyzer, which forced operators to frequently measure turbidity. Consequently, operators had difficulty predicting the correct feedrate, and constantly overfed and underfed chemical.

The clarifier efficiency was compromised, and the downstream filter and demineralizer efficiency were negatively impacted.

Several other limitations on the clarifier operation occurred.

During normal operation, this refinery did not feed an oxidizing biocide (chlorine donor chemical) upstream of the clarifier to kill bacteria and counteract the dispersant characteristics of organic contaminants. This refinery also did not have a chemical feed system for a flocculant that would have improved the clarifier operation. The cold temperatures further compromised the efficiency of the coagulation and settling reactions in the clarifier, and the plant had no capability to inject steam or divert condensate to the clarifier inlet stream to improve the efficiency of the clarification reaction.

Additional investigation revealed two other causes of poor clarifier performance: a recent pond dredging procedure and a change to a freshwater source that had higher concentrations of naturally occurring organic contaminants. Immediately prior to the wastewater transfer line leak, plant personnel were conducting an annual dredging procedure to remove vegetation from the holding pond. The dredging process increases the concentration of suspended solids in the water. Since the vegetation normally acts as a “sink” for hydrocarbon contaminants, disturbing and removing the vegetation can release additional hydrocarbon contaminants into the freshwater.

The regional water authority draws water from a primary source, with occasional additions from a lower-quality, Refinery secondary source. During this event, the freshwater supply had a larger-than-normal proportion of water from the secondary source, which increased the concentration of naturally occurring organic contaminants that reduce the efficiency of the clarification reaction.

Demineralizers Filters. Pressure differentials across the gravity and pressure filters increased dramatically during this event, indicating the accumulation of suspended solids from the poorly functioning clarifiers. The spent filter backwash water had a strong septic odor and brown foam, indicating severe biological contamination.

Operations personnel understood the risks of fouled filters passing suspended sol-

PLANT SAFETY AND ENVIRONMENT ids downstream to the demineralizers. In response, they created and immediately implemented a filter cleaning protocol.

Demineralizers. Despite the intensive remediation efforts on the upstream filters, some suspended solids and bacteria reached the cation units. Normal backwashing during each regeneration cycle was sufficient to remove the suspended solids from the fluidized cation units. The packed-bed units required a non-routine, external resin cleaning procedure. The bacterial contamination was severe; in one packed-bed cation, the bacteria created a large, black mass on the surface of the upper resin bed that operators physically removed during resin cleaning.

Visual inspection of the anion resin and evaluation of the effluent quality indicated that the “old” or conventional fluidized anion units—which have only strong base anion (SBA) resin— had a high rate of organic fouling from the wastewater contaminants. The packed-bed SBA resin had low rates of organic fouling because these units have a weak base anion in a separate compartment that acts as an “organic trap.” Refinery personnel designed an offline cleaning protocol to remove the organic contaminants from the SBAs. The cleaning procedure was conducted on one train per day during the event and as needed after the wastewater transfer line was repaired.

Cooling water systems. The cooling towers used contaminated clarified water as makeup. The hydrocarbon contaminants acted as nutrients for bacteria, increasing the risk of fouling and under-deposit corrosion in the heat exchangers. The appropriate response, feeding additional oxidizing biocide, proved to be difficult because, as in all refineries, the responsibility for water treatment for cooling towers is decentralized. Each operator at each unit had a different understanding of the requirements for monitoring and controlling the oxidizing biocide feedrates, increasing the risk of bacterial fouling and microbiologically induced corrosion.

Recovery. After seven days, maintenance personnel repaired

all leaks on the wastewater transfer line and stopped the contamination of the holding pond. The clarifier operation rapidly returned to normal. The chemical supplier conducted feasibility tests for alternate chemical treatment protocols for the influent clarifier to optimize the effluent quality and to reduce the risk of compromised effluent quality during future upsets in raw water quality. The refinery trained operators to conduct jar tests to improve chemical feed control for seasonally changing water quality and during system upsets. Operations personnel developed a preventive maintenance procedure for the online turbidity instrumentation and installed new chemical feed systems.

After the termination of the leak, the filters continued to operate with high foaming and poor-quality effluent. Operators conducted an offline sterilization procedure using an oxidizing biocide. Following the completion of the final cleaning and disinfection procedures, the filter operation returned to normal.

Plant personnel requested an analysis of samples of resin from every demineralizer vessel during the event. Unfortunately, the results were not available quickly enough to aid corrective actions. The resin analyses results indicated that most of the resin was at or near the end of its useful life and would require replacement to maximize effluent quality, minimize water and chemical usage, and maximize system reliability. Following the event, operations personnel created a proactive resin management plan. Post-cleaning, the demineralizers operated normally and produced water according to specifications.

SPECIALREPORT

THE SECOND INCIDENT

On Sept. 13, 2008, Hurricane Ike made landfall near Galveston, Texas, causing a Category 5-equivalent storm surge that flooded the coastal areas of East Texas. In anticipation of the storm, the refinery terminated operations and evacuated the facility. A levee system protected the refinery from inundation by seawater, but it could not protect the canal supplying freshwater, the freshwater storage pond and the adjacent wastewater stor-

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SPECIALREPORT

PLANT SAFETY AND ENVIRONMENT

FIG. 7 FIG. 5

FIG. 6

Irrigation pipe.

Bypass pipe routing—HDPE pipe.

age pond outside the levee boundaries. Like all refineries using freshwater, the pretreatment plant could not purify seawater or freshwater contaminated with measureable quantities of seawater.

Immediate response and corrective actions. The

refinery’s first priority was to restore the freshwater supply to the influent water treatment plant to initiate steam generation.

Refinery personnel investigated several parallel options: restoring freshwater in the canal, draining the storage pond, desalinating the contaminated water in the pond and/or canal, and creating a connection to one of the canal pump stations using temporary piping to bypass the pond. They decided on the most direct method: bypassing the large holding pond.

Canal flush. While the canal authority pumped freshwater into the short section of canal outside the levee system, the refinery supplied diesel pumps to pump contaminated water out of the canal. The initial assessment indicated that the canal flush procedure would require several days.

34

HDPE pipe.

I NOVEMBER 2011 HydrocarbonProcessing.com

Freshwater storage pond. The refinery also began draining this storage pond by breaking the containment wall near the second pump station and using temporary diesel pumps to drain the contaminated water. The limited availability of diesel pumps and the size of the transfer pipe meant that the draining and refilling process would require at least a month before returning the freshwater storage pond to service. Consequently, refinery personnel investigated alternatives to bypass this holding pond or desalinate the water in the pond.

Desalination. Refinery personnel contacted mobile water treatment vendors to evaluate desalination technologies to expedite the restoration of all or part of the freshwater requirements.

However, the capacity of the available equipment was smaller than the minimum required capacity of several thousand gpm. The refinery began to investigate bypass piping options.

Bypass piping. Plant personnel decided that the installation of piping to bypass the contaminated holding pond was the fastest solution to the freshwater problem. Irrigation pipe, although not a perfect solution due to the relatively small diameters and thin walls, was readily obtainable and would provide a portion of the water required to operate the refinery until larger, stronger pipe became available.

Recovery. Within 10 days of Hurricane Ike’s landfall, the refinery installed three 13,000-ft strands of 10-in.-diameter aluminum irrigation pipe between the canal pump station and the pump station that had transferred water from the holding pond to the refinery’s influent water treatment plant. The pipe installation made possible the supply of approximately 40% of the refinery’s boiler makeup water (Fig. 4).

The water treatment plant began making demineralized boiler feedwater on Day 11, and the refinery introduced steam into the primary headers on Day 12. The refinery installed three parallel strands of irrigation pipe (Fig. 5) on Day 14 to provide freshwater for cooling applications, allowing the refinery to return several of its units to operation.

Concurrent with the installation of the irrigation piping, the refinery made plans to install a 36-in.-diameter, high-density polyethylene (HDPE) water pipe to temporarily meet the full demand for freshwater to the refinery. Refinery personnel floated the HDPE pipe across the wastewater pond adjacent to the freshwater

PLANT SAFETY AND ENVIRONMENT pond and installed the pipe on the retaining wall that separates the two ponds (Figs. 6 and 7).

Refinery personnel commissioned the HDPE pipe on Day 23 to provide over 15,000 gpm of freshwater and allow the remaining refinery units to return to operation. Refinery personnel continued to flush the freshwater holding pond to reduce salinity, and returned this pond to service on Day 73.

CONCLUSION

The awareness of risk usually begins during a crisis. The key to reducing risk is not experience, but rather proactive management of risk. Managing risk does not start with planning; it starts with envisioning scenarios that would lead to a crisis. Operations personnel sometimes regard scenario planning as pure speculation because it requires personnel, grounded in their rear-view mirror of experience, to consider the possibility of events that have never happened and have a low probability of happening. The process of scenario planning challenges the boundary between reality and imagination and requires a temporary suspension of disbelief.

In both cases of water supply contamination, refinery management had not developed plans for these types of failures. In the first incident, contamination of influent water supply by a leaking wastewater transfer pipe, refinery personnel had not imagined or conducted scenario planning for an event of this severity. In the second event, refinery personnel had evaluated the risk of inundation of the freshwater supply system with seawater in their emergency planning efforts and identified an option to install a pipe within the levee system from the refinery water treatment facility to the freshwater canal. The refiner did not install this bypass piping

SPECIALREPORT

because personnel defined this risk as very low; there had been no known severe seawater inundation in the refinery’s 100-year history.

Following each of these events, plant personnel analyzed shortcomings in the refinery water supply systems and implemented changes to mitigate the risk of future events. In response to the first incident, refinery personnel installed more reliable instrumentation and feed systems, and conducted training in water chemistry, testing techniques and troubleshooting. After the second incident, plant personnel upgraded the 36-in. HDPE pipe to a permanent installation for use as a future contingency.

More importantly, management successfully fostered a change in culture. Refinery personnel now have a greater appreciation of the value of scenario planning and a better understanding of effective crisis management methods. HP

Walker Garrison is the technology advisor for utility infrastructure at Valero Energy. He directs new project development activities and stewards reliability and efficiency improvement initiatives that impact refinery steam, power and water systems. Dr. Garrison has a PhD in chemical engineering from Auburn University and is registered as a professional engineer in Texas.

Loraine A. Huchler is president of MarTech Systems, Inc., a consulting firm that provides technical advisory services to manage risk and optimize energy and water-related systems including steam, cooling and wastewater in refineries and petrochemical plants. She holds a BS degree in chemical engineering from the University of Rochester. She also has professional engineering licenses in New Jersey and Maryland and is a certified management consultant.

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PLANT SAFETY AND ENVIRONMENT

SPECIALREPORT

Tips on communicating LOPA results to management Communicate clearly and explain thoroughly G. C. SHAH, Mustang Engineering, Houston, Texas

A

lthough layers of protection analysis (LOPA) has often been used by safety professionals for risk assessment, some managers remain skeptical of its effectiveness. Usually, the skepticism stems from a lack of proper information (communicated to management) about LOPA. This skepticism is healthy and provides a fine opportunity to safety professionals to communicate safety to management. Consider the following incident: A busy plant manager took some time off from the plant to attend a LOPA facilitation being conducted for a large project for her plant. The facilitator made profuse use of acronyms and probability calculations in evaluating risk of unsafe events and, where appropriate, made recommendations for additional safeguards. While the LOPA process was technically sound, it frustrated the manager. She said, “Although I see what you guys are doing, I have considerable trouble seeing its relevance in really reducing risk.

I have had a lot of trouble following your acronyms. Can’t you folks talk in laymen’s terms so that ordinary people like us may understand what LOPA really is?”

This is not an uncommon incident. It offers us an opportunity to distill LOPA wisdom in managerial terms.

The big picture. Today, managers are extremely busy with scant time left for delving into details of LOPA or other risk assessment methods. Managers are typically financially astute professionals with good people-skills. They are very good at communicating their ideas effectively to all audiences. They focus on the results and not myriad details about the LOPA process. Their educational backgrounds may include training in finance, communication, law and/or engineering. To streamline communication to management, consider the following:

• Avoid technical jargon. The jargon and acronyms that are so useful in technical discussions with safety professionals can be a significant hindrance while you are trying to communicate to management. Try to avoid or minimize use of technical jargon.

On the other hand, if you must use it, try to explain the meaning of each term in a simple fashion.

• Managerial language. Emphasize that LOPA is closely tied to a company’s productivity and image. This will require relevant data that links risk and its associated cost. Stated differently, additional safeguards that reduce risk should be weighed in terms of their overall cost (life cycle cost) and the economic benefits they yield by reducing risk.

• Be concise in the presentation. Keep in mind, you have limited time in which to communicate key points of your LOPA work. Be strategic and focus on “big impact” items. Don’t get bogged down in minutia.

Of course, in the LOPA report, all the details of the findings will be spelled out.

• LOPA reports. Keep readers in mind in developing your reports. The executive summary section should focus on the key action items. Make the report readable to all relevant readers. Your readers are managers, engineers, safety professionals and plant operating/maintenance personnel.

• Start LOPA facilitation with a brief presentation on LOPA. This will ensure the LOPA team is familiar and proficient with the use of LOPA terminology. Prior to the LOPA sessions, you may send out the LOPA presentation to each of the LOPA participants.

Specifics. Face-to-face communications with plant management or corporate management naturally require preparation.

What issues are managers most interested

in? It is certainly difficult to predict the exact questions and the depth of inquiry from managers, but the items listed here are a good start.

Question (Q): Our company is totally committed to safety. We follow recommendations of HAZOPs and where necessary install additional safeguards to reduce risk.

Why then do we need LOPA? We believe we are already reducing risk with the help of HAZOP recommendations. Does LOPA really reduce risk (beyond that reduced by the HAZOP)?

Answer (A): HAZOP does help reduce the risk. However, since it is qualitative and subjective, it could result in improper application of safeguards to reduce risk.

The safeguard you apply may not reduce risk to the desired extent, since there is no quantitative consideration of risk reduction. LOPA, on the other hand, quantifies risk and therefore reduces subjectivity. LOPA is typically performed after a HAZOP and focuses on selected high risk issues. LOPA helps you choose among various alternative safeguards to get the most economically justifiable safeguard.

Of course, LOPA requires relevant data on the reliability of the safeguards. From a regulatory perspective, OSHA considers compliance with the standard (for example, ISA-84.00.01-2004) as a part of the compliance with the process safety management (PSM) standard.

Q: What is the meaning of the term “probability of failure?” Explain briefly other LOPA terminology.

A: Probability of failure on demand (PFD) is the chance that a specific safeguard will not perform its intended function when required. For instance, assume a shutdown valve is supposed to close when a hazardous event arises (say, high level in a tank). Failure of that valve to close could HYDROCARBON PROCESSING NOVEMBER 2011

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SPECIALREPORT

PLANT SAFETY AND ENVIRONMENT

result in tank overflow with major consequences. If that valve fails to close one time out of 100 times, then the PFD will be 0.01. Devices with smaller PFD values help reduce risk more than their counterparts with higher PFD values. Today, many electronic instruments are certified and show the expected values of PFDs. In a broad sense, there are two type of failures: Dangerous failures (such as the previous example) and safe failures (failures that do not result in unsafe consequences but could cause plant interruptions). Now, safe failures do not mean there are no consequences to such a failure, but these are usually monetary as opposed to life threatening. Sometimes, safe failures are called spurious trips.

Independent protection layer (IPL) is a safeguard that works independent of other safeguards. Some examples of IPL are relief valves, process control systems (PCS), interlocks and alarms (maintained so that the operator has adequate time to respond to prevent a hazardous event from occurring). To be effective, an IPL should meet the following criteria: • It should be specific for preventing a given hazardous event.

• It should be independent and not influenced by the performance of other safeguards.

• It should be dependably effective in reducing risk in accordance to its PFD value, which requires that the IPL be properly specified, and installed.

• Finally, the IPL should be auditable (inspected and maintained at some specific intervals).

Acceptable risk within the LOPA concept is expressed by the number of events that can be acceptable per year. For instance, 1.0e-04 per year means that one event every 10,000 years is the acceptable risk level. This level depends on a number of factors including the size of the event (events that have offsite impact or that could cause injuries/fatalities will need to be very infrequent, probably at a rate of 1e-05), litigation and company reputation. Less risky events could be tolerated at higher frequency than 1e-05. In several countries around the world, regulations dictate the acceptable risk level.

Q: What is the LOPA process?

A: LOPA is performed on relatively “high” risk hazardous events identified by a HAZOP. For each such event, LOPA

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evaluates the extent of protection provided by the existing safeguards and compares it with desired level of protection by a company. If the desired protection is greater than what currently exists, additional safeguards are recommended. The process of risk assessment and risk management is not a one-time activity. It is an ongoing process that continues throughout the life of a project or a plant.

Q: How many IPLs do I need?

A: The number of IPLs you need depends on a specific hazardous event, its acceptable risk level and current risk level, and risk reduction (probability of failure) provided by each safeguard.

Q: How do I determine what level of protection is required?

A: This question is, in essence, an extension of the question on the number of IPLs we discussed earlier. The level of protection depends on the severity of consequence.

For instance, an event that could result in multiple injuries, a major environmental impact or a major impact on the company’s public image would be tolerated less frequently than an event which has a relatively minor safety or environmental impact.

The level of protection also depends on your company’s policy on risk tolerance.

In several countries, the level of protection required is driven by regulations.

Q: Can LOPA go wrong?

A: Yes. The phrase “garbage in, garbage out” applies here. Assigning inappropriate PFD values would render a LOPA analysis useless. Wrong PFD numbers or improper consideration of safeguards may not provide the desired level of protection or it may provide excessive protection that is not economically justifiable. LOPA, if not properly applied could become a mere number-crunching (playing with PFD values) exercise. Having experienced facilitators, an experienced LOPA team and updated relevant documents helps ensure LOPA will be done properly. Keep in mind, the PFD numbers are average values. For a number of safeguards, average PFD values are available in literature and tend to be conservative.

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PLANT SAFETY AND ENVIRONMENT

SPECIALREPORT

Spent caustic management: Remediation review Proper disposal of spent caustic requires full understanding of waste components G. VEERABHADRAIAH, N. MALLIKA and S. JINDAL, KBR, Singapore

the spent caustic composition varies depending on the operating temperature for the caustic treatment process. To facilitate appropriate handling of these characteristically different streams, as shown in Table 1, it is advisable to segregate them by the contaminants present: Sulfidic: Primarily sulfides (scrubbing of straight-run gaseous hydrocarbons) Phenolic: Phenols, cresols and xylenes with sulfides (scrubbing of cracked gases/gasoline) Naphthenic: Naphthenic acids (scrubbing/mercaptan-extraction of middle distillates.)

SOURCE REDUCTION

Reducing waste generation at the source is the first and most preferred step. When designing caustic treating processes, best TABLE 1. Typical spent caustic composition Sulfidic

Phenolic*#

Naphthenic

Sodium hydroxide, wt%

2–10

10–15

1–4

Inorg. sulfides as S, wt%

0.5–4

0–1

0–0.1

Mercaptide as S, wt%

0.1–4

0–4

0–0.5

Cresylic acids, wt%

–

10–25

0–3

Naphthenic acids, wt%

–

–

2–15

Component

Carbonate as CO3, wt% pH Free oil * #

0–4

0–0.5

–

13–14

12–14

12–14

vary up to 20% in raw/unskimmed content

Dilute caustic operation results in about 70–80% dilution in composition.

Olefins stream is like diluted one with higher S,CO3 and lesser phenols

Source characterization and segregation. Typical

processes in the hydrocarbon industry where spent caustic is generated are caustic scrubbing of straight-run light hydrocarbons, feed streams to isomerization and polymerization units; cracked gases from thermal/catalytic cracking units; and caustic washing of middle distillates, followed by mercaptans extraction/sweetening operations. The caustic converts the acidic components into their respective inorganic/organic salts of sodium such as sulfides, carbonates, mercaptides, disulfide oil, phenolates, cresolates, xylenolates and naphthenates. Caustic strength used (typically 5–20%) in these processes is governed by feed type and nature of caustic treatment; accordingly, the residual caustic strength will differ. Since acidic components have a wide boiling range,

Most Reduce

Source reduction

Reuse

Use within source facility

Recycle

Use secondary value externally

Recover

Extract the usable/saleable material

Order of preference

S

pent caustic handling, treatment and disposal are major concerns for refining and olefins (ethylene) production facilities due to its hazardous nature and noxious properties. As sources for spent caustic generation are diverse, they do produce characteristically different waste streams consisting of inorganic and organic acidic components such as carbon dioxide (CO2) sulfides, carbonates, mercaptans, phenolics, cresylics and naphthenates. These components are acidic and must be removed to avoid corrosion of downstream equipment and to prevent poisoning catalysts. The conditions can be further complicated by neutral oil carryover. Several treatment methods can be used to manage spent caustic and they include chemical precipitation, neutralization, chemical reagent oxidation, wet oxidation, catalytic oxidation and incineration.

Improved processes are now available. Each method offers certain advantages while its application would depend on the waste stream composition, size and the configuration of the total process facility and toxicity threshold limits of downstream biological treatment systems. Spent caustic is toxic to bacteria used in the wastewater treatment unit. When zero discharge or stringent limits are stipulated in environmental permits, high dissolved solids present in the spent caustics add to treatment loading in desalination plants.

Selecting the best treatment method is a critical task, especially in meeting total waste management needs. It is often driven by environmental regulatory limits associated with emissions and discharges. There are essential elements in dealing with spent caustic streams that will be presented in this article. They involve applying the principles of waste management hierarchy, with merits and demerits of each possible solution, as shown in Fig. 1.1–2

Remove Treat to remove hazards before disposal Least FIG. 1

Waste management hierarchy.

HYDROCARBON PROCESSING NOVEMBER 2011

I 41

SPECIALREPORT

PLANT SAFETY AND ENVIRONMENT

practices seek to generate the least amount of spent caustic while maintaining the desired efficacy of the process. The following measures help achieve the objective:

operation of these regenerative units that remove major H2S quantities would reduce the load on caustic wash units, thereby minimizing spent caustic generation.

Caustic-free processes. Eliminating spent caustic generation at the source can be accomplished by applying caustic-free processes.3 These techniques involving ammonia injection and solidbed catalysts offer benefits in mercaptan oxidation process units.

Choosing the maximum caustic strength. When possible, the maximum caustic strength can be chosen to minimize water content, thereby reducing the dissolved organic contamination loads.

Multistage caustic wash. Two levels of scrubbing—first

with weak caustic followed by a strong one—offer improved utilization of caustic.7 The first level facilitates removal of most of the hydrogen sulfide (H2S), while the second level acts as a polishing step to achieve maximum removal efficiency. However, the additional investment costs must be weighed against the incremental caustic savings.

Non-dispersive mass transfer technique. Extraction of naphthenic acids into caustic is limited by the emulsion-forming tendency and precludes using higher-strength caustic in units where the dispersive caustic mixing is applied. Film-contact techniques can overcome these limitations and allow higher caustic strength, thus enabling savings in caustic usage and reduced spent caustic generation.

Maximizing the percentage. Spent caustic generation can

REUSE WITHIN THE FACILITY

be minimized by using up the caustic strength as much as possible while preventing breakthrough of acidic components in the hydrocarbon product. This can be determined based on analytical data and operating experience.

After reducing generation of spent caustic, the next step is identifying options for reusing it within the facility. Segregating spent caustic based on contaminants benefits this approach, since mixing dissimilar caustic effluents can render a blend that is unsuitable for reuse. The reuse potential of spent caustic is a function of its alkalinity, a measure of residual free NaOH and contaminants like sodium phenolate, Na2S and other sodium salts of weak acids. The high potential reuse applications are fresh caustic users. To optimize reuse application, it is essential to understand the process chemistry and operating conditions of the subject system, as well as the impact of the spent caustic contaminants on that system. Potential reuse applications include a substitute for fresh caustic usage:

Efficient regenerative systems. In many cases, amine treatment precedes the caustic wash. Ensuring efficient design/

Raw spent caustic

Coagulant Flocculant Skimmed oil/solids

Treated effluent

Flash mixing tank Flocculation tank

FIG. 2

Sludge

Clarifier

Flow diagram of a typical chemical treatment unit for spent caustic.

Neutralization of desalter fluids. The desalting process removes salt and other impurities such as bottom sediment and water from the crude oil before fractionation. Depending on the crude being processed, caustic is injected into the desalter to maintain optimum pH (normally 7–8) by neutralizing the acidity of the crude and to maximize de-emulsification. Dilute caustic solution, usually 2–3 wt%, is used to keep salt levels low and limit emulsification due to naphthenic acids present in the crude. Naphthenic spent caustic is not recommended, while the sulfidic stream is also not suitable for reuse due to lack of sufficient alkalinity. Conversely, phenolic spent caustic is effective as it neutralizes naphthenic acids to form phenols that dissolve back in the crude.

Crude-column corrosion control. Caustic is often injected

Oxidation tower Offgas Raw spent caustic

Separator

Heat exchanger Air blower

Treated effluent

FIG. 3

42

Flow diagram of a wet oxidation treatment unit.

I NOVEMBER 2011 HydrocarbonProcessing.com

into the crude-column feed to minimize corrosion resulting from hydrochloric acid (HCl) evolution due to the hydrolysis of calcium and magnesium chloride present in residual water droplets contained in the desalted crude oil. Phenolic spent caustic is effective here. Naphthenic spent caustic effluent can also be used since sodium naphthenates will react with the HCl. Remember: that reuse should be done in a controlled manner to avoid fluctuations in the sodium content.6 Lower levels cause the HCl release, resulting in overhead column corrosion; while higher levels increase sodium content in the residue, leading to caustic corrosion and catalytic deactivation in downstream processing units. Increasing the concentration of acidic contaminants in the products exdistillation is expected to be insignificant when spent caustic is used instead of fresh caustic.5

PLANT SAFETY AND ENVIRONMENT pH adjustment of desalter brine. If the desalter pH control cannot provide minimum alkalinity to outgoing brine, it can lead to corrosion of downstream valves and piping, requiring caustic injection on the brine line. Phenolic spent caustic is suitable.

SPECIALREPORT

proper cost-benefit analysis before proceeding further. Emerging techniques, such as membrane and electrolysis applications, show promising trends.

TREATMENT AND DISPOSAL

Internal reuse. In most mercaptan-oxidation processing units,

higher caustic strength (20°Be) is normally used in the extractor sections to favor mercaptan removal. A lower strength (10°Be) is used in the prewash operation due to lower solubility of Na2S. The spent caustic from the extractor unit is relatively free from sulfides and can be diluted and used in the prewash.1 Such regenerative processes are more effective in reducing spent caustic than the once-through processes.

Wastewater processing needs. Caustic is normally dosed upstream of the chemical and biological treatment units to sustain favorable pH conditions. Since phenols and napthenates are manageable at controlled concentrations in biotreatment, phenolic and naphthenic spent caustic streams are more suitable for reuse.

Sulfidic streams pose odor issues in this application.

Accordingly, phenolic spent caustic provides better reuse opportunities followed by naphthenic, while sulfidic streams offer relatively lesser avenues within the facility.

RECYCLE OUTSIDE THE FACILITY

Along with reuse options, recycling is another opportunity to explore for industries (where there are similar streams) and it has been successfully implemented by several refineries in the US and Canada.10 This approach may require additional treatment or conditioning within the facility, depending on the composition needs of the receiver. These applications may find roadblocks in terms of handling and transportation, in which case they can be sold to intermediate processors to handle them. Potential recycling opportunities include pulp and paper, tannery, mining, wood preservatives and paint industries.4 In-plant processing could be an option to extract the valuable content, especially the free caustic, sulfide salt, phenols and naphthenic acids. These can be used as feedstock for phenolic resins, herbicides, solvents, wood preservatives, paint and ink driers, fuel additives, etc.4 However, this approach may need a

Treatment for final disposal is the last option, but, unfortunately, an inevitable one in most cases. Efforts should be made to handle the spent caustics directly, in well-acclimatized biological treatment units, after diluting them with bulk effluents and maintaining homogenous feed meeting biotoxicity threshold limits (established by lab tests). Biotreatment is the most economical, and offers flexibility in operation. If treatment is necessary before routing it to biotreatment, many proven techniques are available.

Their suitability is case-specific as driven by factors such as quantity, composition and treatment limits to be achieved.

Treatment methods for spent caustic can be broadly categorized as “chemical” and “thermal,” with further categorization based on chemical(s) used and system operating conditions. If adequate treatment facilities are unavailable, third-party disposal should be worked out. These methods include: Chemical treatment—Oxidation (acidic/alkaline), precipitation, neutralization/acidification Service water makeup Combustion air Steam/fuel/waste gas Raw spent caustic

Stack

Combustion chamber Flue gas scrubber

Quenching chamber

FIG. 4

Venturi scrubber Treated effluent

Flow diagram of an incineration spent-caustic disposal unit.

TABLE 2. Application of treatment methods Treatment method

SSC

Application* PSC NSC

Chemical oxidation

9

8

8

Fenton oxidation

8

9

,

8

Chemical precipitation

9

8

8

,

Neutralization

8

9

9

,

LP wet oxidation

,

8

8

,

MP wet oxidation

9

9

8

,

HP wet oxidation

!

9

9

9

Catalytic wet oxidation

!

9

8

9

Incineration (thermal oxidation)

8

9

9

9

Biological oxidation

#

#

#

#

SSC PSC NSC MSC *

Sulfidic spent caustic Phenolic spent caustic Naphthenic spent caustic Mixed spent caustic Suggestive (not absolute), as it depends on case specific actual characteristics and site conditions

Vented air with offgas for supplementary aeration/treatment in bio-tower (trickling filter) bottom or to safe location

MSC ,

Anti-foam agent (if required)

Manual skimming provision

Copper catalyst solution (as needed) Raw spent caustic Air blower

Sprinklers for better contact

Bell mouth inlet

9 8 ! ,

Suitable Unsuitable Not “Applicable/Required” Potentially suitable depending on bio-system feed limits # If enough dilution (meeting biotoxicity limits) exists

Floating oil skimmer

Spent caustic storage/aeration tank FIG. 5

Recirculation Skimmed oil for reuse/ recycle as low-grade fuel oil/waste oil Oxidized/partially treated stream to biological treatment units

Flow diagram of an atmospheric treatment unit.

HYDROCARBON PROCESSING NOVEMBER 2011

I 43

SPECIALREPORT

PLANT SAFETY AND ENVIRONMENT

Thermal treatment—Wet oxidation (low-/medium-/highpressure), incineration Biological treatment—Oxidation (attached/suspended cells)—normally after pre-treatment.

Wet oxidation. This is a liquid-phase hydrothermal oxida-

tion using dissolved oxygen at elevated temperatures facilitated by air and supplementary steam injection. Oxidation efficiency increases with temperature; its operating range is set based on target contaminants (lower for inorganics and higher for organics). The oxidation needs are driven by downstream biotreatment limits. The operating pressure is governed by partial pressure of the oxygen to be maintained, and the methods are accordingly categorized as low-/medium-/high-pressure (LP/MP/HP) wet oxidation. Due to its high treatment efficiencies, no-sludge generation and minimal air pollution, this method is most widely used. It is one of US Environmental Protection Agency’s best available techniques (BATs).

Chemical oxidation. Hydrogen peroxide (H2O2) is a widely

used oxidant; its radicals possess very high oxidation potential. It can oxidize most inorganic and organic compounds, but the reaction rate toward sulfides is effective to apply it economically for smaller streams. Alkaline conditions are favored for complete conversion to sulfates. For organics removal, a Fenton reagent (peroxide with Fe+2 catalyst) application in an acidic medium is normally used.

Chemical precipitation. “Chlorinated copperas” is com-

monly used in an alkaline medium to remove sulfides as insoluble ferric sulfide with ferric hydroxide sludge. Due to its hygroscopic nature, it is normally produced in-situ using ferrous sulfate and chlorine. However, with the associated chemical and sludge handling issues, this method usage is receding.

Catalytic wet oxidation. This method involves a catalyst

application in wet oxidation units to reduce operating temperatures and to enhance oxidation efficiency.

Incineration. This is a gas-phase oxidation process at much

higher temperatures, converting inorganic constituents into molten forms and decomposing organic compounds into most stable states. It offers the ultimate oxidation levels. Diluted streams may not provide enough calorific value for self-sustaining hightemperature needs and normally require supplementary fuels. In a recent gas-cracker ethylene plant in Saudi Arabia, an improved incineration system using waste oil as fuel was installed; it addressed eutectic solid crystals formation in the quench section.

Neutralization/acidification. Neutralizing free caustic and

other alkalinity converts the spent caustic components into their original forms, i.e., H2S, RSH, phenol and naphthenic acids; thus allowing recovery of the valuable acid layer but requires stripping and further handling of volatile sour gases.

Spent caustic Source identification 1 Stream characterization Use within the facility

2

Use in other industry

3A

Third-party processors

3B

Source reduction

Yes Options

Chemical treatment

5B No

5B1

5B2

5B3

Saleable/ reusable as such?

No

Options

5B4

5A

5B5

Chem (H2O2) Fenton Chemical Neutralization Neutralization oxidation precipitation w/stripping w/o stripping oxidation 5B6

4

Further processing

6B

Third-party disposal

5

Treatment

Thermal treatment

5C

Meets biotoxicity threshold limits ?

No

Options

Yes

Options

Stream segregation

5C1

5C2

5C3

5C4

5C5

LP wet MP wet HP wet Catalytic Incineration oxidation oxidation oxidation oxidation

Bio treatment

5B7

5C6 5C7

6A Disposal Code 1 2 3A/B 4 5 5A 5B 5B1 5B2 5B3 5B4 5B5

FIG. 6

44

Description/rationale Reduce/eliminate waste at the source Reuse as substitute to fresh caustic Recycle to other industries/waste recyclers Recovery/reprocessing for value enhancement Treatment after 2/3/4 are fully explored Most preferred route of treatment Low flow and low concentrations (typically) Major pollutants are sulfides Major pollutants are phenols/other-organics Major pollutants are sulfides and H2O2 scarcity Major pollutants are organic acids + Sulfides; waste acidic streams available

Code 5C 5C1 5C2 5C3 5C4 5C5 5B6 5B7 5C6 5C7 6A 6B

Logic diagram for spent caustic management.

I NOVEMBER 2011 HydrocarbonProcessing.com

Description/rationale High flow or high concentrations (typically) Mostly sulfides; partial oxidation suffices Partial oxidation of organics suffices Complete oxidation required Complete oxidation w/moderate op. conditions Complete oxidation reqd.; waste fuels available Residual treatment required Quality comparable to biotreated effluent Residual treatment required Quality comparable to biotreated effluent Final disposal after treatment No in-plant treatment available

Biological oxidation. This comprises of pollutant decomposition and oxidation through bacterial adsorption, respiration and synthesis mechanisms. It produces additional bacterial cells, followed by clarification and stabilization. While feed homogeneity—ensuring pollutant levels below the acceptable limits (pH: 6.5–8.5, Oil < 25 ppm, sulfides < 10 ppm, phenols < 50–200 ppm, copper < 1 ppm, etc.)—is a basic prerequisite to the system, it can provide flexibility through proper acclimatization processes.

Table 2 summarizes the typical application/suitability of these techniques; further details including pros and cons are listed in Table 3. A logical approach is also presented in Fig. 6; it facilitates the total management. Research into this area has been producing more methods, mostly based on the same principles. But improvements through process/mechanical designs and some requiring establishment on a commercial scale are promising.

Only commonly used methods or those successfully implemented on full scale are covered in this analysis. Licensed technologies under each method are not the focus here, but their specific features and advantages can be established through techno-economic assessment during the selection process.

PLANT SAFETY AND ENVIRONMENT

SPECIALREPORT

TABLE 3. Commonly used techniques for spent caustic treatment—Pros and cons Treatment method and reactions involved

Operating conditions

Major needs

Merits

Demerits

Chemical oxidation

T: Amb.

• H2O2 injection

• Complete oxidation of sulfides

Na2S + 4H2O2 r Na2SO4 + 4H2O

P: Atm.

• H2O2 bulk inventory

• Low CAPEX

• High peroxide consumption (OPEX) • Its availability in proximity may be an issue

pH: 8–9 R: < 0.5 hr Fenton oxidation

T: Amb.

• H2O2 injection

• Oxidation of organics

C6H6O + 14H2O2 r 6CO2 + 17H2O

P: Atm.

• FeCl3 injection

• Low CAPEX

pH: 2–4

• H2O2 bulk inventory

• Handling of corrosive sulfuric acid

R: < 1 hr

• Generates chemical sludge

Catalyst: Iron Chemical precipitation

T: Amb.

• FeSO4 and Cl2 injection

• Complete removal of sulfides

3FeSO4 •7H2O + 1.5Cl2 r Fe2(SO4)3 + FeCl3•21H2O

P: Atm.

• FeSO4 bulk inventory

pH: 9–11

• Chlorine cylinders

• Also removes emulsified oil (EO) and TSS

R: < 1 hr

• Caustic injection

Fe2(SO4)3 + 3Na2S r Fe2S3 + 3Na2SO4 Fe2S3 (Hydrolysis) r 2FeS + S

• Above list + unsuitable for sulfides removal

• Sludge handling

FeCl3 + 3NaOH r Fe(OH)3 +3NaCl Neutralization

T: Amb.

• H2SO4 unjection

2NaOH + H2SO4 r Na2SO4 + 2H2O

P: Atm.

• H2SO4 bulk inventory

Na2S + H2SO4 r Na2SO4 + H2S

pH: 3–5

• Striping and sour gas

Na2CO3 + H2SO4 r Na2SO4 + CO2 + H2O

R: < 2 hr

• Need for in-situ generation of chemicals • High chemicals consumption

• Can be applied in existing flotation units

• Large chemical sludge generation

• Low CAPEX

• Occupation risk of chlorine gas leaks

• Recovers valuable phenol/ organic acids

• High CAPEX/OPEX for sulfides removal with add-on stripping and acid gas handling systems

• Handling of corrosive chemicals

• Handling of corrosive sulfuric acid

handling (for sulfides)

• Odor issues LP wet oxidation

T: ~100–120°C

• Air blowers

2Na2S + 2O2 + H2O r Na2S2O3 + 2NaOH

P: ~2–7 bar

• Steam supply

2NaSR +1⁄2O2 + H2O r RSSR + 2NaOH

R: 4–6 hr

• Cooling water supply

• Conversion of sulfides to Thio sulfates, reducing biotoxicity (IOD) • Plant air may meet air supply needs

• Partial oxidation; low BOD/COD reduction • Does not target organics; foaming potential • High CAPEX; requires offgas treatment

MP wet oxidation

T: ~200–220°C

• Air compressors

Na2S + 2O2 r Na2SO4

P: ~20–40 bar

• Steam supply

• Conversion of sulfides to sulfates

• Does not completely oxidize organics

2NaSR +1⁄2O2 + H2O r RSSR + 2NaOH

R: 2–4 hr

• Cooling water supply

• Partial oxidation of organics

• High CAPEX and OPEX; need off-gas treatment • MP steam needs, foaming potential

HP wet oxidation

T: ~240–260°C

• Air compressors

Na2S + 2O2r Na2SO4

P: ~45–70 bar

• Steam supply

NaSR +2O2 r NaHSO4 + CO2 + R’COONa

R: < 2 hr

• Cooling water supply

NaOOR + O2 r R’COONa + CO2 + H2O

• Nickel alloy materials

• Complete oxidation of sulfides/organics

T: ~150–240°C

• Air compressors

(Reactions similar to wet oxidation but catalyzed)

P: ~40–60 bar

• Steam supply

R: < 2 hr

• Cooling water supply

• Enhanced Thiosulfate oxidation

Incineration (thermal oxidation)

T: 920–950°C

• Air compressors

Na2S + 2O2 r Na2SO4

P: < 0.2 bar

• Fuel supply

C6H5OH +7O2 r 6CO2 + 3H2O

R: 2 sec

• Quench/cooling water

• Complete oxidation of sulfides and organics to sulfates and CO2 and H2O

• SS scrubbers/stack

• HP steam needs

• No further offgas handling required

Catalytic wet oxidation

2NaOH + CO2 r Na2CO3 + H2O

• High CAPEX and OPEX

• Same as wet oxidation but reduced T&P

• Can use waste oil/vent gases as fuels • May allow direct disposal

• High CAPEX and OPEX • Catalyst handling

• High OPEX, if fresh-grade fuels are used • Waste fuels may need special injector/atomizer • Eutectic salt (sulfates and carbonates) crystals formation need bulk and fine solids removal

LP/MP/HP: Low/medium/high-pressure; TSS: Total suspended solids; IOD: Immediate oxygen demand; T: Temperature, P: Pressure; Amb.: Ambient, Atm.: Atmosphere; R: Residence time; Equations containing R’ (typically CH3) are unbalanced; SS: Stainless steel; N&P: Nutrients, i.e., nitrogen and phosphorous—typically urea and di-ammonium phosphate (DAP) are used.

HYDROCARBON PROCESSING NOVEMBER 2011

I 45

SPECIALREPORT

PLANT SAFETY AND ENVIRONMENT

Potential for atmospheric treatment technique.

Beyond the analysis carried out for the widely used techniques and their suitability, the authors investigated the merits of exploring atmospheric aeration and recirculation within the spent caustic storage tank(s). Based on known and available information, this technique seems either not tried on a wider scale or not put to effective implementation as yet by the hydrocarbon industry. It is proposed to test the efficacy and results on a pilot scale first to establish its advantages and operational range. Being a nonchemical and non-thermal technique, it is expected to have merits including low costs and operational simplicity. The view is supported by available data for reaction kinetics, which favor an atmospheric sulfide oxidation rate of 0.3 kg/m3hr to 0.6 kg/m3hr at ambient temperature, requiring 18–85 hr (< 4 days).9 This seems attractive, as the storage inventory commonly seen for spent caustic effluents is about 7–15 days. It can easily be implemented in existing tank(s) with simpler metallurgy and low operational and maintenance needs.

Odor control. This is an important part of a total spent caustic management system. Odor control has potential adverse impact not only on occupational and community environment but also has stake in the public perception of the facility. The malodorous characteristic of the spent caustic is attributed to its constituents like H2S, mercaptans, disulfide, cresols and thiophenol with their volatile nature and extremely low threshold odor numbers (< 1 ppb). Several measures would help mitigate these objectionable odor issues: • Closing/covering all treatment units in spent caustic service • Avoiding routing directly to drainage sewers

Simplify your operations with Novozymes’ wastewater solutions

• Maintaining alkaline pH (9–10) in bulk stream it is mixed with, to avoid hydrolysis of Na2S to H2S • Ensuring there are no significant residual sulfides in spent caustic, before it is sent to biological treatment • Routing of vents from LP/MP wet oxidation and mercaptan oxidation units to offgas treatment.

Control review. Selection of a suitable technique to handle

spent caustic is a critical task involving technical, economic, environmental, health and regulatory considerations. Source reduction and segregation, followed by reuse/recycle, have the potential to reduce the volume to be treated. The volume reduction aids in selecting the most appropriate method specific to its characteristics. All these can be made possible by following a logical approach built on waste-management hierarchy principles. HP ACKNOWLEDGMENTS Authors express sincere gratitude to KBR Management for their support and encouragement in bringing out this work. This is an updated version of a presentation at the International Refining and Petrochemical Conference-Asia, July 19–22, 2011, in Singapore.

LITERATURE CITED Dando, D. A., and D. E. Martin, “A guide for reduction and disposal of waste from oil refineries and marketing installations,” CONCAWE Report No. 6/03, 2003.

2 Veerabhadraiah. G., and A. Haldar, “Aiming towards Pollution Prevention and Zero Discharge in Petroleum Industry”, Proceedings of AIChE Spring Conference, Atlanta, 2000.

3 US Dept. of Energy, “Energy and Environmental Profile of the US Petroleum Refining Industry,” 2007.

4 API, “Category Assessment Document for Acids and Caustics from Petroleum Refining”, US EPA, 2009.

5 Sarkar, G. N., “Utilization of the Spent Caustics Generated in the Petroleum Refineries in the Crude Distillation Unit”, 5th Intl. Conference on Stability and Handling of Liquid Fuels, The Netherlands, 1994.

Complete literature cited available at HydrocarbonProcessing.com.

1

G. Veerabhadraiah is lead environmental engineer for KBR,

Novozymes provides cost-effective solutions for improving biological treatment.

Key benefits include: s Increased throughput of high-strength waste material s Improved treatment during turnarounds s Improved settling s Stabilized nitrification s Reduced toxicity

For more information on Novozymes’ bioaugmentation products or to place an order: Web: www.novozymes.com/wastewatersolutions Tel: 1-800-859-2972 E-mail: wastewater@novozymes.com

Select 162 at www.HydrocarbonProcessing.com/RS 46

Singapore. He earned a B. Tech in chemical engineering from Andhra University, India, and a Masters in HSE Technology from National University of Singapore. He has over 19 years experience in the hydrocarbon industry and specialized in environmental engineering activities of project conceptualization, design and execution. Previous to KBR, he worked with Engineers India Ltd., New Delhi. He has publications in various International Conferences and is recipient of ‘Best Research Work’ Award from ‘Central Pollution Control Board’ of Government of India.

N. Mallika is principal process engineer for KBR, Singapore. She obtained graduation in chemical engineering from Amravati University, India, and worked for more than 18 years in the chemical and oil and gas industry, mainly in refining, petrochemical and gas processing facilities. Her experience includes process simulation, basic design, detailed engineering, pre-commissioning and commissioning support, and she has worked extensively on licensed processes for various refining units. Previous to KBR, she worked with Engineers India Ltd., New Delhi.

S. Jindal is process and environmental discipline manager for KBR, Singapore. He has also held positions of lead process engineer and proposals engineer in a career spanning more than 20 years in the HPI. He previously worked with Aker Kvaerner, Larsen & Toubro, and Engineers India Ltd. in senior technical positions. He has authored technical papers on varied topics at international conferences. He received a B. Tech degree in chemical engineering from the Indian Institute of Technology, Mumbai, and is a AICHE member.

PLANT SAFETY AND ENVIRONMENT

SPECIALREPORT

Automated decoking solves coker safety challenges The concept improves safety and efficiency and bolsters the bottom line I. BOTROS, Flowserve Corp., Irving, Texas

S

afe, efficient operation of hydraulic decoking equipment is critical to the financial success of the entire refinery.

Refineries report that a coker unit outage can cost up to US $1 million per day, while the financial impact of an accident in the delayed coking unit can be in the tens of millions of dollars.

Improving safety and performance are the mutual objectives of refiners and equipment manufacturers. One way to achieve better safety is through fully automated decoking. This is now possible with an integrated, intelligent technology platform coupled with a programmable logic controller (PLC). The benefits of remote and automated coke cutting are: • Improved safety of cutting personnel • Process efficiency and consistency • Improved reliability of equipment • Data recording for process optimization and troubleshooting.

Remote cutting. Improving safety

is the mutual objective of refiners and equipment manufacturers. One sure way to achieve this goal within the DCU is by removing the operator from the cutting deck. Traditional decoking combination tools require extensive handling by an operator to manually shift cutting modes (Fig. 1). This is a cumbersome and hazardous operation exposing cutting deck personnel to: • High-pressure water discharge • Hot spots or steam eruptions • Hydrogen sulfide (H2S) vapors • Mechanical hazards, including heights and high winds.

A combination cutting tool eliminates these dangers and reduces cycle time by shifting modes automatically and remotely inside the drum through water pressurization and depressurization (Fig. 2). The abil-

ity to remotely shift operating modes means operating personnel do not need to be on the cutting deck, risking exposure to the aforementioned hazards. Also, the time savings positively impact the production capacity of the refinery by reducing the decoking cycle times by 20 to 30 minutes and allowing the drum to be available for the next cycle.

In the event of cave-ins or slumped bed conditions, the remotely operated autoshifting combination tool provides the flexibility to remove a “stuck” tool quickly and efficiently. Shifting between modes is accomplished by switching the decoking control valve into the bypass position or, in the case of variable speed driven pumps, by slowing the pump to idle speed and then re-accelerating to rated speed.

For successful remote operation and safety in coke cutting operations, several other best-in-class equipment and information solutions are needed, including: • A remotely operated winch and rotary joint • Remote drum unheading capability • Automatic guide plate and tool enclosure

• Drum vibration monitors to determine tool position and cutting progress • Cutting equipment sensors to monitor tool rotational speed, wire rope system tension, etc.

• Interlocked safety systems for cutting water flow control • Data monitoring, transmission and control systems within an integrated technology platform • A remote operator enclosure with a master control panel • Video and acoustic equipment to observe cutting deck activities, as well as coke chute and pit status (Fig. 3).

The key element to improve coke cutting efficiency is gaining precise knowledge of the auto-shifting combination tool’s position, both inside the drum and after the coke has been removed. Coke drum monitoring instrumentation provides coke cutting personnel positive confirmation of both these conditions so the decoking process can continue.

Four vibration monitoring devices are permanently mounted at equally spaced intervals on the outer drum wall with another

FIG. 2 FIG. 1

Traditional decoking combination tools require extensive handling by an operator.

The autoshift tool eliminates dangers and reduces cycle time by shifting modes automatically and remotely inside the drum.

HYDROCARBON PROCESSING NOVEMBER 2011

I 47

SPECIALREPORT

PLANT SAFETY AND ENVIRONMENT

on the coke chute. Permanent mounting allows for a high signal-to-noise ratio to provide a more accurate readout (Fig. 4).

As the coke is removed from the drum, the high-temperature accelerometers monitor the vibrations on the coke drum wall and relay the information to a data collection device. The signals are processed and the tool location and coke cutting status are displayed on a video screen where the operator can clearly see if the section of the drum being cut has been cleaned.

This feature also reduces cycle time, as the tool is automatically advanced as soon as a section is cut, rather than stopping while the operator takes time to ensure a clean section. The four sensors mounted on the drum give the operator feedback at each level of cutting. The chute sensor provides information on coke exiting the bottom of the drum and is a necessary asset for safe operation in low-visibility and remote cutting operations.

In addition to the vibration sensors, feedback on cutting progress is enhanced by an audio and video system designed to help the operator determine when the section of the drum is clean. As the coke is removed from the drum, the sound of the impinging water changes, allowing the operator aural recognition of a clean section

FIG. 3

Looking behind the curtain of hydraulic decoking system process evolutions.

FIG. 4

Coke drum monitoring and vibration systems.

48

I NOVEMBER 2011 HydrocarbonProcessing.com

(Fig. 5). Simultaneously, a video monitoring system allows the operator to view the coke chute, thereby alerting the operator when no more coke is being removed.

This positive feedback enables the operator to advance the cutting tool at the earliest opportunity, reducing the total time needed to clean the drum and eliminating some of the guesswork currently associated with coke cutting. The coke drum monitoring system is completely integrated into the decoking control system’s master control panel. The operator display provides real-time feedback on drum cleanliness and cutting status.

One master control panel can be designed to operate the decoking equipment for each pair of drums in the DCU. The panel is designed to control and monitor: • Drum selection and in-drum indication • Crosshead latch/unlatch status • Winch and rotary joint speed control and position indication • Decoking valve position and valve condition • Cutting water pressure and pump condition • Cable tension indication • In-drum cutting progress.

Additionally, safety interlocks and emergency shutdowns are integrated for cutting, water system flow control and for the unheading devices.

Automated decoking takes remote cutting to this ultimate step by capitalizing on the advanced monitoring, diagnostic, control and instrumentation capabilities of an integrated, intelligent technology platform coupled with a PLC. DCU operators can now custom design and install the requisite computer software and algorithms, instrumentation and embedded intelligence to automatically operate the hydraulic decoking system while protecting it from unanticipated downtime. Moreover, a single operator can monitor the entire process in safety— away from the cutting deck.

An integrated technology platform makes the benefits of data acquisition, diagnostics and intelligent control more accessible to DCU operators. It helps lower life cycle costs by delivering actionable information to optimize process control and equipment operation. High-speed data acquisition of dynamic sensor signals along with the convergence of multiple data streams into embedded diagnostic and control algorithms makes this possible.

PLANT SAFETY AND ENVIRONMENT Among the benefits of an integrated, intelligent technology platform are: • Continuous, highly accurate sensor signal condition monitoring and data logging in realtime • Reliable detection and diagnostics to identify mechanical and hydraulic anomalies • Intelligent control through automated control capabilities to adjust equipment and system parameters • Data visualization through a shared information portal providing access to performance history, exception notification, reporting, etc. (Fig. 7) • Seamless integration into distributive control and equipment health management systems • Protection from high-risk process conditions with equipment-specific software to help operators proactively diagnose and manage unique, as well as common, operating problems.

The practical application of an integrated, intelligent technology platform is nearly limitless. For example, by applying onboard sensors to critical system components such as the hydraulic decoking jet pump and decoking control valve, the DCU operator is able to realize significant uptime improvements by actively monitoring for process and equipment problems that may lead to unscheduled downtime and reduced production. Using data acquisition tools and the shared information portal, experts from around the world— including the supplier’s DCU specialists and hydraulics engineers—can monitor, diagnose and communicate necessary solutions and recommend actions to increase unit uptime (Fig. 8).

There are two approaches to automated decoking. The first is called preprogrammed cutting, a semi-automated system in which an operator interface is required. This approach is a programmed cutting operation with a fixed sequence, but there is no feedback signal about the cutting progress. The program is customized based upon the established best practices of the unit’s operators. The basic parameters include vertical cutting position increments, dwell time and rotary joint speed control.

The second approach is a fully automated system featuring cutting control and continuous feedback signals for equipment and drum status. It includes embedded intelligence to process signals for monitoring and control, whereby operator interface is only required for sequence exceptions. Operator safety is further improved

by integrating an automated cutting system with a PLC interlock.

The benefits of automated decoking with fully integrated, intelligent monitoring control systems and access to a management portal are impressive: improved safety, more efficient process cycles, greater equipment and system reliability and higher operating profit.

More specifically, these benefits include: • Improved cutting personnel safety as an automated cutting system with PLC interlocks minimizes the possibility of operator mistakes and eliminates operator “shortcuts.” Standardized cutting procedures also reduce the risk of aggressive cutting practices.

SPECIALREPORT

• Process efficiency and consistency are achieved since the cutting program advances as soon as possible with consistent cutting times and standardized cutting procedures.

• Improved equipment reliability as continuous equipment condition monitoring results in predictive maintenance for the jet pump and other critical decoking equipment. Damage from aggressive or improper cutting techniques (example: ramming the tool into the coke bed during boring operation) can be eliminated.

• Data recording for process optimization/troubleshooting is collected continuously. When properly analyzed, this data can be used to optimize cycle times, trouble-

FIG. 5

As the coke is removed from the drum, the sound of the impinging water changes, allowing the operator aural recognition of a clean section.

FIG. 6

A video monitoring system allows the operator to view the coke chute.

HYDROCARBON PROCESSING NOVEMBER 2011

I 49

SPECIALREPORT

PLANT SAFETY AND ENVIRONMENT shoot and avoid failure events, and monitor performance for predictive maintenance.

Safety improves via automation.

Largely made possible by the auto-shift-

FIG. 7

An integrated technology platform provides a complete solution for intelligent monitoring, visualization and anomaly control.

FIG. 8

Panel view display.

Remote coke cutting To move the operator from the cutting deck to a remote location, the following is required: Equipment • Remotely operated, auto-shifting combination cutting tool • Automatic guide plate or tool enclosure • Remote winch and rotary joint operation • Vibration/acoustical devices • Video equipment • Remote operator enclosure Information Data sent remotely to operator: • Cutting tool position and rotational speed • Cable tension and auto-shifting combination cutting tool mode • Drum status • Video feedback for pit, winch and top of drum.

Automated coke cutting Fully automated decoking is achieved through a PLC with embedded intelligence and advanced algorithms to process signals and control the cutting process. Continuous feedback is provided. Operator action is only required for sequence exceptions.

Equipment • Remotely operated, auto-shifting combination cutting tool • Automatic guide plate or tool enclosure • Remote winch and rotary joint operation • Vibration drum monitoring • Remote operator enclosure Information • Data received by PLC and transferred to integrated, intelligent technology platform – Cutting tool position and rotational speed 50

I NOVEMBER 2011 HydrocarbonProcessing.com

ing combination cutting tool, remote coke cutting provides greatly improved safety by removing the operator from the cutting deck. Automation through an integrated technology platform further improves DCU operational efficiency and process consistency. Intelligent monitoring and control systems assist in process optimization, improved equipment reliability and maximum DCU availability.

The ultimate result is safer, faster and more efficient coke cutting. HP

Ihab Botros currently serves as director of global special products for Flowserve Corp. and has global responsibility for the Flowserve special products portfolio, including hydraulic decoking systems, multiphase pumps, reciprocating pumps, subsea pumps, high energy barrels and ebullated bed reactor recycle pumps. Mr. Botros earned his bachelor of science degree in mechanical engineering from Alexandria University as well as a masters degree in mechanical engineering from California State University in Long Beach.

– Cable tension and auto-shifting combination cutting tool mode • Data received directly by integrated, intelligent technology platform – Drum status – Critical equipment monitoring.

The shared-information portal can make a critical difference A powerful platform of information technology and sensorbased solutions can streamline the collection, storage, interpretation and use of essential process and equipment data. This data can be acquired and integrated with the DCU operator’s existing data management systems or displayed on a local PC or laptop.

With a shared-information portal, this data/information aggregation system enables plant managers and unit operators to: • View ongoing performance metrics through interpreted visuals • Monitor real-time equipment performance • Review historical equipment information Users can also: • Quickly diagnose and solve equipment performance issues from anywhere in the world via the secure remote login capability • Consult with corporate staff, industry experts and supplier specialists in real-time to analyze anomalies and provide immediate corrective recommendations • Benchmark asset performance against industry averages • Create a centralized view of plant asset information regardless of source. This view may include: – Installation and operation information – Bill of material data including drawings – Historical data including parts usage, upgrade and maintenance records. HP

presents

HPI MARKET DATA 2012 NOW AVAILABLE! Hydrocarbon Processing’s industry-leading forecast of HPI spending and activity is now available. With accurate, reliable information from governments and private organizations, the HPI Market Data 2012 book is one of the most valuable tools available to global HPI decisionmakers today. Hydrocarbon Processing’s editors forecast total spending in the HPI to exceed $222 billion in 2012. The HPI Market Data 2012 book provides exclusive information detailing where and how this spending will take place, and how expenditures will be affected by various economic, political and environmental factors. Also included in the 2012 edition are: • In-depth analysis of the predicted $222 billion total spending within the HPI, broken out by geographic location • A closer look at the worldwide economic, social and political trends driving HPI activity across all sectors • Detailed forecast breakdowns for capital, maintenance and operating expenditures in the areas of Refining, Natural Gas/LNG, Petrochemicals, Health/Safety/Environment and Maintenance/Equipment

In the next year, capital spending is forecast to exceed $56 billion; maintenance spending, $65 billion; and operating expenditures, $99.9 billion. In today’s competitive global HPI, the ability to recognize ways to capitalize on new opportunities and trends is more important than ever. The 2012 edition of the HPI Market Data book contains over 96 pages of data, tables, figures and editorial analysis— the largest forecast to date.

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NEW TO THE HPI MARKET DATA 2012 Hereâ&#x20AC;&#x2122;s what is new in the 2012 edition: â&#x20AC;˘ Expanded editorial analysis of worldwide HPI trends, including case studies on Japanâ&#x20AC;&#x2122;s industry status post-natural disaster and the political climateâ&#x20AC;&#x2122;s effect on energy in North Africa and the Middle East â&#x20AC;˘ An exploration of the changing markets and demands within the global HPI, with discussion of activity in China and India â&#x20AC;˘ Included Bonus CD containing practical data from the Hydrocarbon Processing Construction Boxscore Database Hydrocarbon Processing has produced an HPI Market Data book for more than 35 years. HPI leaders, executives and decision-makers throughout the world have come to rely upon this analysis and data for valuable strategizing information. More than 120 detailed tables and figures appear in the HPI Market Data 2012 book. The data analyzed is broken down by factors like geographic region, year(s), demand and activity level.

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REFINING

â&#x20AC;&#x153;Those that fail to learn from history, are doomed to repeat it.â&#x20AC;? â&#x20AC;&#x201D;Winston Churchill

Although the 2008 recession is over, the recovery still continues. The total worldwide economic health has greatly improved from the depths of 2009 according to the World Bank. Depending on where you live, the level of recovery is another factor.

OECD nations Developed economies of North America and Europe still struggle to bounce back to pre-2008 levels. These economies fell harder than developing nations; thus, it is more complicated for the recovery.

Non-OECD nations These nations are the engines of growth in the global HPI. Economic activity is strongly linked to manufacturing capacity and energy consumption. A change in economic growth is shifting demand centers for energy, especially crude oil and natural gas. Developing nations now account for over 47% of global crude oil demand, up from 25% in 1970.

Constant ďŹ&#x201A;ux Changes in demand centers constantly update the location and concentration of new reďŹ ning capacity. ReďŹ ning capacity has always kept pace with demand. In some years, new capacity additions over shot demand, creating periods of excess supply. During such periods, utilization rates declined until corrections in demand or rationalization of unproductive reďŹ ning capacity occurred.

As shown in Figs. 1 and 2 and Table 1, demand for crude oil since 2005 to the present has hovered around 86 million bpd. Many

Anyone involved in the hydrocarbon processing industry (HPI) over the past few decades can fully understand what Winston Churchill was referencing. The global HPI continues to evolve and to learn from recent history. This industry is dynamic and very diverse.

Early crude oil reďŹ ning efforts focused on the lighter fraction of the barrel. The heavy ends were discarded because no one had discovered how to transform this high boiling point mixture of hydrocarbons into a useful product. The mid-19th century was a coal-oriented era. Only the middle fraction of the crude barrel was separated and used for lighting, heat and lubrication. Lubricating oil was more effective than animal fat in managing friction for machinery. Kerosine saved the whales; this hydrocarbon fraction replaced whale oil for lamps. By 1859, parafďŹ n was discovered and actively extracted for candle making.

factors contributed to this condition. Much of it is the stabilization fac and in some cases, demand destruction in the US, Japan and Europe. and, At the same time, the economies for developing nations began to tak off. Asia-PaciďŹ c economies continue to expand and increase take ene energy demand. China and India account for nearly two-thirds of the energy consumption by non-OECD nations (Table 1). The em emerging middle class are now consumers of petrochemical-based pro products, especially vehicles, motorcycles and trucks. This new middle cla is creating a strong domestic market for transportation fuels. class Dev Developing manufacturing centers, likewise, are consumers of energy and transportation fuels to move goods to consumers. Accordingly, fut reďŹ ning capacity expansions will be located, or directed, to fulďŹ ll future this growing energy demand.

â&#x20AC;&#x153;The only thing constant is change.â&#x20AC;? â&#x20AC;&#x201D;Francois de La Rochefoucauld Kerosine was the new â&#x20AC;&#x153;lightâ&#x20AC;? brieďŹ&#x201A;y for 30 years. In 1879, the incandescent electric light bulb would soon replace oil lamps and illuminate the world. Again, change would usher in another opportunity for reďŹ ned crude oil products. In 1885, Daimler built the ďŹ rst successful motorcycle, and Benz produced the ďŹ rst successful motorcar. Eleven years later, Henry Ford designed the ďŹ rst gasoline powered vehicle.

By 1908, Ford had developed the assembly line to mass produce automobiles, thus greatly reducing unit cost. Fordâ&#x20AC;&#x2122;s model T soon changed how goods and people were transported. As they say, the rest is history. As motor vehicles became more popular, the demand for transportation fuels followed. Transportation fuels and reďŹ ned products became a global industry thanks to the efforts of Royal Dutch Shell Oil Co., British Petroleum and others.

World War I ushered in the conversion from horse drawn to mechanical transport in the US. World War II (WWII) increased demand for transportation/aviation fuels along with major improvements in fuel qualities. New engines required better quality fuels. Europe became more motorized following WWII. Likewise, the modern petrochemical industry rose out of the innovation and need to replace natural products with synthetic ďŹ bers and compounds. In 100 years, crude oil displaced coal as the hydrocarbon of choice for products, transportation fuels, plastics, etc.

Change continues as HPI products improve the quality of life and expand the standard of living of the global community. In looking ahead, more challenges confront the global HPI. Three trends will reshape the global HPI: s .EW DEMAND PATTERNS s #HANGING TRADE PATTERNS s 3USTAINABILITY AND ENVIRONMENTAL REGULATIONS DIRECTIVES HPI companies are most adept in utilizing technology to resolve problems. However, the new challenges for the HPI are not technology based. Social, political and natural disasters are more difďŹ cult problems and, too often, they require very different solutions. Three very different challenges have altered conditions and markets for the global HPI in 2011, and they continue to impact the 2012 environment.

NEW REFINING CAPACITY N There are approximately 650 reďŹ neries with a combined processing cap capacity of 85 MMbpd in operation worldwide. They vary in complexity, as well as in size. About 83 MMbpsd of capacity is the traditional crude oil feedstocks, and 2 MMbpsd of capacity is based on unconventional fee Margins are sustained by unique combinations of complexity feeds. and capacity. ProďŹ tability is determined by the feedstock processed, as well as the ďŹ nished products produced. Changes in future crude oil characteristics, price and availability will impact operations and pro proďŹ tability of present and future reďŹ ning capacity additions.

Global oil demand changes, chan 2008â&#x20AC;&#x201C;2011 thousand and bpd b FSO Europe Europ urop rop o op North America 2008 2009 2010 -1,300 -900 516

2011 -207

2012 0

Latin America 2008 2009 300 0

2010 300

2008 2009 0 -730

22010 201 010 100 -100 -10 000

2011 2012 -150 -370

2008 2009 0 -200

2010 2011 2012 290 120 100

M Middle East 00099 2008 2009 9 400 290

2010 280

2011 2012 200 270

2011 2012 220 245

Asia-PaciďŹ c 2008 2009 2010 2011 2012 -200 100 1,460 960 780

A Africa 009 00 2008 2009 0 500

2010 2011 2012 50 40 125

Source: Hydrocarbon Processing

ENERGY TRENDS GDP projections lowered When 2011 began, the expectation was for most global economies to continue a steady trajectory of growth. For the energy industry, growth in most sectors was actually higher than expected in 2010, leading to projections of a sustained recovery.

But the early part of 2011 was marred by constant worries over political turmoil in the Middle East. By mid-2011, worries escalated on the back of economic troubles in developed areas such as the US and Europe. Stock markets tanked as reports showed softening consumer spending, rising debt and stubbornly high unemployment ďŹ gures.

Crude prices plunged about $20/bbl as worries persisted about overall demand for commodities.

On a global market exchange rate basis, gross domestic product (GDP) should grow by 3.5% in 2012, 3.6% in 2013 and 3.6% in 2014, according to the latest forecast from the American Chemistry Council (ACC). This can be seen in Table 1. Figures were down from prior ACC projections, and all were below the 3.9% growth registered in 2010â&#x20AC;&#x201D;at one point thought to be the beginning of a sharp recovery! â&#x20AC;&#x153;Sharply higher commodity prices and temporary supply chain disruptions from the disaster in Japan have slowed growth,â&#x20AC;? said ACC chief economist Kevin Swift.

Indeed, producers appeared to raise prices at a rate too high to keep up with ďŹ&#x201A;agging post-recession demand. And even though some rebound is forecast in late 2011, Swift warned that the recovery remains quite fragile. â&#x20AC;&#x153;Multiple risks remain, and the wrong trade, tax or other policy initiatives could derail activity,â&#x20AC;? Swift said.

The US is expected to lag overall economic growth, with projected GDP growth ďŹ gures of 2.9% or 3.0% for each year between 2012 and 2014. â&#x20AC;&#x153;With strong headwinds facing the US economy, domestic demand is expected to be soft,â&#x20AC;? Swift said.

Meanwhile, the story for UK and Eurozone countries is even worse, with average GDP growth of around 2% for each of the next three years.

On the other hand, the majority of the economic bright spots continue to be found in the Asia-PaciďŹ c region. China and India should each average nearly 9% year-on-year GDP growth from the

Table 1. Projected GDP growth, change Y/Y Overall US UK Eurozone

2011

2012

2013

2014

3.2

3.5

3.6

3.6

2.5

2.9

3.0

1.5

2.1

2.4

1.8

1.7

1.8

Japan

â&#x20AC;&#x201C;0.3

3.0

1.8

China

9.3

8.9

8.8

3.0 2.4 1.9 1.5 8.7

India

8.2

8.3

9.0

8.4

Brazil

4.3

4.8

4.7

4.7

Source: American Chemistry Council

HPI MARKET DATA 2012 5

FIG. 1 Global oil demand changes by regions, 2008â&#x20AC;&#x201C;2012.

HPI MARKET DATA 2012 21

PLANT SAFETY AND ENVIRONMENT

SPECIALREPORT

Pilot-operated safety relief valves: A simple, effective plant upgrade Replacing spring-loaded valves can be an important step in the quest to increase efficiency and output J. R. SCOTT, GE Energy, Houston, Texas; and N. MacKINNON, GE Energy, London, UK

A

never-ending quest for plant operators is how to wring more output from the existing infrastructure and budget without compromising safety or product quality. The challenge is daunting, but a relatively simple upgrade can help plant operators take a big step toward meeting it.

The replacement of direct spring-operated pressure relief valves (PRVs) with pilot-operated safety relief valves (POSRVs) can help plant operators streamline maintenance processes, reduce maintenance costs, address common valve performance issues, maintain safety and potentially increase output.

This article explains how valve replacement can be beneficial.

It also clarifies some common misconceptions about POSRVs and identifies factors that should be considered when specifying pilot-operated safety relief valves.

GREATER EFFICIENCY AND INCREASED THROUGHPUT

A POSRV relieves an overpressure situation by actuating a pilot valve that is plumbed to a main valve. The pilot valve opens and closes the main valve in response to system pressure, and all of the relieving capacity flows through the main valve.

The pilot valve receives vessel pressure through a sensing line attached at a point below the seating surface of the main valve or at a point directly on the vessel. The pressure travels through the pilot and pressurizes the dome. The surface area of the dome is greater than the seating surface, which is the area under the disc.

Since Force = Pressure ⫻ Area (F = P ⫻ A), the force pushing down on the main disc is greater than the force pushing up. With a POSRV, as system pressure increases, seat tightness also increases.

By contrast, the seating forces of a direct spring-operated valve are essentially a simple force to close (spring) against a force to open (system pressure). This difference means that the pilot valve has greater seat tightness at higher system operating pressures.

Since the pilot and main valves work together to protect the system, the system operating pressure can be closer to the valve’s set pressure than what is possible with a spring-loaded valve; 98% of set pressure is possible while staying within American Society of Mechanical Engineers (ASME) guidelines, vs. 90% of set pressure with a spring-loaded valve. Operating closer to set pressure allows plant personnel to maximize system efficiency while maintaining safety and reducing loss of product through seat leakage. As shown in Table 1, a POSRV’s set pressure can be higher than that of a comparable spring-loaded valve, helping increase throughput.

VERSATILE PROBLEM-SOLVERS

POSRVs are powerful problem-solvers and can help system designers overcome a variety of challenges commonly faced in hydrocarbon processing facilities. They are particularly appropriate choices for applications that include the following attributes.

Involvement of costly fluids. These fluids could include liquid natural gas (LNG), gasoline or another end product; or lubricants, cleansers or other additives used in the production process. The greater seat tightness delivered by POSRVs reduces the potential for these valuable fluids to be lost to leakage.

Presence of dangerous fluids. Such fluids create a potential breathing or explosion hazard. Again, seat tightness is the key. By reducing the potential for leaks, POSRVs help ensure safety by preventing these fluids from being released into the atmosphere.

Concern over fugitive emissions. Increasingly strict regulatory guidelines have made controlling fugitive emissions a major focus for plant operators. Leaking valves are one of the leading causes of fugitive emissions.

Direct spring-operated valves operate at something akin to a low boil. As system pressure begins to approach the valve’s set point, the valve will start to simmer as the disc gently rides on top of the valve seat. Although this is how the valve is intended to operate, the fugitive emissions caused by this slight leakage may not be acceptable in some applications. A POSRV’s tighter seal eliminates the simmering.

Existence of significant back pressure. It is, of course, common in hydrocarbon processing facilities for a PRV to exit into a header system where multiple valves are piped together. A prime example of this setup is a valve that is vented to a flare. This configuration will create superimposed variable back pressure when a valve relieves and generates pressure in the shared outlet pipe.

TABLE 1. Set pressure comparison: POSRVs vs. springloaded safety relief valves Valve size, in. (cm)

Nominal orifice area, in.2 (cm2)

Set pressure, psig (barg) Spring-loaded safety relief valve POSRV

3K4 (8K10)

1.838 (11.8)

2,220 (153)

6,250 (431)

4P6 (10P15)

6.38 (41.2)

1,000 (69)

3,750 (259)

6R8 (15R20)

16.00 (103)

300 (21)

1,500 (103)

8T10 (20T25)

26.00 (168)

300 (21)

1,500 (103)

8FB10 (20FB25)

38.96 (251)

N/A

1,500 (103)

HYDROCARBON PROCESSING NOVEMBER 2011

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SPECIALREPORT

PLANT SAFETY AND ENVIRONMENT

Typically, the solution has been to use a direct spring-operated bellows valve.

POSRVs are an ideal alternative to direct spring-operated bellows valves since a POSRV’s set pressure does not increase with the addition of back pressure (provided that the pilot is balanced against the effects of back pressure). Valve stability is greater with a POSRV because the back pressure cannot act on the back side of the disc to hold the valve closed. As a result, POSRVs are suitable for use in applications with 60–65% variable back pressure.

In some applications, POSRVs may be used with back pressures up to or exceeding 80%.

A POSRV can also be a more cost-effective choice in these applications. Although the up-front cost of a spring-loaded valve may be lower, bellows are relatively fragile and are generally costly

FIG. 1

This piping configuration has a pressure drop, potentially greater than 3%. Note: Valve piping and vessel not to scale.

Attention P I P E S Y S users

to replace when damaged, potentially creating lead-time issues during shutdowns and resulting in higher life-cycle costs.

High pressure drop exists. A variety of maintenance and construction considerations can lead plant designers to create facilities that have piping with multiple bends, narrow pipes or long runs of piping. High inlet pressure drops can result, causing a direct spring-operated valve to chatter or flutter and leaving the system at risk. However, a POSRV with remote sensing will protect the system without the need to re-pipe. Placing the sensing line in an area of the vessel that is unaffected by pressure drop allows accurate operation of the main valve (Figs. 1 and 2). The American Petroleum Institute (API) and ASME Section VIII Appendix M recommend a maximum inlet pressure drop of 3% of set pressure.

One application in which these high pressure fluctuations are commonly found is a reciprocating compressor in a refinery.

When operating at high capacity, these compressors have a tendency to surge, creating pressure variations that can cause a direct spring-operated PRV to chatter. A POSRV, on the other hand, will not chatter under these conditions.

Size and weight are major considerations. POSRVs are much more compact than their spring-loaded equivalents, allowing them to be used in tighter quarters and making installation and maintenance more convenient. POSRVs also weigh considerably less than direct spring-operated valves, reducing the number of piping supports required and making installation and maintenance easier. Consider, for example, the weight savings that can be achieved by replacing the following common spring-loaded valves with POSRVs: • 3-in. inlet and 4-in. outlet: up to 42%

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PLANT SAFETY AND ENVIRONMENT • 2-in. inlet and 3-in. outlet: up to 33% • 1.5-in. inlet and 2-in. outlet: up to 36%.

COMMON MISCONCEPTIONS ABOUT POSRVs

Regardless of POSRVs’ problem-solving abilities and attractive characteristics, several common misconceptions lead some plant operators to shy away from specifying POSRVs. Some of these misconceptions are based on simple misunderstandings, and others are based on operators’ experiences using traditionally accepted POSRV technology.

Misconception 1: Pilots cost more. It is true that the

sticker price of a POSRV is typically higher than that of a comparable direct spring-operated valve. POSRVs can, however, help plant operators reduce their overall investment in PRVs and increase plant uptime, for the following reasons: • Fewer valves may be required. A hydrocarbon processing facility may experience a variety of overpressure scenarios. Multiple direct spring-operated valves, each with a different relieving capacity, would be required to accommodate all of these situations. A single proportional lift-modulating POSRV, on the other hand, will adjust to and accommodate all overpressure situations, eliminating the need to install and maintain multiple valves.

• POSRVs are easier to maintain than direct spring-operated valves, resulting in a lower life-cycle cost and increased plant uptime. Maintaining a direct spring-operated valve is an extremely labor-intensive and time-consuming process that involves pulling the valve from service, lapping and polishing the seat, re-machining the nozzle and sometimes replacing the disc. This process can span several hours for a single valve, multiplied by the high number of valves that are found in a typical hydrocarbon processing facility.

In today’s world of shortened and highly time-sensitive plant turnarounds, the time for extended valve maintenance does not exist.

Maintaining a POSRV is a far easier process. The valve is simply pulled from service, the O-rings and seals are replaced, and then the valve is brought back online. Eliminated are the hassles of measuring minimum machining dimensions and critical dimensions, completing a spring rating test and inspecting the spindle.

• The interval between required maintenance activities is often longer with POSRVs than with direct spring-operated valves. Once a valve begins to leak, the disc and nozzle can quickly become eroded to the point that the valve must be repaired, requiring a complete shutdown of the process. A POSRV’s greater seat tightness means fewer leaks and, therefore, fewer costly and disruptive shutdowns.

Switchable dual-pilot actuators provide an additional opportunity to increase operational uptime and lengthen service intervals.

One pilot actuator remains active while the other is removed for repair and setting in a workshop. Periodic changing of the O-rings in the main valve and checking of free movement allow the main valve to be removed from the line less frequently than direct spring-operated valves.

• In-situ testing allows POSRVs to be tested without costly process downtime. Valve manufacturers have developed equipment that keep the main valve closed during testing, eliminating the need to remove the valve from service and allowing production to continue safely while the test is completed.

SPECIALREPORT

advanced technology; however, just as today’s auto mechanics are more skilled than those of a century ago, so are today’s plant operators. A modest amount of hands-on, practical training is all that is required to ensure adherence to the manufacturer’s recommended maintenance practices and techniques.

Misconception 3: Pilots are for “clean service” only.

When POSRVs were first introduced, their use was limited to “clean service” applications. Engineering technology has advanced considerably since that time, and today POSRVs can effectively be used in many “dirty service” applications.

The “non-flowing” design used in virtually all modern POSRVs protects the “brain” of the valve assembly—the pilot valve actuator—from potentially damaging process fluids. Early POSRVs had a “flowing” design wherein process fluid also flowed through the pilot actuator when the main valve was open, thereby exposing the actuator to the process fluid and making it vulnerable to erosion and contamination. The advent of non-flowing POSRVs removed this risk by ensuring that no process fluid moves through the pilot actuator when the main valve is open, thus eliminating contamination and possible erosion within the pilot actuator. It should be noted, however, that, despite these advances, precautions must be taken when applying POSRVs to dirty, viscous or paraffin-laden fluids.

Clean service connections can be installed to keep sand, grit and dirt from clogging a POSRV’s sensing line and damaging other vital valve components. A closed chamber filled with an inert gas is positioned at the top of the pilot valve body and below the pilot valve bonnet. The process media pressure still controls the set pressure and blowdown of the POSRV, but crucial valve parts such as the modulator, dome assembly, vent and inlet seals never come into contact with the dirty system media.

Cover gases can also be used to protect the disc and sensing line from corrosive process fluids. A blanket of inert gas fills the spaces between the process gas and the relief valve, ensuring that the fluid does not come into contact with the disc or enter the sensing line.

Misconception 4: Re-piping will be required. Many operators believe that converting from direct spring-operated valves to POSRVs will involve re-piping the system to make room for the

Misconception 2: Pilots are more complex. POSRVs

are more complex than traditional spring-loaded valves, but that comparison is also a bit like comparing today’s cars to a Model T. Yes, technology has progressed and POSRVs incorporate more

FIG. 2

The POSRV shown here senses pressure at the vessel rather than at the valve inlet piping. Note: Valve piping and vessel not to scale.

HYDROCARBON PROCESSING NOVEMBER 2011

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PLANT SAFETY AND ENVIRONMENT

main and pilot valves. In many cases, however, existing piping may be used since manufacturers now offer POSRVs that fit directly into the holes left by the spring-loaded valves they are replacing. These

pilot valves have a main valve designed to API 526 rules for direct spring-operated valves and are ASME-certified POSRVs, according to the National Board of Boiler and Pressure Vessel Inspectors.

In one example, such a valve was used to replace two safety relief valves in a medium-pressure steam header application. The safety relief valves were prone to not closing properly and, as a result, required frequent maintenance. (The second valve had been installed so that one valve could remain in service while maintenance was completed on the other.) The valves also fluttered due to a high pressure drop created by a long run of piping between the valves and the system pressure flow. The safety relief valves were replaced with a single POSRV designed to API 526 face-to-face dimensions.

The seating issues were resolved, and remote sensing eliminated the high pressure drop and the potential for flutter. Also, no new piping was required, likely saving the customer tens of thousands of dollars.

THE NEW GENERATION: TUBELESS POSRVs

FIG. 3

In a tubeless POSRV, the media is directed through internal passages rather than external tubes.

A relatively new kind of POSRV, the tubeless POSRV, offers significant additional advantages. As the name implies, tubeless POSRVs operate under the same principles as other POSRVs, but the media is directed through internal passages rather than external tubes (Fig. 3). Eliminating the tube—the part most frequently in need of repair or replacement—gives the valve even greater flexibility, further streamlines maintenance practices and enhances safety.

Doing away with the tube eliminates the risk of tube failure— and ultimately valve failure—caused by human error, misuse, vibration or atmospheric conditions. Hydrocarbon processing facilities are inherently high-risk, making safety the highest priority. Tubeless POSRVs can help plant operators ensure that a valve

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SPECIALREPORT

PLANT SAFETY AND ENVIRONMENT

will not be disabled if a worker inadvertently steps on and crimps the tube, if extreme vibration breaks the tube, or if freezing temperatures cause hydrates to form in the sensing line, plugging it.

Furthermore, the absence of a tube in a POSRV lowers the potential for leakage and reduces the need for custom configuration.

CHOOSING THE RIGHT POSRV

There are several important factors and options to consider when specifying a POSRV: â&#x20AC;˘ Should the POSRV use internal or remote sensing? Specifiers should examine where the valve will be installed and determine whether the POSRV should have internal or remote sensing.

High pressure near the valve inlet can cause a valve with internal sensing to discharge unnecessarily because the valve is not correctly sensing the pressure. In these instances, system designers should opt for a POSRV with remote sensing that can be placed an adequate distance from the valve inlet. â&#x20AC;˘ Will there be condensable gases in the flow stream? If the flow stream will contain condensable gases, a dual-phase POSRV that can accommodate both liquids and gases must be used. In most installations, the pilot valve discharges into the main valve outlet. If the flow stream contains condensable gases and the main valve experiences cooling, liquid condensate will form in the top of the main valve. If the POSRV is not designed to handle liquids, the main valve will not open and will not protect the system in the event of an overpressure situation. â&#x20AC;˘ What material should be used? The valve material should conform to that used in the piping, as the piping will be compatible with the fluid. For example, if the fluid will already have been

treated and cleaned, carbon steel with stainless steel trim will be acceptable. However, if the gas will be sour, exotic materials should be considered. NACE International offers a list of materials that can be used in environments that cause stress, corrosion and cracking, such as sulfur and hydrogen sulfide. â&#x20AC;˘ What are the code requirements? POSRVs are governed by two primary regulating bodies. ASME establishes regulations for certifying valve capacity and the materials that can be used in constructing valves. The US Department of Transportation, with its responsibility for governing interstate and offshore pipelines, establishes requirements for valve testing.

As hydrocarbon processors strive to meet ever-higher expectations, replacing direct spring-operated pressure relief valves with pilot-operated safety relief valves is a relatively simple upgrade.

Such replacements can pay significant dividends, from improved valve performance to streamlined maintenance processes, lower maintenance costs and, potentially, increased output. HP Joshua R. Scott is the global director of product management for GE Energyâ&#x20AC;&#x2122;s Consolidated product line and has 12 years of energy industry experience. He is responsible for the life-cycle management of the Consolidated line of products. He has an MBA degree from the University of Baltimore and a BS degree in industrial engineering technology from Southern Illinois University.

Niall MacKinnon is a regional product manager for GE Energyâ&#x20AC;&#x2122;s Consolidated product line in the UK and has 22 years of valve industry experience as a technician, trainer and manager. He is responsible for product management and aftermarket services in the UK. Prior to joining Dresser Consolidated (now part of GE Energy), he gained extensive hands-on service experience while working in offshore oil and gas facilities and serving in the Royal Navy.

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SPECIALREPORT

Relief device inlet piping: Beyond the 3 percent rule With careful consideration, an engineer can be certain that an installation will not chatter D. SMITH, J. BURGESS, and C. POWERS, Smith and Burgess, Houston, Texas

G

ood engineering practices (API STD 520 and ASME B&PV Code Section VIII) have long specified/required that inlet piping pressure drop from the vessel to the safety relief device should be limited to no greater than 3% of the safety relief valve’s set pressure. Many companies have taken a more lenient approach to the inlet pressure loss limits; consequently, many installations do not meet the 3% design guideline, as the prevailing company logic assumed that existing installations were “safe” as long as the inlet losses were less than the safety relief device’s blowdown with some built-in safety margin. Up until recent fines by OSHA, there have been no hard and clear industry requirements or penalties for companies to adhere to the 3% inlet pressure loss rule. However, OSHA recently rejected this argument and has now begun levying fines against companies violating this 3% rule. In an April 2010 letter to the API STD 520 Committee, OSHA stated that higher inlet losses may be considered acceptable if safety relief valve stability could be assured with an engineering analysis.

This monumental shift has added serious financial consequences for violations of this rule, making compliance no longer an academic argument. This article details a procedure to assist facilities to ensure that existing relief devices with inlet losses greater than 3% are properly designed and will not chatter. It is not the goal of this article to confirm the criteria for an installation to chatter, but instead to give engineering guidance as to which installations are acceptable as they are not expected to chatter. To ensure that this methodology actually solves problems associated with real installations, an entire refinery was subjected to the methodology, and it was found that over half of the installations that have inlet pressure losses greater than 3% are acceptable as is and are not expected to chatter.

Based on a review of literature, the design requirement of “limit the inlet losses to 3%” has been taken as a rule to design safety relief device inlet piping for two primary reasons:1, 15 1. Ensure that the pressure in the vessel will not increase beyond what is allowed by pressure vessel codes 2. Ensure that the valve will operate stably and will not chatter or flutter.

The first concern associated with high inlet pressure losses is elevated vessel pressures beyond the allowable limit, which is 110% for ASME Section VIII vessels with a single relief device.15 This concern is not expected to result in loss of containment from relief device failure and, in most cases, is simple to solve by set-

ting the relief valve opening pressure low enough such that any accumulation in pressure due to excessive inlet line losses does not result in the vessel pressure increasing above the largest pressure allowed by the applicable vessel construction code. However, the second concern is related to the opening of a relief device from a closed position transitioning into a stable operation without the system damaging itself from chatter. The second concern is the more complicated to solve and critical to the overall facility safety.

The inlet piping for safety relief devices has been required to be designed to limit inlet losses to less than 3% per API STD 520 and ASME B&PV Code Section VIII. Many engineers in operating companies that use safety relief devices have taken a more liberal approach to the inlet pressure loss limits for existing facilities. Some companies allow for as much as 5% to 7% inlet losses prior to requiring facility changes based on the argument that the valves will perform as designed without chatter with inlet losses less than the relief device blowdown.18 Up until recent fines

by OSHA, there have been no hard and clear industry requirements or regulatory nudges to adhere to the 3% inlet pressure loss rule. So, logic went that existing installations were safe as the inlet losses were less than the safety relief devices’ blowdown.

However, OSHA rejected this argument and levied a ~$7 million fine against BP.19 In this fine, OSHA rejected the argument that the valve would operate safely if the installation has inlet losses greater than 3% without a corresponding engineering analysis that shows the installation will not chatter. It should be noted that according to the BP press release, this citation is being fought in the US courts (outcome unknown at press time).18 Thus, the determination of “if inlet piping pressure losses that are greater than 3% are acceptable” is no longer an academic argument, but one that has caught the attention of engineers and plant management. Industry needs a cost effective way to confirm that existing installations that have inlet pressure losses in excess 3% are acceptable. This article is meant to detail a procedure to assist facilities in ensuring that existing relief devices with inlet losses greater than 3% are acceptable. It was not the goal of this article to confirm the criteria for an installation to chatter, but to give guidance as to which installations are acceptable and will not chatter. High inlet pressure losses may also result in relief device capacity reduction, which is also outside the scope of this article.

Cost to industry. Based on industry statistics, between 5% and 10% of existing relief device installations have piping conHYDROCARBON PROCESSING NOVEMBER 2011

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PLANT SAFETY AND ENVIRONMENT

figurations such that the inlet line pressure losses are greater than 3%. To ensure that the methods presented are not just academic, but actually can reduce the costs associated with changes to inlet piping, an entire mid-sized US-based refinery was reviewed using the presented methodology. The value of these methods to industry is that this analysis allows a facility to focus modifications on installations that may chatter, not just those with high inlet pressure losses.

Fig. 1 shows the inlet pressure loss percentages for relief devices for a refinery located in Texas. The calculations for determining if chattering is possible based on the listed methodology were performed in software developed by the authors for this refinery.

At the facility, there were approximately 550 relief devices installed in the process units, of which 64 relief devices were identified as having inlet line losses greater than 3% (~12% of the total). Of these relief devices, 34 were not expected to chatter, based on known mechanisms that cause chatter. This methodology eliminates the need to review (or modify) ~50% of the relief devices with inlet pressure losses greater than 3% and allows the management team to focus its efforts on the remaining valves as potential concerns which may chatter.

Since the use of the presented methodology reduced the number of installations that needed further review or piping modifications from 64 to 30 (representing a reduction in potentially unacceptable relief devices from 12% to 6%), this allows an owner/operator to focus time and capital on high risk relief devices. Assuming an average cost of $20,000 to re-pipe the inlet lines for these relief devices, this analysis could save this refinery nearly $700,000. The review and application of this methodology to this refinery shows that sorting relief devices into “those that will not chatter” and “those that may chatter” and focusing time and effort on the relief devices that may chatter is a strategy that presents a real cost savings for operating facilities that use safety relief devices and have inlet pressure losses greater than 3% of the set pressure. The alternative of doing nothing is even more costly.19 Spring operated relief device. When the pressure in the

vessel is below the set pressure of the relief device, the spring holds the valve closed. When the pressure in the vessel approaches the set pressure of the relief device, the relief valve opens. When the pressure at the inlet of the relief device drops below its blowdown pressure (which may be changed based on backpressure), the valve closes. Thus, if a relief device that has been sized and installed Example refinery summary of PSV inlet pressure loss

Valves with inlet losses < 3% 88%

Vapor valves with inlet losses > 3% 11% Liquid valves with inlet losses > 3% 1%

FIG. 1

60

PSV inlet pressure loss summary for the example refinery in Texas.

I NOVEMBER 2011 HydrocarbonProcessing.com

properly is needed, it will “pop” open at its set pressure, allow fluid to leave the system, and either depressure the system or keep the pressure from rising above the design limits. It will close when the overpressure event is finished. If the required capacity is nominally more than 60% of the relief device rated capacity (see discussion on h/hmax below), the pressure will increase as the PSV slowly opens to the specified pressure. If the required relief rate to prevent overpressure is less than ~25% of the valve’s rated capacity, the equipment protected by the safety valve will depressure the system until it closes, at which point the system will begin to pressure up again, and the cycle will be repeated (this is examined more closely later in the article).

While the previous discussion does not introduce any new concepts to industry, the basic operation of the safety relief device is the basis for this discussion on destructive chattering. High frequency (destructive) chatter can best be defined as the rapid cycling (> 1 hz) of a relief device open and closed which may lead to the loss of containment of a system through a mechanical failure in the relief valve or inlet/outlet piping or by the friction welding of the relief device (either open or closed).

Two related phenomena are flutter, the cycling of a valve open and closed without the seat contacting the disk, and short cycling, the non-destructive opening and closing of a relief device (at a frequency < 1 hz), both of which may result in damage to the safety relief valve internals but not expected to result in a loss of containment. Thus, flutter and short cycling are not considered significant safety hazards, and facility modifications should be focused on mitigating the risk associated with high frequency chatter. Based on discussions with various valve manufacturers, when the frequency of the relief device chatter exceeds ~1 hz, the potential for destructive chatter is greatly increased.

Known causes of chatter. Chatter is caused by the rapid fluctuation of pressure beneath the relief device disk. Thus, with the absence of all the known causes of high frequency chatter, destructive valve operation is not expected and the inlet piping does not need to be modified. Some examples: • Excessively long inlet lines • Excessive inlet pressure losses • Frequency matching/harmonics • Oversized relief devices • Improper installation.

Once an engineer analyzes and eliminates each of these potential issues for a safety relief device installation, the system can be designated as one that is not expected to chatter and does not need further modifications to the installation to improve the facility’s safety. For most of these system characteristics, there are differences between the analysis for liquid filled systems and for vapor filled systems. Therefore, most sections on known causes of chatter have a sub-section for each fluid type that specifies details of how to analyze each criterion for that fluid case. The term vapor is used to describe systems that contain either vapors or gases.

In 1983, research was published31 that listed the minimum blowdown pressure required for stable valve operation with various inlet piping configurations. The required blowdown for stable operation ranged from 3.5% to 8.4% of the safety valve set pressure. The methodology in this article was used to analyze these installations and in each case predicted the potential for chatter.

Since the blowdown for these valves was experimentally determined to be the minimum possible for which chattering would not occur, any simplified method to rule out the possibility of chatter,

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that is conservative, would be expected to predict that these valves could chatter. In addition, the analysis has predicted chatter could occur in five other installations known to have chattered.

Two phase fluid. The primary cause of chatter is based on

the flow of pressure waves through the fluid on the inlet of the piping and the subsequent interaction on the relief device.6, 9, 31, 32 Based on fluid dynamic work in two-phase flow, systems that are mostly liquid that contain dispersed bubbles have pressure wave flow patterns similar to pure liquids (albeit the vapor significantly reduces the speed of sound in the liquid). Similarly, vapors that contain dispersed liquid droplets have pressure wave flow patterns similar to the vapors. The inability to predict how pressure waves move through a two-phase fluid occurs when the phases slip to the point that the dispersed bubbles or droplets merge and combine.21 Thus, for the analysis of PRV chattering, any installation that could result in the formation of slug flow cannot be designated as stable and chatter free.

Flow in horizontal piping that is “dispersed,” “bubble” or “froth” should remain mostly homogeneous and not result in slugging or other transients. Eq. 1 below is derived from Mr. Baker’s26 flow pattern regimes figure and corresponding equations to ensure stable two-phase flow: w>

d i2σ l ρl2 3 13

28.8μl (1− x )

(1)

Stable flow in vertical piping falls into the “bubble flow” regime for mostly liquid cases with interspersed vapors. For primarily vapor flow with entrained liquid, the “heavy phase dispersed” regime in vertical piping sections is stable flow. Therefore, the following criteria should be satisfied:30

Mostly liquid (bubble), vertical piping section(s) 1

2 ⎛ σ ⎞ 4 ρ 0.67 g d w < ⎜⎜ l ⎟⎟⎟ ⎜⎝ ρl ⎟⎠ 57x

(2)

Mostly vapor (heavy phase dispersed), vertical piping section(s) 1

2 ⎛ σ ⎞ 4 ρ 0.67 g d w > ⎜⎜⎜ l ⎟⎟⎟ ⎝ ρl ⎟⎠ 3.5x

(3)

Any two-phase flow that may develop unstable flow regimes (slug flow or plug flow) or is unstable (like transitioning from supercritical dense phase to liquid) is inherently unstable. The instability of the flow regime makes it difficult to predict with certainty the stability of the relief device, and such installations should be subject to additional engineering analysis or piping modifications.

Excessively long inlet lines. When a valve opens, a vac-

uum forms: in the physical space beneath the disk. If the pressure wave does not travel from the seat of the disk to the pressure source and is reflected back to the disk inlet prior to the relief valve beginning to close, the disk may not be supported by the returning pressure wave and close. Once closed, the pressure will cause the safety relief device disc to open creating a cycle that has been shown to cause high frequency and destructive chatter.6 2L (4) c If Eq. 4 is satisfied, the time it takes to open the relief device is greater than the time it takes for the pressure wave to travel to the source of pressure, get reflected and return. Once the disk starts tO >

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to close, the returning pressure wave may not provide enough force on the disk to change direction and lift it again. Therefore, the opening time was used for the relief device and not the cycle frequency. According to Dresser, steam valves open between 35 milliseconds and 55 milliseconds.7 When the UK Health and Safety Executive (HSE) tested relief devices, they found that in the case of a very high overpressure, 2H3 and 3K4 relief devices could open in as little as 5 milliseconds.4, 5 Kruisbrink found that relief devices open in an average of 25 milliseconds.8 The following correlation, Eq. 5, was developed based on the 1982 ERPI test data and was verified to satisfactorily predict the opening times.9

For cases where the inlet piping is the same diameter as the inlet relief device nozzle, the results of the correlation proposed by Frommann (Eq. 8 and Eq. 9) are very similar to the straight wave correlation (Eq. 4 and Eq. 7), and it is suggested that both criteria be satisfied. For installations where the diameter of the inlet piping is greater than the diameter of the relief device, the Frommann equation. indicates that longer inlet lines may be acceptable than the limitations presented in Eq. 7. However, reviewing the installation based on the criteria represented in both Eq. 7 and Eq. 9 captures the concerns about the correlation presented by Fromman.

⎞⎟⎛ h ⎞0.7 ⎛ 2d PSVi ⎜⎜ ⎟⎟ (5) ⎟⎜ ≈ ⎜0.015 + 0.02 ⎟ 23 2 ⎟⎜ ⎜⎝ ( Ps PATM ) (1− PATM Ps ) ⎟⎟⎠⎜⎝ hmax ⎟⎠

Incompressible fluids (liquids). For liquids, the criterion

t open

The term h/hmax represents the fraction of total travel when relief devices open. Several researchers have indicated that the initial valve lift varies greatly and can range from between 40% and 100% of their full lift.4–6, 8, 9 When the relief devices are not suddenly subjected to severe overpressure (as in the HSE testing;4, 5), the use of 60% to 70% initial lift, for the purposes of calculating t open, is reasonable and in line with the API guidelines.28 Compressible fluids (vapors). A critical design criterion

in determining that a relief device will not chatter is the time it takes for the pressure wave to travel to the pressure source and back to the safety relief device.6, 9 Due to the nature of compressible fluids, there is a recovery of pressure due to the expansion of the gas in the piping. Thus, an initial estimate of the maximum acceptable length for the inlet piping can be determined as follows (for a perfect gas):

kT (6) MW Eq. 6 was obtained from API STD 52129 to calculate the speed of sound in a perfect gas. Thus, if the pressure disturbance can travel to the pressure source and back prior to the disk starting to close, then chattering from this phenomenon is not expected.

This equation was obtained by substituting Eq. 6 into Eq. 4 for the speed of sound and solving for length. c = 223

kT (7) MW Additionally, Fromman has suggested a pressure surge criterion that establishes a maximum inlet line length based on the magnitude of the expansion wave, taking into account the decay in the wave as it travels from the disk to the vessel and is then reflected back to the disk.6 The allowable pressure change in the expansion wave is specified as follows: L <111.5t open

⎛ P − Prc ΔPJK < ⎜⎜⎜ s ⎝ Ps

⎞⎟ t ⎟⎟( Ps − PB ) o 2tw ⎠⎟

62

⎛ Ps − Prc ⎜⎜ ⎜⎝ P s

⎞⎟ ⎟⎟( Ps − PB ) t o ⎟⎠

I NOVEMBER 2011 HydrocarbonProcessing.com

C = 1.09 (KS /␳)^½

Li < 0.55 to (KS /␳)^½

(11)

The speed of sound in two phase mixtures is lower than that of a pure liquid.21 As Eq. 4 shows, the maximum length of the inlet line decreases with a decrease in sonic velocity. Thus, for two phase flow the designer must determine what phase behavior is the best indicator of performance and evaluate accordingly.

Excessive inlet pressure losses. In the current standards

(both ASME and API) the direction for relief device installation is to the inlet frictional pressure losses to no greater than 3% of the set pressure.1, 15 The implication is if inlet losses plus a safety factor are less than the blowdown, the valve will operate stably and not chatter. The results of research done by both the Electric Power Research Institute (ERPI) and Oak Ridge National Laboratory (ORNL), indicate that frictional pressure losses alone are insufficient to predict valve stability and that a relief system designer must allow include the affects of pressure waves.

Compressible fluids (vapors). Based on experimental data,

EPRI published correlations that show if the sum of the acoustic and frictional inlet pressure losses is greater than the blowdown of the relief device, the system may chatter.32 Eq. 12 presents a method to estimate the acoustic pressure losses. 32 ΔPAcoustic =

(9)

(10)

Thus, if the length of the inlet line meets the criteria in Eq. 11, then chattering from this phenomenon is not expected. The following equation was obtained by substituting Eq. 10 into Eq. 4 and solving for length.

(8)

Eq. 9 is obtained using the Joukowski equation (Eq. 8) for the expansion wave (ΔPJK), substituting L/c for tw , and solving for the maximum allowable inlet line length.

d2 Li < 45, 390 i w%O

is more straightforward, as the fluid does not expand to fill the vessel. Thus, as soon as sufficient material is discharged to create a void space, the pressure that is the driving force to keep the relief valve open is removed. If there is no liquid to support the disk when the valve starts to close, then chatter will occur due to the oscillations in pressure. Since the speed of sound in liquids is generally quite high, cases that do not meet these criteria can result in very high frequency and destructive chatter. For liquids, the speed of sound is calculated as:

2 Lw PSV 1 ⎛⎜ w PSV L ⎞⎟⎟ ⎜ + ⎟ 12.6di2tO 10.5ρ ⎜⎜⎝ c d i tO ⎟⎠

(12)

And,

PS − PRC > ΔPTotal = ΔPFrictional + ΔPAccustic

(13)

Eq. 13 is taken from the work by Singh32 but simplified based on the assumption that the initial pressure at which the valve stem lift is reduced (prior to stable flow being established) is lower than the

Since 1968

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reclosing pressure of the relief device. To ensure valve stability under all modes of operation, Eqs. 12 and 13 should be verified for the initial opening conditions, at full capacity, and at closing conditions.

PSV installation concerns resolved

Incompressible fluids (liquids). ORNL published work

that shows for liquid filled systems, the sum of the wave pressure and frictional inlet pressure losses should be less than the blowdown of the relief device. If not, the system may chatter.33 cρ ΔPWave = (Vo −V F ) (14) 4,636.8 And, PS − PRC > ΔPTotal = ΔPFrictional + ΔPWave

Concerns resolved by methodology 53%

Concerns remaining 47%

(15)

As with compressible fluids, Eq. 14 and Eq. 15 should be verified for opening, full flow and closing conditions. Based on the analysis for an entire refinery, the inlet line length limits (Eq. 9 and Eq. 11) and inlet pressure loss limits (when acoustical and wave pressure losses are included, Eq. 13 and Eq. 15) tend to predict similar maximum inlet line lengths.

Frequency matching/harmonics. Based on a review of the literature, there are two primary phenomena that cause vibrations in relief device inlets associated with harmonics: • Standing waves—resonance caused by the combination of waves such that the reflected waves interfere constructively with the incident waves. Under these conditions, the medium appears to vibrate and the fact that these vibrations are made up of traveling waves is not apparent. This phenomenon is caused by a high velocity fluid passing over the inlet to the relief device.

• Matching relief device natural frequency—A cavity tends to exhibit a single resonant frequency. This is caused if a pressure

FIG. 2

PSV installation concerns are resolved.

wave pushes fluid into the volume and then is released; the excess pressure will drive the fluid out. The momentum of the fluid flow out of the vessel will result in excess fluid being pushed out and produce a slight decrease of pressure in the cavity. Fluid will tend to fill the vessel; the cycle will repeat and oscillate at the natural frequency of the container.36 Standing waves. Flow induced vibration becomes a problem when the fluid velocity passing by a relief device inlet nozzle is high enough to create standing waves caused by vortex shedding.

Based on research done in the power plant industry10 the following correlation has been used to predict failures in steam service:

Li <

di c 2.4U

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Thus, to avoid relief device chattering problems associated with standing waves from vortex shedding, the length of the inlet line should be limited to meet the criteria in Eq. 16.10 Note that these equations are valid for other vapor systems, as well as steam.

Helmholtz resonators and cavity resonance. Sallet has implied that chatter due to harmonics caused by the release from a pressure relief device is caused by cavity resonance.34 For this phenomenon to occur, the natural frequency of a piping system would have to match the natural frequency of a relief device, and a constant flow would have to occur as the pressure oscillations in the system build. Per the Consolidated catalog, matching the natural frequency of the piping system and relief device would result in the premature opening of the relief device and not in destructive chatter.35 For destructive chatter to occur due to cavity resonance, the relief device would need to cycle at a frequency almost exactly equal to the resonance frequency of the system and stabilize at that cyclic frequency.36 Since the cyclic rate of the relief device is a function of the valve lift (required relief rate) and the system frequency is a function of the material being relieved and the system piping, the authors have concluded that the phenomenon of destructive resonance is unlikely to occur and difficult to predict in advance for systems with varying materials and flows.

Oversized relief valves. Safety relief devices close at approxi-

mately 25% of their rated capacity.22, 29 Therefore, if a relief device is oversized, the system will be more prone to chattering. This is because there is not enough fluid flowing through the relief device, and the combination of the momentum and pressure forces are insufficient to hold the valve disc open. Once the valve closes, the pressure can build quickly (depending on the system) and re-open the valve. Thus oversized relief devices create a cyclic opening/closing chatter prone cycle.

Compressible fluids (vapors). Once a valve is open (assuming an installation in line with good engineering practices), the flow through the relief valve is dependent only on the relief valve disc position (which generally determines the orifice area and capacity) and the inlet and outlet pressures (the driving force). The amount the relief valve is open is determined by the inlet and outlet pressure for the valve. Although the required relief rate determines whether the vessel pressure will increase or decrease once the relief valve opens, the flow through the relief valve is based only on the inlet and outlet pressures and not the required relief rate nor the rated capacity of the valve. If the required relief rate is greater than the actual flow rate through the valve, for the given inlet and outlet pressures, the vessel pressure will increase. If the required relief rate is less than the actual flow rate, for the given inlet and outlet pressures, the vessel pressure will decrease. However, the rate at which the inlet pressure will increase or decrease is based on a mass balance that takes into consideration the accumulation of mass in the system along with the volume of the inlet system. All other variables being equal, a larger inlet system will pressure or depressure more slowly than a smaller system. Therefore, the only way that a vapor relief valve can have high frequency chatter from being oversized, is for the system to de-inventory and depressure to the valve’s closing pressure and then re-pressure to the valve’s opening pressure in the specified high frequency cycle time, 1 second or less. Thus, the following two conditions are required for high frequency chatter to be a potential for a vapor filled system 64

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assuming a safety factor of 500% (specifying the system cycling time as five seconds instead of one second): w PSV < 0.20 ⋅VSystem ( ρSet − ρShut ) + wrequired

(17)

And, WPSV > 4WRequired

(18)

A further conservatism built into Eq. 17 is that a safety relief valve typically only “pops” open to ~60% of the full lift. Therefore, the safety relief device’s capacity at the valve’s set pressure is significantly lower than the rated capacity which will tend to increase the time it takes to depressure a system. After reviewing the industrial relief systems that are known to have chattered and the installations used in the literature, the most prevalent instances of chatter caused by oversized safety relief valves in compressible service seem to be in academia and not industry.

Incompressible fluids (liquids). For liquids, this criterion

is more critical than for vapor systems as the incompressible fluid does not expand to fill the vessel. Thus, if there is not enough liquid flow to keep the safety relief valve open, it will close. Based on the published limits in API STD 521, the safety relief valve is expected to close with a flow rate of 25% or less. While these phenomena usually results in short cycling and not chatter, to eliminate the possibility of chattering, Eq. 18 should be satisfied for a liquid safety relief valves.

Relief valves with liquid trims or safety relief valves with very small relief loads are not known to chatter. Liquid trim relief valves are designed to open proportionally to the flow rate and operate more stably in liquid service.35 Per conversations with relief device manufacturers, safety relief valves with very small loads (2–5% of the capacity) do not fully lift the relief device, and thus short cycle, and are not expected to chatter.

Improper installation. If the valve is improperly installed,

there is no way to confirm that the relief device will not chatter.

The following installation guidelines are based on experience and code requirements. This section does not separate vapor from liquid installations, as improper installations are not dependent on valve service.

Inlet restriction—if the minimal inlet line flow area is less than the sum of the area of the inlet nozzles, the installation may chatter. This is also a violation of UG-135(b)(1) in ASME B&PVC Sec. VIII. Outlet restriction(s)—if the minimal outlet line area is less than the area of the sum of the outlet nozzles of the valves, the installation may chatter. In addition to this not being generally considered acceptable per industry recognized and generally accepted good engineering practices, the cases listed above under excessive backpressure document instances where restrictions in the outlet lines near the discharge flange result in relief device instability.

Backpressure—installations that result in backpressure greater than the limits specified by the valve manufacturers may result in chatter. For cases where the backpressure exceeds the valve manufacturer’s limits, the increased backpressure has been shown to either increase the likelihood of chatter or the vessel pressure.3, 9, 12, 23, 25 The installation of bellows relief devices was explicitly shown to increase the stability of the installation for the given backpressure.12, 23

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PLANT SAFETY AND ENVIRONMENT

Plugged bellows vent(s)—Based on the information in the methodology section of the DIERS Safety Valve Stability and Test Results,24 tests were performed to assess the capacity and stability of a relief device with and without balanced bellows installed. The safety valve tests that were performed with bellows installed had the bonnet plugged. The DIERS study found that bellows valves, with the bonnet plugged, have a higher likelihood of chatter when compared to conventional relief valves. Furthermore, the DIERS study found that when the valve disc vibrations occurred (with a bellows valve with a plugged bonnet vent), the vibrations were more severe, having a higher peak-to-peak amplitude than a conventional relief device.

The authors of the DIERS study stated that they re-ran a few tests without the bellows plugged, and it did not affect the test results. Since the authors of the DIERS study are not clear as to what tests or how many were rerun or what results that were not affected are, and other authors have indicated that bellows relief devices increase the stability of relief devices, 9, 12, 23, 25 it is believed that the incorrect use of the relief valves, e.g. plugging the bellows vent, is what led to the increased instability. It is summarized that the DIERS finding of a decrease in relief device stability and increase amplitude of vibrations is due to plugging the bonnet vent, not on the installation of the bellows. A recent incident of loss of containment due to relief device chatter that involved topped crude with a liquid trimmed relief device that had the bellows vent plugged further supports this conclusions.

Pocketed/liquid filled discharge piping—If the discharge of a safety relief device is pocketed or is normally filled with liquid, such that the outlet bowl of the device is filled with liquid, the potential for chatter increases. A specific relief device must be used to provide overpressure protection or the installation may chatter (or disintegrate) when the valve opens and tries to accelerate a stagnant liquid.

Safety valves designed to operate with liquid in the outlet chamber (e.g. on a pump discharge) have been documented to chatter destructively when the fluid heats to near the vapor pressure of the pumped fluid.

Waterhammer style chatter—Waterhammer arises from the pressure waves generated from velocity changes in liquid flow in response to valve closure. The impact of waterhammer on chatter due to inlet piping configuration is addressed in the section on excessive inlet pressure losses. All other instances of waterhammer are outside the scope of this article.

Multi device installations—It has been shown that when a system has multiple relief devices installed that staggering the set pressure of the relief devices reduces the tendency to chatter.25 While no listed source could be found to link a horizontally mounted relief device to chatter, it is a poor practice and any section on proper relief device installation would be remiss without this warning.

Orientation. With careful consideration of inlet line lengths,

harmonics, relief device sizing and the specifics of each installation, an engineer can be certain that an installation will not chatter. Based on the large number of relief device installations existing in industry that have inlet pressure losses greater than 3%, this methodology can help responsible engineers focus corporate resources appropriately. In the sample refinery reviewed, half of the installations with inlet pressure losses greater than 3% were found to not chatter and are acceptable as-is. This methodology does not predict that valves will chatter, so installations that 66

I NOVEMBER 2011 HydrocarbonProcessing.com

fail to meet all the listed criteria could either further studied or physically modified. When the methodology was checked against instances that were known to chatter, it always predicted chatter was possible. HP NOTATIONS c = speed of sound (ft/s) d = diameter (in) h = valve lift (in) k = isentropic expansion factor (Cp /Cv for an ideal gas, dimensionless) ks = the isentropic bulk modulus of elasticity (psi) kxt = spring constant (lb/s) L = length (ft) m = mass (lb) MW = relative molecular weight of the fluid (dimensionless) t = time (s) T = temperature (°R) U = Process fluid velocity as it passes the PSV nozzle (ft/s) x = mass vapor fractions (dimensionless) w = mass flow rate (lb/s) GREEK LETTERS ␳ = fluid density (lb/ft³) μ = fluid viscosity (cP) ␴ = surface tension (dynes/cm) SUBSCRIPTS ATM = atmospheric b = backpressure on relief device i = inlet jk = Joukowski pressure losses l = liquid max = maximum o = opening PSVi = inlet PSV flange rc = valve reclosing pressure s = relief device set pressure v = vapor %O = Flow rate at the valves percent open LITERATURE CITED Complete literature cited available at HydrocarbonProcessing.com.

Dustin Smith, P.E., is the co-founder and principal consultant of Smith and Burgess LLC, a process safety consulting firm based in Houston, Texas. As a consultant, Mr. Smith has extensive experience with helping refineries and petrochemical facilities maintain compliance with the PSM standard. He has more than a decade of experience in relief systems design and PSM compliance. His experience includes both domestic and international projects. Mr. Smith is a chemical engineering graduate of Texas A&M University and a licensed professional engineer in Texas.

John Burgess, P.E., is the co-founder and principal consultant of Smith and Burgess LLC, a process safety consulting firm based in Houston, Texas. As a consultant, Mr. Burgess has extensive experience with helping refineries and petrochemical facilities maintain compliance with the PSM standard. He has more than a decade of experience in relief systems design and PSM compliance. His experience includes both domestic and international projects. Mr. Burgess has a BS and MS degree in chemical engineering from both Texas Tech and the University of Missouri and is a licensed professional engineer in Texas.

Craig Powers has seven years of experience in relief system analysis. He has been a principal developer of two pressure relief systems analysis software packages. He holds a BS degree in chemical engineering from Northeastern University and MS and PhD degrees in chemical engineering from the University of Notre Dame.

NORTH AMERICAN

TURNAROUND AND MAINTENANCE 2011 Special Supplement to

CONTENTS Make the case for ‘lean thinking’ in maintenance T–69

Corporate Profiles Hytorc T–72 FabEnCo T–73 Rentech Boiler Services T–75 Sulzer Chemtech T–77 Turnaround Management Company T–79 ZymeFlow Technology T–81 Cover Photo: Tray-Tec, Inc. is based in Humble, Texas, and performs vessel mechanical services for the refining, chemical and gas industries across the United States. Photo courtesy of Tray-Tec, Inc.

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Make the case for ‘lean thinking’ in maintenance R. G. LAMB, Consultant, Houston, Texas What is ‘lean’ for maintenance; should companies use?

Lean is not what it seems. The word “lean” makes most of us think of cutting costs by eliminating waste and people; leaving the survivors to do more work with less. The correct vision of lean is to determine what is truly important to the customer and, accordingly, reshape the maintenance work stream to deliver it.

Along the way, wastes and nonvalue-activities drop out, and precious resources are powered up to accomplish newly evolving activities.

What needs to be gone? The essence of lean is that something “needs to be gone.” For discrete manufacturing, it is inventory. For maintenance, it is lead time: the time from when a need is recognized to when it is completed. Average lead time along the typical maintenance work stream is much longer than the tasks needed to actually process most jobs to completion. There is no conceivable upside to the gap.

What is the primary transformation? Lean revolves around a primary transformation, which the customer values. For the maintenance work stream, production assets are transformed from a state at which a production sector’s performance is either actually diminished or the probability of sustaining sector performance to be diminished. Deteriorated infrastructure assets are transformed from a state that potentially presents unforeseeable risk until reversed.

Why is short lead time a profit? No brain trust can fully foresee the collective consequences of decisions to act on all currently outstanding maintenance needs. Short lead time greatly reduces the firm’s exposure from less-than-best decisions and the unforeseeable full ramifications of all decisions. Consequently, short lead time translates to increased business performance.

There is a range of approaches to advance a firm’s organizational excellence or effectiveness. One of the greatest challenges may be to determine which one to adopt. This is because a big part of success is fit. What works for one enterprise and any one work stream within it often has limited relevance to another. This is one reason that we have all seen the flavor-of-the-month programs come and go.

Great fit, terrible name. It is surprising to many that lean is an extremely good fit for reaching maintenance excellence. Maybe its biggest shortcoming is the word “lean.” It is misleading and causes lean to be dismissed before it is understood or abandoned after being initially embraced. Mantra-like expressions such as, “do more with less” and “eliminate waste and nonvalueadded activity” do not help. How can we conjure up anything but our worst nightmares coming true?

The problem is clear when maintenance and reliability professionals were asked what their perception of lean is. A maintenance manager said, “When I think of lean, I think of operating with a smaller budget and fewer people.” A best practices leader said, “My definition of a lean operation would be one that is basically cheap or frugal. They operate lean, meaning they probably would have very low overhead. I would think that they would not spend a lot of money on planning and scheduling.” A reliability leader said, “At the mention of lean, I think of a good, juicy steak with all the fat trimmed off and washed with dish detergent.” Most professionals said that they thought of eliminating wastes and cutting costs.

Something must be gone. This may be what is done in the name of lean. However, this is far from what lean is about. Words such as lean, less and eliminate are only appropriate in a particular way. They are appropriate in that something needs to be gone from the process of transforming a material object to meet a carefully defined customer value to which the work stream is passionately and strongly dedicated to delivering. Whatever that something is, it needs to be gone because it undermines the organization’s ability to recognize and then to deliver customer value.

Lean is most commonly described and touted in the context of discrete manufacturing because that is where its fit is most apparent. It is easy to quickly recognize what needs to be gone. It is inventory along the production line. As it is reduced, all sorts of good things happen. This is because activities and costs, Two whichline werecaption always necessary to deal with large batches and queues, drop out of the picture.

Big question to answer. The study of lean maintenance quickly revealed a question that we must ask ourselves: What core aspect of the subject work stream must there be less of to most effectively transform some material into a final state with value to the customer? Answer the question correctly and all else falls into place.

Let’s stop and establish what is meant by “customer” with respect to maintenance. A customer can be envisioned as a chain of cause and effect. Fig. 1 shows that the frontline links in the chain exist along the total production process. At each, a maintenance work stream of job families delivers the uptime needed for a subject production sector to perform as planned, e.g., allow time for changeovers and other process actions.

The ramifications of success pass along the chain of cause and effect. Ultimately, the customer is the firm as a business system and beyond. The overarching delivered value is sustainable competitive advantage. With our understanding of the entire chain, we accordingly design and deliver value to each production sector as the frontline links. For maintenance, the answer to the big question is lead time.

It is the time from first recognizing a maintenance job as needed until it is completed. For the customer, lead time is central to the uptime of the production sector.

The reason that lead time rests at the heart of lean for maintenance is clear.

Regardless of significance, a maintenance need is a negative condition. When a Firm, supplied and suppliers as a business system Firm as a business system Production process Production sector

e nc na am e t e in tr Ma ork s w

e nc na am e t in tre Ma ork s w

Production sector

Production sector

e nc na am e t e in tr Ma ork s w

FIG. 1. The “customer” is the chain of cause and effect upward from each frontline production sector.

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sword hangs over our head, the sooner we remove it the better; no matter how lethal. The longer we let it hang, the more likely we will get hurt by unforeseen consequences. There may not actually be an ultimate downside to allowing the sword to hang. However, it is inconceivable that there is any upside.

Let’s look at the actual outcome of a lean program if the question is not asked and answered correctly. The default answer to the question had already taken hold: eliminate waste and reduce cost. After listing off all that was being done in the name of lean, the first being “look at costs,” the maintenance excellence leader said, “We had to reevaluate our strategies because we started seeing a negative effect on production.”

A closer inspection of actions taken revealed a program of standard maintenance and reliability improvements traveling under the flag of lean. Unfortunately, in this case, lean will eventually be blamed, and the lean-based opportunity to reach excellence will be lost.

Backlog-think must die. The now-standard maintenance work stream practices actually extend rather than shorten lead time. In fact, lead time is not included in the lexicon of the standard maintenance work stream practices.

The closest association to lead time in the set of standard maintenance practices is backlog. However, it is actually a contrary concept to lead time.

The nature of this discussion is how much backlog should there be, rather than how small we can make it and still function effectively in delivering value.

Furthermore, by definition, backlog does not include all sources of lead time such as the scheduling process and transformation activities.

Another fundamental distinction is that backlog thinking is based on trade hours. By comparison, lead-time thinking is focused on the time until a customer is no longer exposed to a lurking risk. Backlog thinking treats the maintenance work stream as the center of attention. Lead-time thinking demands that customer value be central to all deliberations.

■ Bottom line, a key characteristic of lean for maintenance, including reliability, is to continuously grow the value-to-power ratio of the entire maintenance work stream.

Theoretically, four to eight weeks of backlog is necessary to assure the dayto-day highest possible efficient and productive engagement of staff and field personnel. Few of us, if any, have ever seen hard proof. However, if it is true, shortened lead time would require the firm to engage a larger workforce to counterbalance the consequences.

Lean thinking drives us to refuse to accept lead time much beyond short as necessary. To not refuse is contrary to the core principle of lean : customer value.

If you brought your car to my shop, you do not care about the efficiency of my employees. It is my problem to solve if I want your business. Lean would say, “Figure it out.” That was the case long ago for reducing changeover time from hours and days to minutes in discrete manufacturing. We have many skills, methods and tools to achieve short lead time without increasing the existing work force.

The value tool speaks. Value-stream mapping is the primary analytical tool for lean thinking because it enables us to see value. Something immediately jumps off the page when we chart a map for the maintenance work stream.

For maintenance, a value stream map charts the steps and flow patterns of distinctive job families through them along with measured lead time and other statistics. For each family, the statistics will include flowrates in and out, cycle, available and retention times, etc. The details ultimately link to the uptime specification of the production sector that the charted work stream supports with the transformations made.

With mapping, we compared the lead time of actual maintenance work stream cases to only what was needed to prepare for and execute their naturally occurring jobs. Lean would call this the “perfection” case because all time for backlog, delays, etc., is omitted from the total.

Except for work classified as emergency and break-in, the gap between the current and perfection case was found to be several to many weeks for a majority of the jobs. The backlogs were even greater for progressively lower-priority categories. Maintenance jobs in the middle categories were often very long.

Backlog in the lowest categories was too often out of control.

Something else was even more noteworthy. The long lead times were not just because the mapped work streams were off-the-chart poor performers. Actually, they were not. When we charted the maintenance work stream that is considered to be standard practice, the difference still ranged up to nine weeks. This was to be expected since current non-lean thinking provides for four to eight weeks of job backlog. Additionally, standard scheduling practices extend lead time by more than a week.

Core transformation. Discovering the essence of lean for main-

Meeting current goal for production process uptime Probability of:

Consequences from the business risk created by deterioration of infrastructure

Lead time

All seeing, all knowing. The ramifications of lead time are shown

FIG. 2. The shorter the lead time, the better the outlook for business performance.

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tenance is to eliminate lead time. Why is it such a big deal? The answer lies in establishing another aspect of lean with respect to maintenance. It is what material object is being “transformed?”

In manufacturing, the answer is obvious and easy. It is to transform raw materials into finished products. The transformation for the maintenance work stream is asset specific, but defined with respect to the continued performance of the targeted production operations. Any asset is either a player in the production process or surrounding infrastructure.

Production-linked assets are transformed from a state at which a production sector’s performance is either actually diminished or the probability of sustaining the sector’s performance is diminished. Transformation will also be to sustain a condition or status that blocks the occurrence of need for the first transformation type.

Infrastructure assets are transformed from a state of deterioration. Time is of the essence because, as long as the case for the deterioration stands, it is a potential business risk affecting safety, health, morale, etc.

in Fig. 2. Two undesirable situations get worse as lead time is greater. One is that the production sector’s performance declines over the accounting period as

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NORTH AMERICAN TURNAROUND AND MAINTENANCE 2011

probability becomes actuality. At the same time, the risk inherent to deterioration is more likely to become actual loss as it is allowed to remain in the game.

Look at a value stream map for a production process in discrete manufacturing. For each sector along the production process, lean identifies uptime as a primary aspect in its performance. Uptime in lean is the percentage of time that “everything works or nothing works.”

The lead time of the maintenance work stream has immense ramifications whenever it is a component of a production sector’s total lean uptime. If the plant resides at the left side of its curves in Fig. 2, the goals for lean uptime are much more likely to be the actual outcome.

Why is this the case? We could present countless analogies, and it would be fun. A good one is an old saw in business. The best performing firms make more good decisions than bad decisions.

Consider the ramifications of lead time in making good decisions to prioritize actions along the maintenance work stream. We could make them and use sophisticated simulation models. Some smart people do the best they can with some decision tools.

It is virtually impossible to know what’s going to happen. Someone once said, “To despair is presumptuous because it presumes that we know what will happen.” This is why risk matrices to assign priority upon which to administer and schedule each job in the backlog are only marginally effective. We do not and never will have a crystal ball to go along with the matrix. Short lead time is the closest we will ever come to a crystal ball. As lead time is shortened and the number of jobs outstanding is reduced, the overall outcomes of decisions will be better than the best simulations, brain trusts or priority matrices.

The reason is that the need to see into the future is greatly reduced. At the same time, the need to correctly interpret the future is greatly reduced because

the consequences from suboptimal decisions rarely have an opportunity to arise in a short lead time. To quote one wise old boy’s rule of thumb, “Never give them just one more chance to get at you.”

Stake in ground. Today’s purpose is to explore and build a case—if there is one—for lean in maintenance. We need to either kill it or bring it into the yard and domesticate it. This article is written by engaging practitioners across industry in the exploration of lean. It is what not to expect and accept as lean.

Part of the overall maintenance work stream is the reliability engineering stream.

For lean maintenance, it is regarded as the product design stream.

Bottom line, a key characteristic of lean for maintenance, including reliability, is to continuously grow the value-to-power ratio of the entire maintenance work stream. As this article reveals, the power-to-value ratio is largely defined by the ability to substantially shorten the lead time to delivering the maintenance work load in a manner that allows each affected production sector to meet its business purpose in the current business environment. HP

Richard G. Lamb, PE, CPA, has practiced in the field of maintenance and reliability since 1988. He was the first to fully detail how availability performance is achieved in a manufacturing plant with the many tools, techniques and processes that are now typically referred to as “best practices.” His book, Availability Engineering and Management for Manufacturing Plant Performance, published the details. Since then, his expertise has evolved to tapping the business returns possible through maintenance and reliability by bringing all business disciplines and database technologies to the problem of planning, measurement and control, as explained in his book titled, Maintenance Reinvented and Business Success.

INDUSTRY REPORTS Gulf Publishing Company Introduces Market and Regional Reports Providing Actionable Analysis and Forecast Information. Gain a Deeper Understanding of Market Trends and Industry Development and be Ready to Capitalize on New Global Opportunities.

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Refining Industry Outlook in China to 2015—Capacity Analysis, Forecasts and Details of All Operating and Planned Refineries

This report provides an in-depth analysis of the key trends, issues, challenges in the global refining industry to 2015, including information on refinery product types and future refining trends. The research covers the global refining market with information on historical and forecast capacities of refineries by region and key countries during the period 2000–2015. Leading companies in the global refining industry and their investment opportunities and challenges have been examined.

This report is a comprehensive resource for industry data and information relating to the refining industry in China, providing historical data from 2000 to 2009 and forecast data to 2015. The preports provides asset level information relating to active and planned refineries in China. Extensive information is provided for key companies including China Petroleum & Chemical Corporation, PetroChina Company Limited and CNOOC Limited. Growth segments and opportunities in China’s refining industry are explored in detail.

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HYTORC

NORTH AMERICAN TURNAROUND AND MAINTENANCE 2011

The world’s most trusted torque and tension systems HYTORC® makes industrial bolting safer and simpler. With over 40 years of experience focused entirely on industrial torque and tension systems, HYTORC is the most trusted name in the industry. From steel mills and mining equipment to refineries, nuclear power plants, and wind turbines; the company has developed solutions for every bolting application imaginable. For custom projects, HYTORC’s highly experienced engineering team is at your service to design the most efficient solution for your job with simple operation and economical pricing in mind.

HYTORC is consistently improving upon existing products, and developing new tools based on feedback from the people that use our equipment every day. Our latest product line features patented innovations like reaction arm-free torquing to eliminate dangerous pinch points, hands-free operation to keep tool operators at a safe distance from the application, and industry-leading bolt load accuracy to reduce nut loosening and flange leakage.

Next Generation Tensioning. HYTORC has developed the world’s first bolting system that is capable of applying straight pull tension with consistent, groundbreaking accuracy within 5% of desired bolt load. Unlike traditional tensioning systems, there are no pullers, no hand torqueing, no relaxation after stretch and no heating or measuring required with the HYTORC system. This patented system is unlike anything else in the market: it has been proven by independent testing agencies to be the most accurate system when directly compared to various hydraulic puller tensioners and heat induction systems.

This tensioning technology is currently in use at many refineries and power stations around the world and the time-savings reported over previous methods have been said to pay for the system after the first install. Substantial reductions in job time have been reported on critical applications such as nuclear reactors, turbine casings, boiler pumps, valves and other bolted joints that had been viewed as a challenge during previous assembly/disassembly procedures. In one case, where 14 bolted joints in a refinery had been assembled with the HYTORC tensioning system, over 72 hours of job time was saved during the outage – a remarkable achievement.

For anyone who is hesitant to upgrade to this advanced tensioning technology, HYTORC issues The Leakage-Zero Challenge: allow a HYTORC field technician to survey your most troublesome bolting application and provide a quote for the upgrade to the HYTORC system. If the system isn’t completely leak-free upon startup, and the installation was not as safe and as fast as promised, the job is completely free of charge.

Worldwide Customer Service. HYTORC has the goal of 100% customer satisfaction deeply embedded in every aspect of the business. Every HYTORC customer is entitled to free 24/7 phone support as well as free safety training, product operation training, and many more unique benefits. Additionally, all HYTORC products are covered by a worldwide one-year no-questions-asked warranty, which includes free parts and labor; another first in the industry. With authorized repair facilities located all over the world, a one-day turn-around is usually available.

HYTORC also has a new mobile service division that is available in many areas to provide on-site calibration and repair. With this service, free tool inspections are available and reminders or follow-up visits can be easily planned for all future calibrations. All repaired/replaced parts are warrantied for an additional 6 months and if a repair must be sent off-site, a free loaner tool is immediately available.

Our mission at HYTORC is to make our customers’ jobs as hassle-free as possible and we will do everything in our power to accomplish that.

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Two HYTORC Avanti tensioning tools operated simultaneously by remote.

Training and Educational Programs. HYTORC has worked together with OSHA and the ASME to create bolting courses and specifications that are designed to increase safety on bolting jobs. For the first time, OSHA certified bolting courses can be given at a customer’s site to train anyone that will be using the equipment on safe handling and operation. This applies to bolting equipment made by other manufacturers as well. HYTORC takes job safety very seriously, and while developing safer products lessens the chance for incidents in the future, these courses are the best way to immediately increase safety and reduce the possibility of OSHA recordable incidents.

ASME has recently updated their views on current and practical bolting methods. HYTORC has worked together with the ASME to understand these methods, and has developed technologies and procedures to assist all HYTORC users in upgrading their bolting methods to meet the new ASME specifications. Free consultations are available through HYTORC to learn more about these procedures and what is involved in assuring that your facility is in compliance.

Additionally, HYTORC works together with trade unions and educational institutes to give future workers practical training on tool handling and operation. This is the first step in ensuring safety as well as correct and efficient operation on the job. When this is combined with the many innovations that are present in today’s torque and tension systems available from HYTORC and the continuing training and educational programs available through HYTORC, the result is more efficient bolting practices and a safer future for everyone.

Since 1968

Contact information 333 Route 17 North, Mahwah, NJ 07430 Phone: +1-201-512-9500 Fax: +1-201-512-9615 Email: info@hytorc.com Web: www.hytorc.com

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FabEnCo

NORTH AMERICAN TURNAROUND AND MAINTENANCE 2011

Fall protection with FabEnCo self-closing industrial safety gates As the world’s leading manufacturer of adjustable, self-closing industrial safety gates, FabEnCo is the “one-stop shop” for high-quality, Americanmade safety gates. With a full range of gates for fall protection as required

by OSHA, FabEnCo gates fit unprotected openings up to 60 inches at ladders, platforms, stairs, catwalks, mezzanines and machine guarding.

FabEnCo’s family of safety gates includes the A Series (the original double bar gate), the XL Series (for extended vertical coverage), the R Series, (a competitively-priced, metal alternative that replaces aging and/or deteriorating “plastic” gates) and the Z Series (designed specifically for new construction projects). FabEnCo also recently introduced its new Toe Board Kit as an optional clamp-on extension to the Z Series gate.

FabEnCo Self-Closing Safety Gates are available in carbon steel, as well as aluminum and stainless steel for special applications and environments.

Finishes include galvanized and safety yellow powder coat. On request, FabEnCo also develops custom safety gates to meet special requirements or unusual openings.

Easy to install on all types of handrails (angle, flatbar, pipe) or to existing walls, FabEnCo Self-Closing Safety Gates save companies the time and money it takes to fabricate their own gates. Most gates can be mounted on

either the left or right side of handrail openings, at different levels. Once the stop bolts have been adjusted, each safety gate’s reliable stainless steel spring automatically closes the gate to the customizable stop point set on the gate–up to a 90 degree angle.

Safety gates are shipped directly from FabEnCo’s manufacturing facilities in Houston, Texas, and arrive with all of the necessary mounting hardware.

Easy-to-follow mounting tips are included with each gate. In addition to contacting the company by phone, customers have the option of easy online ordering using a major credit card or charging their open account.

Contact information Address: 2002 Karbach Houston, Texas 77092 Phone: (713) 686-6620 TwoFax: line caption (713) 688-8031 Toll Free: (800) 962-6111 www.safetygate.com

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HYDROCARBON PROCESSING NORTH AMERICAN TURNAROUND AND MAINTENANCE 2011

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R E N T E C H

C R E AT E S

RENTECH Boiler Services specializes in engineered repairs, rebuilds and upgrades of industrial boilers using headered membrane waterwall design.

We retrofit any style of boiler, making RENTECH your one-source boiler company.

Our work meets NBIC and ASME standards. To reduce operating costs, eliminate shutdowns, allow faster start-up and cool-down, and reduce emissions, call for personal service from RENTECH Boiler Services.

RENTECH

Boiler Services, Inc.

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

RENTECH BOILER SERVICES

NORTH AMERICAN TURNAROUND AND MAINTENANCE 2011

Not all boilers are rebuilt equally

An efficient rebuilt boiler is the combined result of its redesign, engineering and fabrication. Our engineering at RENTECH Boiler Services creates reliable boiler upgrades. RENTECH is your one-source, full-service boiler company because we provide reliable upgrades for many types of industrial boilers. We specialize in engineered repairs, rebuilds and retrofits of boilers using headered membrane waterwall design that eliminates refractory walls and seals.

You’ll find satisfied customers of RENTECH in a variety of industries – including refining, petro-chemical, manufacturing and power generation – across the U.S. and in several other countries. Our engineers along with our service and manufacturing technicians work together in our state-of-the-art plant and in the field. RENTECH is proud of its reputation and record of service. We work diligently to help our customers operate their boilers more efficiently and safely, and our work is backed by the best warranty in the industry.

Our people make the difference because of their experience, knowledge and dedication to customer service. Our qualified engineers understand all process conditions, and they can optimize your system and improve its performance in a cost-effective manner on your original footprint. We offer fully integrated solutions that comply with all performance criteria. Boilers upgraded or repaired by RENTECH provide: • faster start-up and cool-down • cooler furnace environment • minimize unscheduled outages • improved combustion control Since 1997 RENTECH has provided quality products and services, including superheaters, economizers, sulfur condensers, burner and CO/SCR system retrofits, seal-welded furnaces, watertube and firetube boilers, heat recovery boilers, and solid fuel fired boilers. We strictly abide by National Board Inspection Code (NBIC) and American Society of Mechanical Engineers (ASME) standards. Our engineering knowledge, advanced technology and commitment to customer service combine to produce value for each customer by reducing operating costs, eliminating shutdowns, reducing emissions and extending boiler life. Customers with boilers upgraded by RENTECH spend less on maintenance, allowing them to redirect those funds for other needs in their budgets for daily operations and capital improvements.

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Our employees at RENTECH Boiler Services have accumulated more than 1,000 years of combined service. Our plant covers 12 acres at RENTECH headquarters in Abilene, Texas.

In recent years our customers have included 3M, Alon Chemical, ChevronTexaco, Dallas Independent School District, Entergy, Sinclair, Sunoco, Texas Tech University, University of Texas, and Valero. One Valero project engineer said, “I was very impressed with the level of service and quality of work that Rentech Boiler Services was able to provide. I awarded a fast-track job to Rentech for fabrication of a boiler tube bundle on a critical piece of equipment. Rentech was able to deliver a great quality product to the refinery on schedule.”

We realize that an efficient boiler contributes to your profitability. So if a boiler is crucial to your plant’s operations, and your outdated boiler is costing you time and money, call or email today to discover a solution that’s right for you from RENTECH Boiler Services. RENTECH is building a reputation, not resting on one.

Contact information 5025-C Highway 80 Abilene, TX 79601 Phone: 325-672-2900 E-mail: INFO@RENTECHSERVICES.COM Website: WWW.RENTECHSERVICES.COM

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SULZER CHEMTECH

NORTH AMERICAN TURNAROUND AND MAINTENANCE 2011

Tower technical bulletin Tray design features that reduce turnaround maintenance time Background Column shutdowns can be costly. Production is halted and maintenance expenses accumulate without any offsetting revenue. Maintenance crews need to isolate, open, inspect, modify, repair, and close columns, all under pressure to complete work as expeditiously as possible.

Minimization of shutdown costs begins during the equipment design phase.

Sulzer incorporates several features into our tray designs that can reduce column shutdown time.

Tray Replacement and Installation Tray removal and replacement can take a significant amount of time; the larger the tray diameter, the longer the time. This is not only due to the handling the physical size of the components, but also to all the many hardware connections associated with the various tray panels.

For more than 40 years, Sulzer has offered a boltless panel to panel connection called Lip-SlotTM. This interlocking tray panel design decreases installation time by as much as 50% (two Lip-Slot trays installed in the time it normally takes to install one conventional tray).

The Lip-Slot design is used for panel to panel connection allowing adjacent panels to be quickly secured to each other. This design is typically employed on trays with diameters greater than 72 inches, where installation times can be significant.

Lip-Slot design has been successfully utilized in heavy duty applications, including high uplift (2.0 PSI) internals designs.

Lip-SlotTM Connection

Tray Manway Design During column openings, it is always important to have quick access for work and inspection and then to be able to close the tray manway panels as quickly as possible. Sulzer can provide quick opening manways that allow access to the tray below in less than 10 seconds.

These quick opening manways come with handles and special locks that allow opening and closure without losing tightness between manway panels. This design allows the panels to be opened or closed either from top or bottom of the tray. The handle position indicates if it is locked or unlocked.

Some customers prefer using slide fasteners on manway panels. In these cases, an easy opening manway design has been developed with slide fasteners. This design takes somewhat longer to open and close compared with the quick opening design, but clearly less time than conventional manways.

Quick Opening

Easy Opening

Contact information 8505 E. North Belt Drive | Humble, TX 77396 Phone: (281) 604-4100 | Fax: (281) 540-2777 TowerTech.CTUS@sulzer.com www.sulzerchemtech.com

The Sulzer Process Applications Group Sulzer Chemtech has over 50 years of operating and design experience in refinery, oil & gas, and chemical applications. We understand your process and your economic drivers. Sulzer has the know-how and the technology to provide internals designs with reliable, high performance.

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The People You Count On

Tired of getting an “almost fit” for your turnaround and projects team?

Trying to fit a square peg into a round hole may sound like a cliché—but job shops do it every day, especially when presenting flex workers for turnaround, project and maintenance teams.

TTMC Personnel has developed an advanced process called EQSP (Employee Qualification and Selection Process) that helps you find that “just right” person(s) to help you build a high performance team.

Rather than trying to mold a candidate to a position, the EQSP process allows you to dig deeper. EQSP is rigorous, in-depth and reliable. It consistently matches the best candidates to your specific needs as defined by your goals and their role to help you get there.

EQSP is a streamlined and systematized hiring and on-boarding process that doesn’t waste your time. It is not a one-size-fits-all approach. You have multiple hiring options that give you the flexibility you need to make the most of your flex workforce.

So when you need qualified people to round out your turnaround, project and maintenance organizations, call TTMC Personnel. You won’t get a square peg but a well-rounded top-notch candidate that’s the perfect fit.

17629 El Camino Real • Camino Center 1, Suite 125 • Houston, Texas 77058 Main: 281-461-9340 • Toll-free: 877-TRNARND (876-2763) Fax: 281-956-5787 • www.tamanagement.com Select 79 at www.HydrocarbonProcessing.com/RS

TURNAROUND MANAGEMENT COMPANY

NORTH AMERICAN TURNAROUND AND MAINTENANCE 2011

A new and advanced solution addresses flex force needs The Turnaround Management Company (TTMC) began providing project controls and management outsourcing for maintenance turnarounds in 1998.

Because of downsizing, many operating plants outsourced project management and controls for turnarounds to their contractors. Some chose one of the larger contractors to act as general contractor. Others became the general contractor and hired specialty contractors to work under the direction of their own team.

The latter offered control, cost, and quality advantages provided they had core competencies and staff in-house. TTMC became a successful resource for plants that wanted to outsource job planning, scheduling, or cost management so their in-house staff could focus on remaining activities.

When plants needed planners, cost engineers or other specialized indirect labor to work as part of their staff, they would solicit them from the same turnaround and capital projects contractor that was approved to supply engineering services or direct labor. It was bittersweet for the contractors. Having their people working on a client’s staff was a way to secure additional work. On the other hand, they needed their best people to control their own work and bottom line, especially when bids were not based on time and material.

Specialized flex workers are in demand Then, the market changed again. Today, most in-house competency has been restored. But due to the recession, the in-house staff has not grown in size. Today’s operating plants want a qualified “flex” workforce that they can expand and contract as needed.

To answer these needs, we recently formed a new division called TTMC Personnel. While TTMC is a resource for expertise, processes, and tools, the purpose of TTMC Personnel is to supply a specialized “flex” workforce for maintenance turnarounds, shutdowns and capital projects. The market needs specialized contract personnel with the expertise to augment their staff—independent of contractors who supply direct labor or engineering.

Instead of being a staffing company, TTMC Personnel is a personnel contractor and must qualify as a contractor to work in plant facilities just as any mechanical, electrical, or other contractor does. TTMC Personnel provides a flex workforce of specialized personnel to work under the direction of the client company while remaining TTMC Personnel employees. Once they finish an assignment in one plant, they are reassigned to another TTMC Personnel job at another plant—multiple assignments, same employee benefits and employer until retirement. Also, we are an ESOP (Employee Stock Ownership Plan) company so all employees get an annual stock distribution—simply for being an employee.

TTMC Personnel’s EQSP digs deeper than just reviewing a stack of résumés. The process helps match client goals with specialty “flex” personnel to get the right “fit.”

Let the situation, not the résumé, determine the “hiree” We call this “situational hiring.” While the phases and fundamentals of each turnaround and project are primarily the same, each turnaround and project have their own unique circumstances and requirements based a number of factors like location, time of the year, availability of resources, alloy welding vs. carbon steel, amount of revamp vs. plain vanilla work and more. It will behoove us to carefully consider the situation, the project and what’s expected from the person in that position. We also caution our clients about applying the same hiring standards and techniques their operating company uses to fill its long-term employee positions to fill temporary positions. The goals for a flex-force position can be much different than the goals of a permanent long-term employee position.

By carefully considering what our clients want and need and matching that with the person or persons who best meet those wants and needs, we can better serve both our clients and our employees. Our industry knowledge and client-centric service approach means better people equal better results…an experienced flex workforce you can count on.

A stringent and customer-friendly selection process TTMC Personnel offers even more advantages to clients. Unlike staffing agencies and other contractors, we have a comprehensive and advanced process we call EQSP (Employee Qualification and Selection Process) to provide clients with better and more qualified people to fit the position.

EQSP goes further than just looking at résumés because, while a résumé is a primary connection to the person, their work history and their credentials, we also look at what our customers want. We interview our customers to determine the goals they want to accomplish versus giving them a “one size fits all” perspective for the position. This improves our odds at helping them put the right person in the right seat on the bus to help them develop a high-performance team. In other words, we help them hire the position and not the résumé.

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Contact information To learn more contact David Frinsco The Turnaround Management Company & TTMC Personnel 17620 El Camino Real, Suite 125 Houston, TX 77058 Phone:281-461-9340 E-mail: sales@tamanagement.com www.tamanagement.com

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100%

Biodegradable

Decontaminate naturally in a single step.

In one easy step, Zyme-Flow® removes hazardous contaminants from refinery and petrochemical units. 100% natural. 100% safe for your people. Sulfides (H2S) and pyrophorics are eliminated.

LELs and benzene are removed. Residual oil and gas are gone.

All without impacting wastewater facilities, personnel and the environment. Simply put, it’s a natural for fast and effective results.

Tel: +1 832.775.1600 | Toll Free: 877.332.6648 | zymeflow.com

Zyme-Flow® is a mark of United Laboratories International, LLC. 2010 United Laboratories International. All Rights Reserved.

Worldwide Leader in Refinery Decontamination

Select 76 at www.HydrocarbonProcessing.com/RS

Zyme-Flow® tough. From routine decontamination to heavy oil.

ZYME-FLOW® TECHNOLOGY

NORTH AMERICAN TURNAROUND AND MAINTENANCE 2011

Innovative alternative to conventional pipeline cleaning—Petrogal Matosinhos refinery M. P. CASTRO and T. T. PINTO, Petrogal Matosinhos Refinery, Portugal; and D. SCOTT P.E., M. SMITH M.SC., S. MATZA PhD, and H. DAWSON, Zyme-Flow® Technologies, Houston, Texas

For 20 years, Zyme-Flow® Technologies has offered the most complete decontamination solution for refining applications. In a single step, this process removes oil, gas, LEL, and benzene while also neutralizing hydrogen sulfide and pyrophoric iron sulfides. The chemistry can be applied as an aqueous solution in circulation or through a proprietary Vapour-Phase® steam cleaning process where the product is injected directly into the plant’s steam source. Using Zyme-Flow® chemistry in conjunction with the Vapour-Phase® procedure offers the fastest method for rendering process equipment ready to open with a minimal mechanical footprint and vastly reduced amounts of generated waste that are compatible with waste water treatment facilities. Zyme-Flow® chemistries are environmentally responsible formulations utilized in refineries worldwide.

Case Study In a recent application at Petrogal Matosinhos Refinery, the Zyme-Flow® Process was used to successfully decontaminate an uninsulated 2.1 Km 36” pipeline network associated with the transfer of crude oil at Matosinhos Refinery tank farm. This particular facility was located in an environmentally sensitive and residential area, so there was obvious concern for chemical releases and noise pollution. The pipeline had never been decontaminated in its 40+ year history, but inspection reports indicated the need for some spool replacements due to wall thinning. Industry standard is to use a liquid circulation chemical cleaning process followed by mechanical pigging. Using that methodology, the estimate for completion of this project was one (1) month. Due to critical time constraints posed by ship unloading schedule and the environmental concerns, the facility instead chose an innovative alternative approach using ZymeFlow® chemistry in a Vapour-Phase® application in order to minimize wastewater for disposal. Prior to the implementation of the project, meetings were conducted between Zyme-Flow® Technologies and Petrogal plant personnel to discuss project planning, job scope definition and to develop a collaborative execution plan.

Zyme-Flow® Technologies estimated duration of this decontamination was three (3) day shifts exclusive of the preparative steps of draining the pipeline and conducting a water flush. Since the pipeline was drained but never water-flushed, significant oil volumes were expected and present when the decontamination commenced. Using a single injection point, Zyme-Flow® chemistry was introduced to the plant’s 3” steam line using a single-stroke pneumatic pump. Piping laterals from the main pipeline to the storage tanks were blocked in before the tank, but did not have drain points. Skin temperatures of 226°F (107°C) at the end of the pipeline and on the lateral sections indicated adequate transfer of chemical throughout without the need for any supplemental steam injection. The Vapour-Phase® of Zyme-Flow® continued for five (5) hours, after which the small amount of condensate was collected using two (2) vacuum trucks. Upon opening, the pipeline was found to be completely free of oil, LEL, benzene, H2S, and pyrophoric iron sulfides.

The only foreign material present was a minor amount of iron oxide scale.

Advantages of the Zyme-Flow® Vapour-Phase® Process for Pipeline Decontamination Relative to chemical cleaning approaches using liquid circulations and mechanical pigging, the Zyme-Flow® Vapour-Phase® Process offers the following advantages: • Significant time and cost reduction • Minimized mechanical footprint SPONSORED CONTENT

• Elimination of noise pollution • Minimized waste generation Furthermore, large circulation pumps, frac tanks, and mix tanks are not required.

Any oil emulsions quickly break upon quiescence with no further chemical treatment. The Zyme-Flow® Vapour-Phase® Process does not require pipe breaks that are normally associated with the use of pigs with 90° piping turns (eliminating concerns for possibility of chemical release).

The total job duration was three (3) days and the total cost of the project using Zyme-Flow® Process was a fraction of the original budget utilizing conventional liquid chemical cleaning/pigging practices.

DECON TECHNOLOGY

ZYME FLOW Contact information 12600 N. Featherwood Dr., Suite 330 Houston, TX 77034 USA Email: info@zymeflow.com www.zymeflow.com Phone: +1 832-775-1600 Fax: +1 713-672-3988

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FEELING THE PRESSURE FROM MACT?

The more than 100 members of the American Boiler Manufacturers Association think it’s time to take a look at the key facts about the Boiler MACT and its impact. Implementation may not be cheap or easy, but it’s entirely doable – and critically important for long-term public health, environmental quality, and business stability. ABMA members have been successfully meeting the challenges of tough air quality rules for more than a quarter century.

Please visit us online at boilermactfacts.com to learn more.

You’ll get more details plus contact information for ABMA members who can provide expert MACT implementation support.

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PROCESS CONTROL AND INFORMATION SYSTEMS

BONUSREPORT

Improve material balance in high-purity distillation control Using dual-composition conserved energy efficiency, reduced reprocessing and allowed higher throughput S. NINO, Summa Control Solutions Inc., Quebec, Canada

I

n this case history, a petrochemical facility needed to improve operation control as well as profitability for a benzene-toluenexylene (BTX) distillation train. The project focused on dualcomposition material balance controls. Improved process control from the new control system provided an annual $1 million in energy savings and reduced feedstock reprocessing needs.

Dual-composition material-balance control strategies were successfully implemented and commissioned for heat-integrated high-purity distillation towers at a petrochemical facility by using Shinskey’s methodology as guidance in the strategy selection.

Background. This petrochemical facility produces different aromatic components. The following control strategies were implemented on a unit comprised of a reactor, stabilization column and a BTX distillation train. The BTX train operated with great stability as long as there were no load disturbances. Feedrate, feed composition and enthalpy changes would cause long periods of instability; thus, this unit required constant operator attention.

The BTX train was working very close to the design limit; problems were more evident in the toluene tower operating very close to the flooding point. When considering options, the plant operation decided to implement an advanced regulatory control (ARC) solution based on results attained in a similar distillation train at another facility. This project included the first two towers, where the energy input to the benzene tower is from the cooling of the toluene tower boilup in a reboiler/condenser.

sensitive and more interacting. Sometimes unexpected dynamics and steady-state behavior can be observed due to transient and steady-state changes in internal vapor and liquid molal rates.

The original dual-composition control of the 55-tray benzene tower was an LV strategy-controlling the top composition from a temperature differential inference between the 41st and 45th trays—counting from the bottom—manipulating the reflux flow, L, and tray No. 9 temperature as a surrogate of the bottom composition to manipulate auxiliary steam supply, V. Only the bottom composition was controlled in the 72-tray toluene tower by using a cascade arrangement comprising temperature control and a near-infra red (NIR) analyzer located at the top of the xylene tower. An inference of the top composition was attempted by using the differential temperature across trays 57 and 65 to complete an LV strategy.

Heat removal yLH P PT

Qc Condenser

La

Accumulator

FC

FC D Distillate

L Reflux

Initial problem. High-purity distillation, dual composition

control, heat integration and pasteurization comprise a short and substantial statement that describes this process, which is deemed to be complex and challenging to control because: • High-purity distillation columns have been characterized by highly nonlinear behavior and are considered as of being beyond conventional linear feedback control.

• Dual-composition control has been questioned objected for many years due to the high interaction between the top and bottom composition controls.

• Heat integration makes the processes more intricate and prone to interactions as well as adding more complexity.

• Pasteurization, in distillation columns, makes the control inherently more difficult than with conventional columns since there are more degrees of freedom, product quality and materialbalance control loops. It is more complex, less direct, often more

AT

FI

D

MVs L B

Qc

XLK

F Feed

V Heat input Boilup Qr

V

C y V LK s La Lb P Lb Base

FC

xLK AT FIG. 1

B

Distillation column and variables definition.

HYDROCARBON PROCESSING NOVEMBER 2011

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PROCESS CONTROL AND INFORMATION SYSTEMS

The towers are heat integrated: Boilup in the benzene tower is provided by a reboiler/condenser that recovers latent heat from the boilup in the toluene tower while providing the condensing duty to the latter. The hot bypass around the reboiler condenser was open at around 30% on average, and over 3,000 lb/hr of auxiliary steam was supplied to the benzene tower.

The LV strategy resulted in higher interactions between the top and the bottom composition controls in the benzene tower.

This was not a problem for the toluene tower as it was working in a single-composition mode to maintain toluene impurities or bottom product below the maximum limits allowed in the downstream process.

Dual-composition control via material balance.

Typical distillation columns have five controlled variables (CVs): Bottoms light key (LK) concentration (xLK ), overhead LK vapor composition (yLK ), accumulator level (La), bottom level (Lb) and pressure (P). Five manipulated variables (MVs) exist: distillate flow (D), boilup (V), reflux flow (L), bottoms flow (B) and condenser heat removal (Q c ), as shown in Fig. 1.

Temperature probes located along the columns are usually used as surrogates for composition. Therefore, whenever the text refers to temperature, it will also be making reference to product composition. This scenario is a 5x5 multivariable-control problem with too many possible combinations to serve any practical TABLE 1. Benzene tower specifications KEY

Feed

Distillate

Bottoms

z%

y%

x%

Lighter

LLK

0.006

0.036

Light

LK

17.000

99.960

0.500

Heavy

HK

66.000

0.004

79.126

Heavier

HHK

16.994

20.374

Theoretical stages

36

D/F =

0.166

Reflux ratio (RR)

4.6

␣=

2.302

purpose in controlling a distillation column, especially when it comes to the simultaneous control of the top and bottom composition control due to the high degree of interaction there may be among them.

Back in the late 1960s and knowing that an off-the-shelf control strategy would not fit all distillation columns, Greg Shinskey began working in a methodology to assist in selecting the most suitable control design strategies.1–2 The method, based in the concept of material balance, matured with the conception of separation models and with the concept of internal decoupling.3–6 The method starts by taking advantage of the ability to reduce the 5x5 matrix to 2x2 subsystems because of the significant difference in the dynamic response of fast loops (accumulator level, top pressure and bottom level) with respect to slow responding composition control loops. The composition loops will not affect the fast loops, and the changes in the vapor-liquid traffic inside the tower will show up sooner in the liquid levels and pressure so they can be neutralized before influencing compositions (temperatures).

Assuming that the levels and pressures are in control, the next stage is calculating the relative gain array (RGA) as a metric of the interaction for multivariable process control (see the appendix for relative gain in a nutshell.)7 In the final step, a material balance, component material balance and a separation model are used to trace the column-operating curves at current or desired conditions. Five possible manipulated variables (MVs) are normally plotted: Reflux (L), Boilup (V), material balance line (D or B, as B = F – D so the slope is the same)—typically in ratio with the feed; and separation—S (L/D constant)—and boilup-to-bottoms ratio—R(V/B constant). A tabular display of the different relative gains (RGs) along with the column operating lines constitute the outcome and assist in the selection of the most appropriate control strategy for the distillation column.

Shinskey’s methodology has been used to drive the design of material-balance dual-composition control strategies for the benzene and toluene towers at this petrochemical facility.

Material-balance control in the benzene tower. The

0.010

S L

V R

D

0.009 yHK, mol-impurity at the top, %

0.008 0.007 0.006 0.005 0.004 0.003 0.002 0.001 0.000 0.000 FIG. 2

84

0.500 xLK, mol-impurity at the bottom, % Benzene tower operating curves.

I NOVEMBER 2011 HydrocarbonProcessing.com

1.000

feed to the benzene tower comes from the reactor stabilizer. Due to light non-aromatics, such as n-hexane, the benzene product is withdrawn from the pasteurizing section sidedraw located four trays down from the top plate, and the bottom product is mainly composed of toluene and xylene. Shinskey’s four components and two-product distillation model were used to characterize the benzene tower as explained here: The distillation column model requires: 1. Feed composition to the distillation column (maximum four components): light key (LK), lighter than light (LLK), heavy key (HK) and heavier than heavy (HHK). The top and bottom main products composition are assigned to be the LK and HK, respectively. The remaining components are combined as LLK, and the model takes the balance as the HHK. 2. Top and bottom specifications in terms of impurities in the distillate and bottom product, yHK and xLK , respectively.

3. Theoretical number of trays in the column; normally this quantity is found by correcting the actual number of stages by assuming an efficiency of 70%. The efficiency can be adjusted so the relative volatility nears what the actual value should be.

4. Reflux ratio (RR); defined as RR = L/D.

PROCESS CONTROL AND INFORMATION SYSTEMS Table 1 shows the entered values in red and those calculated in black.

The next step is calculating D/F from the material and component balance, followed by computing the relative volatility (␣) by using the separation model.5 The relative volatility is defined as the ratio of the light over the heavy key molar composition in the vapor phase with respect to the same light/heavy key ratio in the liquid phase when the mixture is at equilibrium. The operation curves are drawn by using this information. These curves cross at the product-composition specifications and represent the vaporliquid equilibrium relationship near the specs coordinates when a selected MV is held constant (Fig. 2). There are five possible MVs available to control the compositions: separation S (function of the reflux ratio), reflux L, boilup V, boilup/bottoms ratio (R = V/B ), and distillate D or bottoms B. The slope of each operating curve evaluated at the intersection of the operating top and bottom compositions can be found for each of the five possible MVs. The slope of the curve of the MV1 that would be used to control the top composition is calculated from: ∂y ∂x MV 1( y HK )

impurity specification of toluene in the benzene side-stream product, the relative gain would get up to about 148, indicating even more severe interaction, well in agreement with the higher degree of difficulty in controlling a column closer to specifications.

The almost vertical inclination of the material-balance line in the operating curves suggests that keeping either D/F or B/F constant will maintain a constant level of impurities at the bottom of the benzene column. This is also supported by the 0.998 value in the RG table.

The RG value for the DB strategy is plus or minus infinity, meaning equal effect of either product stream on the composition, as the two CVs are not independent variables. The practical limitation of the strategy is the impossibility of operating the two composition controls independently due to the lack of selfregulation. This would make the operation very unreliable.

Recommendations for the benzene tower. Since the material-balance control is the most desirable strategy, manipulating the top-product stream (D/F) can be used to control the light non-aromatics (NA) at the top as measured by the analyzer, and the sidedraw (Ds/F ) can be used to maintain benzene specifications at the bottom of tower. In the latter case, Tray 9 pressurecompensated temperature is used as a surrogate for the impurities composition. The loop performance will be affected by the long dead time caused by the delay associated on changes for the composition profile following feed changes. A lead/lag dynamic compensation was used to improve the control performance.

The slope of the curve of the MV2 that would be used to control the bottom composition is calculated from: ∂y ∂x

MV 2( x LK

)

TABLE 2. Benzene relative gains

Having calculated the six slopes, they can be used (two at the time) to fill up the 3⫻3 RG matrix, as shown in Table 2, by using the definition: ⎤ ⎡ (∂y ∂x ) MV 1( y HK ) ⎥ ⎢ λ y (MV 1, MV 2) = ⎢1− ⎥ ⎢ (∂y ∂x ) MV 2( x ) ⎥ LK ⎦ ⎣

Arranging the relative gains in a tabular format facilitates a quantitative comparison among the different possible dualcomposition control strategies.

By convention, a particular strategy description name is composed of two capital letters, the first refers to the MV selected to control the top composition and the second letter applies to the manipulated variable used to control the bottom composition, e.g., DV would be a dual-composition control strategy that manipulates the distillate and the boilup to maintain the top and bottom composition, respectively, at their corresponding setpoints.

From Table 2, it can be highlighted the high value of 23.69 for the RG (one being ideal) associated to the original configuration (LV ); this would explain the fragile operating stability of this column. Both curves appear very close to each other, indicating that the change of either MV would have a similar effect in both compositions, and a significant degree of interaction.

Repeating the RG calculations using the

BONUSREPORT

D [D/F]

−1

MV1r x

MV2 r y L [L/F]

S [L/D]

B [B/F]

⫾⬁

0.998

0.998

V [V/F]

0.002

23.693

4.233

R [V/B]

0.002

11.735

3.696

PT

PC PC

FC

La FC

72

55 f(t) FI

FC

51 FC

F

F

30

∑ –

FC

Toluene 4

PTC

FC

1 LC

X

TC

28

X

9

FC

71 65

f(t)

1 PT

Steam

HC

V

FC LC

Steam

Benzene X TC

FIG. 3

FC

To xylene tower

Benzene-toluene dual composition material balance control.

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BONUSREPORT

PROCESS CONTROL AND INFORMATION SYSTEMS

The number written in red in Table 2 also indicates that the best MV to control the impurities at the bottom would be its own flow, leaving the bottom level to be controlled by the reboiler heat input. However, the heat integration made this impossible, as the boilup rate in both columns is driven by the toluene tower.

The auxiliary reboiler at the bottom of the benzene tower had a very narrow rangeability to effectively control the level in the bottom of the column. The near vertical material balance line (D/F ) means that the amount of benzene at the bottom will remain constant if the sidedraw is kept constant with respect to the feed.

Using the side draw to control the benzene content at the bottom of the tower left the overhead accumulator level to be maintained by the reflux. This provided an added benefit of handling the feed and reflux enthalpy disturbances internally, and therefore, preventing them from translating into changes in the external material balance, especially with varying product compositions.

Commissioning war stories. The toluene tower was

selected as the commissioning starting point. However, the earliest activity ended up being the verification that the auxiliary reboiler was not needed to trim the boilup in the benzene tower.

Preliminary work performed during the feasibility study had already pointed in that direction. A startup control strategy completed the design to provide the required energy for the benzene tower during a cold startup.

TABLE 3. Toulene tower specifications Feed z%

Distillate y%

Bottoms x%

4.5

Material-balance control in the toluene tower. Feed to the toluene tower is the bottom product of the benzene tower.

The top product leaving the column is toluene, and the bottom product is mostly xylene and heavier materials. The top product is withdrawn through the distillate and from the second tray from the top. Both streams are mixed right after leaving the column; the purpose of this split of the top product is to reduce the energy required to reheat this stream as it proceeds to the next downstream unit. The bottom product is a low-concentration xylene that will go into another processing unit for further purification.

Once again, the four-components model was used by selecting the light and the heavy keys to be controlled in the withdrawn products and by lumping the other components to either the lighter than light or heavier than heavy key as required to main-

4.0

TABLE 4. Toulene relative gains

Key Lighter

LLK

3.300

3.992

Light

LK

78.400

94.608

1.100

Heavy

HK

17.400

1.400

93.708

Heavier

HHK

0.900

5.192

Theoretical stages Reflux ratio (RR)

5.0

yHK, mol-impurity at the top, %

The material-balance control at the top of the tower requires having the overhead accumulator inventory controlled by the reflux rate and the composition control manipulating the top product stream. This action provides a tower with self-regulation capability that will help maintain the composition profile throughout the tower.

Controlling the benzene impurities at the bottom of this tower by inference for Tray 9 liquid temperature and manipulating the top side draw, Ds, was challenging. However once the process dynamics were modeled as a distributed interacting lag process, it was possible to find load rejection optimum tuning parameters that minimized the integrated absolute error (IAE).

The successful control of benzene impurities at the bottom of the tower resulted in a much lower light non-aromatic content in the sidedraw and in an increase of the benzene product. Thus, the proposed NA control with the distillate became unnecessary.

The bottom-level control was tuned to use this capacity as a surge tank. The overhead accumulator controller minimized the dynamic response and helped in promptly returning the product composition to steady state. Fig. 3 displays the details of the control strategies implemented on the two towers.

The dynamic compensation between the feed to the benzene tower and Tray 9 pressure-compensated-temperature control in the benzene tower consists of a lead/lag circuit. It is intended to speed up the response of the side draw by compensating for the hydraulic and composition lag associated with the location of the thermal sensor, the feed tray and the sidedraw tray.

S

L

50

D/F =

0.827

0.421

␣ =

2.350

V

3.5 3.0

D [D/F]

R

2.5

D

2.0

S [L/D]

MV1r x

B [B/F]

⫾⬁

0.104

0.142

MV1r x

V [V/F]

0.984

1.158

1.107

R [V/B]

1.586

0.240

0.309

1.5

TABLE 5. Toulene tower relative gains—target case

1.0 0.5 0.0 0.0

FIG. 4

86

MV2 r y L [L/F]

D [D/F] 0.5

1.0

1.5 2.0 2.5 3.0 3.5 4.0 xLK, mol-impurity at the bottom, %

Toluene tower operating curves.

I NOVEMBER 2011 HydrocarbonProcessing.com

4.5

5.0

MV2 r y L [L/F]

S [L/D]

MV1r x

B [B/F]

⫾⬁

0.145

0.168

MV1r x

V [V/F]

0.912

2.347

1.922

R [V/B]

1.280

0.436

0.480

PROCESS CONTROL AND INFORMATION SYSTEMS tain the feed material balance. Table 3, where values written in red are entered into the model and those written in black are calculated, depicts the results for the toluene tower.

The operating curves in this case are much more spread than those for the benzene tower, as shown in Fig. 4. The material balance D/F appears more horizontal, indicating that the top-product flow would provide the best alternative to control the impurities at the top of the tower, namely the xylene. And the V/F curve almost vertical at the intersection indicates that using the boilup (V ) to control the light material at the bottom will provide dual composition with almost no interaction. The recommended strategy is for a material-balance DV strategy where both streams will be ratioed by the feed.

The RG table displayed in Table 4 confirms that a DV strategy has a relative gain of almost one, indicating minimum interaction.

It is important to note that some other strategies would give a reasonable relative gain, and this includes the LV strategy; for that reason, a second case can be run for the model in order to reassure the choice of DV, as indicated by the number in red in Table 4.

The product target case was then run in order to reassess the recommended strategy, yHK = 0.75% and xLK = 0.7%. The operating curves spread did not change noticeably, and the RG corresponding to the DV stayed close to one as in the prevailing operation; whereas that of the LV almost doubled, indicating an increase in the interaction when both product compositions are controlled simultaneously closer to the specifications, as shown in Table 5.

Recommended control strategies. Assisted by the opera-

Δ Ttop

tion curves and relative gains, a DV scheme was sketched showing that the column pressure control MV was to be switched from the distillate to the reflux. The top temperature differential was set to control the top composition by readjusting the distillate to feedrate ratio. The material balance scheme at the top of the tower was set to be controlled by the total top product, namely distillate D and sidedraw Ds. Since the Ds setpoint was intended to reduce the energy needs of the reactor feed surge tank, the Distillate D was selected to be the MV used to maintain top composition and, at the same time, to maintain the material balance by adjusting its setpoint as required to compensate for the variations in the side stream flow adjustments.

The impurity in the bottom product was intended to be controlled by controlling Tray 4 temperature by regulating the boilup-

to-feed ratio, while the temperature target would be reset by the analyzer located at the top of the xylene tower.

A dynamic compensation was also provided in the strategy to compensate for the hydraulic lags associated to the liquid moving from the feed tray to the bottom of the tower. The vapor lag time is insignificant with respect to the hydraulic lag. In consequence, a single dead time plus lag time compensator is used for both composition controllers.

More commissioning war stories. As explained earlier, the commissioning of the heat-integrated towers began with the toluene tower being the only energy source for both columns.

Thus, shutting off the reboiler-condenser hot bypass eliminated the 1.5-minute oscillation that was limiting the control loops to be tuned for high performance.

The inventory of the overhead accumulator in combination with the reflux flow creates a dynamic response similar to a firstorder system with a large time constant. This inertia is translated in self-regulation, and this property indicates the convenience of putting in service the controls at the top of the distillation column before anything else. From possible alternatives provided by the RG table, the final choice will come from the validation of the strategy against the process particulars and constraints.

One of the paradigms in controlling high-purity distillation composition by temperature inference is using differential temperatures. One sensor was located in the control plate and the other one a few trays away from the former. There is nonetheless a gray side to it; the differential temperature across several plates in a distillation column follows a concave downward relationship.

At low reboiler heating rate, the top product flowrate is low and very pure, causing the ΔT to be small. High rates in the reboiler heating will cause most of the light material to go to the top product, making the ΔT small as well, with a consequent maximum in between as indicated by the curve in Fig. 5. At this site, the production rate being pushed to the maximum feedrate to the column, combined with high reboiler heating rates, made the relationship fall on the “wrong” side of the curve.

Tray No.

2.8 2.6 2.4 2.2 2.0 1.8 1.6 1.4 1.2 1.0 0.8 0.6 0.4 0.2 0.0 0

FIG. 5

1

2 yH (p-xylene in toluene)

3

Composition vs. differential temperature.

4

BONUSREPORT

70 67 64 61 58 55 52 49 46 43 40 37 34 31 28 25 22 19 16 13 10 7 4 1 280

FIG. 6

ΔTtop R e c t i f y

Feed tray

290

300

310

320 330 340 Temperature, °F

S t r i p 350

360

370

380

Toluene tower temperature profile.

HYDROCARBON PROCESSING NOVEMBER 2011

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BONUSREPORT

PROCESS CONTROL AND INFORMATION SYSTEMS

Disturbances in the L/V ratio can make the relationship get over the maximum point and cause the ΔT control loop to have positive feedback and generate an exponential runaway. The attempts to get the relation to be on the normal side of the curve, the side where increases in ΔT will be proportional to the impurities in the distillate product, resulted in an upset composition profile in the tower, possibly due to the flatness of the temperature profile in that column section.

Toluene tower rectifying section temperature profile was too flat to provide a reliable signal, as shown in Fig. 6. The field testing also showed a poor and nonrepeatable correlation in the temperature difference between Tray 65 and Tray 57. Therefore, using the differential temperature as an inference for the impurities at the top of the toluene tower was ruled out. A single-point temperature, Tray 65, was chosen as a subrogate of the xylene in the toluene exiting as distillate product from the toluene tower.

When working with an actual column in a facility, the only option is to work with what exists, and this circumstance put to the test another paradigm in column distillation control; this time, it was related to the use of temperature sensors located on control trays as opposed to the ends of the column.

In distillation, the nonlinear vapor-liquid equilibrium (VLE) relationship among the different species for a mixture makes the product composition gain to change directly with key impurity levels following a logarithmic relationship. However, when investigating why the temperature probe located in Tray 9 in the toluene tower was not a reliable controlled variable, it was found that the relationship followed a hyperbolic, rather than logarithmic, relationship (Fig. 7).

Considerable change in steady-state gain and lack of sensitivity are among the reasons that led to the discarding of this temperature location for composition control. The temperature sensor located at the outlet pipe downstream from the pump end provided a more repeatable and linear relationship that was eventually used to control the impurities at the bottom of the toluene tower.

The composition feedback control using the NIR analyzer at the top of the xylene tower was not commissioned; the facility management deemed that the inference of the bottom composition with the temperature alone was good enough. Also, the signal-to-noise ratio was too low; so, it would have caused preventable moves in the heat input.

The control strategy for the tower was complemented with a differential pressure-control override intended to cut steam 2.0 Toluene, % on top of tower

1.8 1.6

Outcome. Dual-composition material-balance control strategies have been successfully implemented and commissioned for two heat-integrated, high-purity distillation towers by using Shinskey’s methodology. In this case, energy savings of 55,000 Btu/yr and 86 Mbbl/yr of additional benzene products, de-bottlenecking of the toluene tower, and operation attention reduction were realized; this application took six weeks, including the feasibility study.

Energy balance control, composition variables online linearization, differential temperature measurement as surrogates of composition, and control plate temperature as opposed to end temperature are among the paradigms that did not hold for this application. Working in real life with economic-driven production facilities will require roaming into uncharted territories.

This proved to be the case during the execution of this project.

Optimum tuning, although seemingly irrelevant, was essential for achieving dynamic responsiveness. In particular, unless inventories are controlled precisely, there can be no steady state for the process. HP LITERATURE CITED Shinskey, F. G, “Material-balance control of multiproduct towers,” Oil and Gas Journal, July 28, 1968.

2 Shinskey, F. G., “The material-balance concept in distillation control, Oil and Gas Journal, July 14, 1969.

3 Shinskey, F. G., Distillation Control for Productivity and Energy Conservation, 2nd Ed., McGraw-Hill, 1982.

4 Shinskey, F. G., “Multivariable Control of Distillation,” Control, May 2009.

5 Jafarey, A., J. M. Douglas, and T. J. McAvoy, “Short-cut Techniques for Distillation Column Design and Control. Part I. Column Design,” Ind. Eng. Chem. Proc. Des. Dev., Vol. 18, No. 2, 1979.

6 Ryskamp, C. J., “New strategy improves dual composition column,” Hydrocarbon Processing, June 1980.

7 Bristol, E. H., “On a New Measure of Interaction for Multivariable Process Control,” IEEE Trans. Auto. Control., AC-11(1), 133, 1966.

1

BIBLIOGRAPHY Bojnowski, J. J., R. M. Groghan Jr., and R. M. Hoffman, “Direct and Indirect Material Balance Control,” Chemical Engineering Progress, Vol. 72, No. 9, 1976.

McAvoy, T. J., Interaction Analysis. Interaction Analysis: Principles and Applications, Monograph series / Instrument Society of America, 1983.

Rademaker, O., J. E. Rijnsdorp and A. Maarleveld, Dynamics and control of continuous distillation units, New York, Elsevier, 1975.

1.4 The appendix can be found at HydrocarbonProcssing.com.

1.2 1.0 0.8

Sigifredo Nino, formerly with Invensys, is now a process control consultant

0.6 0.4 0.2 0.0 350

FIG. 7

88

input to the tower should the ΔP exceeds its setpoint, not shown in Fig. 3 for clarity reasons. The override is to protect the tower from flooding.

Online-pressure compensation of the top temperature was attempted. However, the location of the sensors with respect to each other caused an interaction loop to develop, provoking the controls to oscillate. Since inventory control at the top of the tower had to be tuned for performance, the deviations from setpoint were small enough to make unnecessary the compensation.

355

360 365 Temperature tray, no. 9, °F

370

Toluene tower Tray 9 temperature vs. toluene at the top of the xylene tower.

I NOVEMBER 2011 HydrocarbonProcessing.com

with Summa Control Solutions Inc. He has over 28 years of refining, petrochemical, power, pulp and paper, mining and food industry experience. His practice has taken him throughout all instrumentation and control for the process industry spectrum, spanning from specification and installation of field devices through the design, implementation and commissioning of regulatory and advanced control applications. He has given university-level courses in the subject matter of his expertise and authored several technical papers for conferences and magazines. He is currently engaged in process control performance assessment and optimization for oil refining, petrochemical and power industries. Mr. Nino holds a BS degree in Electrical Engineering from the University of Los Andes, Bogota, Colombia.

PROCESS CONTROL AND INFORMATION SYSTEMS

BONUSREPORT

Safety instrumented function design reduces nuisance trips Implementing low-cost best practices can provide peace of mind A. KERN, Wilmington, California

A

conundrum frequently facing safety system designers and plant managers is whether to use two transmitters in a one-out-of-two configuration (1oo2) or three transmitters in a two-out-of-three configuration (2oo3). While both configurations may satisfy the safety requirements, 2oo3 is traditionally considered the only choice when nuisance trip reduction is also a high priority, despite its higher cost, greater contribution to probability of failure on demand (PFD), and often, a sense of transmitter overkill.

In recent years, the concepts of diagnostic coverage, discrepancy alarms and transmitter self-diagnostics have gained acceptance and become proven in use. This trio of concepts gives 1oo2 greatly improved performance with regard to nuisance trip reduction. In many regards, 1oo2D (1oo2 with diagnostic coverage) is the new 2oo3.

In addition, as end users continue their migration from switches, “dumb” transmitters and relay-based safety systems to smart transmitters and PLC-based safety systems, some often over-looked low-cost practices can be adopted as further insurance against nuisance trips.

Making the right choices in any particular safety application remains a multi-faceted question. It is a function of safety integrity level (SIL), the importance of nuisance trip prevention, life-cycle cost, inherent difficulty of the measurement, peace of mind and safety competency. But, as a guideline, 1oo2D can give comparable or better performance than traditional 2oo3. Even 1oo1D can provide excellent PFD and probability of nuisance trip (PNT) performance in many applications. Add to this some fundamental competency practices and nuisance trips can be largely eliminated.

Background. The design of safety instrumented functions

(SIFs) is initially based on achieving the required safety integrity level (SIL), leading to the selection of one, two or sometimes three redundant transmitters (Fig. 1). In recent decades, the safety community has rather brilliantly formalized and quantified this process according to ISA 84.01/IEC 61511, “Safety instrumented systems for the process industry sector.”

Secondly, the SIF designer must also consider the acceptable level of spurious (or nuisance) trips, which is the likelihood the safety function will activate unnecessarily, causing anything from a minor nuisance to a severe operational or economic penalty. In recent years, awareness has grown that nuisance trips also carry safety penalties. This is because even though, in theory, a trip is assumed to result in a safe state, a high proportion of incidents

have been found to occur during plant startup or restart activities.

Nuisance trips. Unfortunately, the safety community has not yet found a methodology to fully address the nuisance trip aspect of SIF design. Methods are available to predict the expected frequency of nuisance trips—namely mean time to failure spurious (MTTFS)—but not to determine an acceptable level for any particular SIF function. Spurious trip level (STL) has been proposed, but as a purely economic function, it has limitations, including difficulty in assigning cost, differences in cost scale from one site to another and a lack of factoring safety or other non-economic negative impacts of spurious/nuisance trips. A practical performance goal is that a safety function should not result in more nuisance trips than true trips.

What are the options available to reduce the probability of a nuisance trip (PNT), after the SIL level has been satisfied?

Historically, the only design option has been 2oo3, due to its inherent fault-tolerance (one transmitter can fail outright and the SIF will continue to function safely as a 1oo2, without a nuisance trip, while the failed transmitter is repaired). But in today’s world, with “smart transmitters” and other forms of diagnostic coverage, there are alternatives that can provide similar or superior performance over 2oo3, in terms of both PFD and PNT, without the spectacle (and cost) of either hanging three transmitters in the field for every SIF or leaving yourself exposed to the possibility of excessive nuisance trips.

Diagnostic coverage. Diagnostic coverage is the ability to proactively detect faults and respond safely, preferably without a nuisance trip. For transmitters, it comes in two common forms— self-diagnostics and discrepancy alarms.

Transmitter self-diagnostic coverage is the percentage of transmitter (or measurement) faults that can be detected by the transmitter itself. For common smart transmitters, whose selfdiagnostics have been steadily beefed up over the years, coverage is often in the range of 50%. For “safety” transmitters, which are certified for use according to SIL level, and which typically have greater self-diagnostics, measurement diagnostics (such as detection of impulse line pluggage) and more rigorous manufacturing quality controls, coverage can be in the range of 90%. The coverage determination comes from the manufacturer’s failure modes and effects diagnostic analysis (FMEDA) testing and review by a certifying agency.

Discrepancy alarms. Discrepancy alarms are deviation alarms between redundant transmitters. For example, in a 1oo1D configuration, the SIF transmitter and the control system transmitter are HYDROCARBON PROCESSING NOVEMBER 2011

I 89

BONUSREPORT

PROCESS CONTROL AND INFORMATION SYSTEMS

SIL and SIF basics

SIFs can be thought of as safety loops, because they have a lot in common with control loops—they comprise sensors (such as transmitters), final elements (such as valves), and a safety algorithm, usually a fairly straight-forward piece of logic. But rather than doing process control, the purpose of SIFs is to increase process safety (or reduce risk). When the sensors indicate a potential unsafe condition, the final elements are activated (or deactivated) to bring the process to a safe state, such as shutting down a heater on high temperature. To help achieve the required reliability, SIFs are usually implemented in a safety instrumented system (SIS) that is separate and independent from the basic process control system (BPCS or DCS).

Each SIF is designed to meet a specified SIL, which is basically a level of reliability. A SIL1 SIF must work at least nine times out of 10, thereby providing a risk reduction factor (RRF) of 10 and a probability of failure on demand (PFD) of 0.1. A SIL2 SIF must work at least 99 times out of 100, thereby providing a RRF of 100 and a PFD of 0.01. And a SIL3 SIF must work at least 999 times out of 1,000.

Practically speaking, it is difficult to design a SIF with greater reliability than SIL3. SIL4 is considered largely unachievable in the context of most conventional industry practices. Where this level of risk reduction is found to be necessary, it is recommended to investigate an inherently safer process design or alternative layers of protection.

For a given process, the necessary SIFs and their required SIL levels are determined within the safety life-cycle management framework defined by ISA 84.01/IEC 61511, “Safety

PT 100

>100 psig

PT 100A

>100 psig

PT 100B

>100 psig

PT 100A

>100 psig

PT 100B

>100 psig

PT 100C

>100 psig

PT 100A

>100 psig

PT 100B

>100 psig

PT 100C

>100 psig

1oo1, SIL1 or SIL2

OR

FIG. 1

2oo3

OR

1oo2, SIL2 or SIL3

2oo3, SIL2 or SIL3 (dual valves)

1oo3, SIL3 (dual valves)

Typical transmitter configurations for various safety integrity levels (SILs) for a safety instrumented function that trips valve(s) on high pressure.

compared and a deviation greater than, say, 5% of span is alarmed, prompting maintenance to resolve the discrepancy before it grows and leads to a nuisance trip. This simple concept is powerful in 90

I NOVEMBER 2011 HydrocarbonProcessing.com

instrumented systems for the process industry sector,” especially within the process hazard and risk analysis step. The SIL rating of any SIF depends on a reliability analysis of all loop components, demand frequency, proof test interval, diagnostic coverage, human factors and other considerations.

As Table 1 and Fig. 1 show, a single transmitter will usually suffice for a SIL1 SIF. For a SIL2 SIF, a single transmitter may suffice if demand frequency is low and the measurement is reliable. Or, two transmitters may be necessary if demand is high, and this may, in turn, require a third transmitter to prevent excessive nuisance trips, if the measurement is difficult or there is no diagnostic coverage.

Protective functions are very similar to safety functions in design, but their purpose is to protect against equipment damage, without safety implications. Protective functions often fall under the same engineering and management practices as SIFs, but greater user discretion is allowed with regard to cost vs. reliability, since money, not safety, is at stake. For brevity, the term SIF in this article encompasses safety and protective functions.

The vast majority of SIFs in industry are demand mode, meaning that upon detection of unsafe conditions, the function is triggered, placing a “demand” on the SIF. In this way, a SIF with an undetected dangerous fault may not result in a failure on demand if no demand occurs, i.e., if the fault is found and remedied without a demand occurring. A continuous mode SIF is one that results in a hazard immediately if it becomes unavailable, such as GPS-based positioning systems on (unanchored) deepwater drilling rigs. HP terms of diagnostic coverage. A discrepancy alarm involving two transmitters may be credited with up to 90% diagnostic coverage, and an alarm involving three transmitters can bring up to 99% coverage. Because it is valid to include control system transmitters in the discrepancy alarm, discrepancy alarm coverage is possible even for 1oo1 SIF configurations.

Discrepancy alarms have limited ability to protect against sudden transmitter or measurement failures, since the response mechanism to a discrepancy alarm involves normal maintenance and troubleshooting procedures. But many transmitter faults are gradual, such as calibration drift or impulse line pluggage, so that a discrepancy alarm can occur and be resolved before a nuisance trip results. A discrepancy alarm is not considered a transmitter failure, does not remove any of the transmitters from the voting logic, and does not result in a transmitter upscale/downscale response, as a self-diagnostic fault would.

Fault tolerance without 2oo3. Diagnostic coverage brings fault tolerance to 1oo2 configurations. These configurations have traditionally lacked fault tolerance, which was a major Achilles heel. Self-diagnostics, combined with configurable fail direction (upscale or downscale), means transmitters in a 1oo2D configuration can be configured to fail in the non-trip direction and the SIF will continue to function as a 1oo1 until the faulty transmitter is repaired. In this way, 1oo2D has fault tolerance to the extent of its diagnostic coverage, often 90–99%.

The new math. Fig. 2 shows comparative figures for traditional dumb transmitter-based configurations and for smart transmitter-based configurations with diagnostic coverage. The

INFORMATION SYSTEMS

Know-how for Your Success

numbers represent the relative effect on PFD and PNT due to transmitter redundancy choice. This is based on transmitters with a 1% probability of causing either a failure on demand (a dangerous undetected fault) or a nuisance trip (a safe detected fault).

As the numbers indicate, when diagnostic coverage is factored in, the effect is to transform safe detected faults, to the extent of the diagnostic coverage, into alarms that will trigger transmitter maintenance, rather than trigger nuisance trips.

Of course, 2oo3 performance similarly improves with diagnostic coverage, but its main strength is fault tolerance, and cases where 2oo3 performance is inadequate have been rare. So while 2oo3 would stay ahead of the pack under this new math, it would do so by exceeding requirements (and one might as easily say that the difference is outweighed by regaining the superior PFD values of 1oo2). As Fig. 2 shows, in terms of meeting requirements, providing fault tolerance and avoiding nuisance trips, 2oo3 today has a lot of company.

The math isn’t exactly new, either. Manufacturers of safety transmitters have been advertising 1oo2D as an alternative to 2oo3 for over 10 years, but traction has been spotty for several reasons. The primary focus in the safety community over this period has been PFD, not PNT. Industry adoption of smart transmitters and smart logic solvers has, of course, been gradual. And end-users in the field are slow to update their working paradigms. But this topic has great currency for the increasingly large number of end users who today find themselves with smart safety logic solvers and smart transmitters in place. This step, along with turning to ISA 84.01/IEC 61511 for greater guidance, can help improve all aspects of the safety system life-cycle performance.

Safety competency. 2oo3 also has the virtue of compensating for shortcomings in safety competency. But this may be only perceived, and may not be a virtue. Most nuisance trips are found to be preventable, which means that some aspect of the safety management life cycle has been neglected. Adding more transmitters may not be money well spent, and may simply lead to more problems, where a neglected or overlooked safety competency is the root cause. Elements of safety competency include: • Independent pre-trip alarms • Implementation of diagnostic coverage and discrepancy alarms

With over 50 independent subsidiaries and over 220 engineering and sales offices spread across the world, SAMSON ensures the safety and environmental compatibility of your plants on any continent.

1.00 1.00

0.20 0.03 0.03

0.01

0

1oo1 1oo2 (No diagnostic coverage)

FIG. 2

2oo3

0.01

0.01 0.02

1oo2D (90%)

1oo2D (99%)

0.1 0.1

1oo1D (90%)

Comparative effect on probability of failure on demand (PFD) and probability of nuisance trip (PNT) due to transmitter configuration based on transmitters with a 1% probability of causing each. 1oo1, 1oo2 and 2oo3 reflect traditional analysis based on transmitters with no diagnostic coverage. 1oo1D and 1oo2D reflect smart transmitters with various levels of diagnostic coverage, including coverage by discrepancy alarms.

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A01051EN

Percentage

1

High-quality control valves and accessories with low cost of ownership are what it takes for economic production.

PFD(xmtr) PNT(xmtr)

2.00

2

Due to global competition, companies can only be successful on the marketplace if they produce outstanding quality cost effectively.

SAMSON AG · MESS- UND REGELTECHNIK Weismüllerstraße 3 60314 Frankfurt am Main · Germany Phone: +49 69 4009-0 · Fax: +49 69 4009-1507 E-mail: samson@samson.de Internet: www.samson.de SAMSON GROUP · www.samsongroup.de

BONUSREPORT

PROCESS CONTROL AND INFORMATION SYSTEMS

• Timely response to self-diagnostic and discrepancy alarms • Configuration control of 1oo2D fault tolerance (upscale/ downscale) • Reliable best practice field instrument installation • SIF proof testing program • Appropriate use of time delays • Real-time monitoring of smart transmitter diagnostic alerts • Effective DCS/SIS communication link and HMI design • Elimination of switches, which defeat diagnostic coverage principles • Reliable wiring (wiring ideally makes a negligible contribution to faults).

At first glance, this may appear to be a long list of complicated competencies, but most of them fall into place naturally as users move to safety-PLC based safety systems and smart transmitters. The challenge facing most end users today is to institute a culture of awareness and management of safety competencies.

The competencies themselves are mostly fundamental and are a TABLE 1. Summary of safety integrity level (SIL), risk reduction factor (RRF), probability of failure on demand (PFD) and common field device configuration Reliability

RRF

PFD

Transmitters

Final elements

1

> 9 out of 10

10

0.1

1oo1

1oo1

2

> 99 out of 100

100

0.01

1oo1, 1oo2, or 2oo3

1oo1 or 1oo2

3

> 999 out of 1,000 1,000

0.001

1oo2, 1oo3, or 2oo3

1oo2

Recommendations. While all of ISA 84.01/IEC 61511 and the safety competencies listed previously are important, a productive, low-cost starting strategy to reduce nuisance trips is to verify: • At least two transmitters and a discrepancy alarm on every SIF • Reliable best practice field installation • Proper upscale/downscale design and configuration control.

In terms of selecting the number of transmitters, use these guidelines: • Use 1oo2D as the normal starting point for SIL2 applications.

• Consider 2oo3 where nuisance trip prevention is overriding, or where measurement reliability is poor and multiple rapid measurement failures are possible, such as dirty, viscous or plugging service, or very weak signal strength.

• Consider 1oo1D to improve SIL1 performance, and as a simpler approach to SIL2, where the measurement is inherently reliable, such as a clean, low viscosity, low temperature service with robust signal strength. HP

I

SIL

product of ISA 84.01/IEC 61511 guidance, rather than a challenge in its compliance.

Note that while a computer-based logic solver is surely best practice in today’s world, the benefits of diagnostic coverage can be captured even with legacy relay-based SIS systems by dialing in the appropriate configuration of upscale/downscale transmitter failure and implementation of discrepancy alarms in the control system (assuming SIF transmitters are brought into a modern DCS for monitoring).

M

O V

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MAINTENANCE/HEAT TRANSFER

Investigation: Failure of a steam generator In this case history, engineers search for the root cause of water-side tube failures for a 23-year-old boiler A. BABAKR and A. K. BAIRAMOV, Saudi Basic Industries Corp., Al-Jubail, Saudi Arabia

T

his case history investigated the water-wall tube failure of a boiler (steam generator) that had been in service. At this stage of the boiler’s life cycle, this steam generator was experiencing several leaks. The failed tubes were examined to uncover the root cause of the tubes’ bulging and leaks. The investigation results revealed that a 1-mm thick deposit in the inner surface of the water-wall tubes was the root cause for the tube failures.

Analytical methods such as x-ray fluorescence (XRF) and x-ray diffraction (XRD) scanning electron microscope (SEM)/elemental analysis (EDX) uncovered that the scale contained elements typical of boiler feedwater (BFW) side composition along with iron oxides.

The failure mechanism was identified and rationalized in terms of operating conditions. Tube cleanliness was also considered in the failure mechanism. In this case, the water-wall tube failed due to creep rupture from localized overheating caused by the presence of excessive internal deposits.

The majority of BFW tube failures are often attributed to poor or improper boiler feedwater chemistry. The steam generator in question is a medium-pressure boiler that has been in service for at least 23 years. Operating pressure was 609 psi (42 bar gage, design—46 bar gage) and operating temperature was around 487.8°F (253.2°C), while design was 498.9°F (259.4°C).

Some water-wall tubes had bulged and identified by a visual internal inspection. The affected tubes faced the hot gas (natural gas) burner. Previously, the plant had faced problems with BFW quality issues; recently, its parameters had significantly improved.1–3 The steam generator was never before chemically cleaned and retubed. The water-wall boiler tubes are made from carbon steel SA-178-A. They were 2 in. (50.8 mm) in diameter and 0.105 in. (2.7 mm) thick.

There were no heavy and/or loose deposits on the outer surfaces of the tubes. When the tubes were visually viewed from one end, it was noticed that the deposit had covered the entire inner surface. This was true for all three tubes; this assumption was applied to all remaining tubes within this boiler. To better understand the extent of the deposits, the tubes were split axially to reveal the inter condition, as shown in Figs. 2 and 3. The deposit was very hard and resistant to being removed by a simple

INVESTIGATION

As shown in Fig. 1, three tubes were investigated. The first tube showed multiple bulges (Fig. 1, middle) on the tube’s hottest side facing the boiler flame path. Openings (ruptures) were found on the apex of these bulges. The second leaking tube immediately faced the burner (rear wall). The third tube (Fig. 1, bottom) was undamaged and located on the side of the boiler wall. This tube provided a base case for comparison and assessment reasons. The tubes’ thickness away from the bulged areas did not show significant thinning/damages caused by corrosion during the long time in service.

FIG. 1

Common photographs of the boiler water-wall tubes showing multiple bulging (top and middle). The leaking middle tube immediately faced the burner. The other tube with bulging was a side-wall tube. The tube with no bulging (bottom) was a side-wall tube.

HYDROCARBON PROCESSING NOVEMBER 2011

I 95

MAINTENANCE/HEAT TRANSFER bristle. The scale was later mechanically removed by knife. Once the scale deposit was removed, the extent of deposit buildup is shown in Fig. 2. There was other damage, such as pitting or cracking beneath the removed deposit. The thickness of the deposit was measured by electronic caliper and was about 0.0374 in. to 0.393 in. (0.95 mm to 1.0 mm).

Samples from different locations along the tubesâ&#x20AC;&#x2122; lengths were taken for metallographic examination. Metallographic examination (light optical microscopy) revealed the cross section condition of the chemically etched samples. The samples were viewed on both sides of ID and OD. Micro-analysis. Microstructural analysis focused on microstructural integrity, creep signs (presence of voids and cementite spheroidization), aligned carbides or microcracks. It also looked for any signs of microstructural damage. In general, a normal microstructure with a ferritic matrix and pearlite grains was found

in unfailed/intact samples. No voids/pores were present in any of the samples; accordingly, the material did not reach the advanced stage of creep. However, it was clearly observed that the pearlite phase for the damaged/bulged tube had significantly spheroidized.

The region with the highest exposure to flame impingement had the highest percentage of transformed pearlite, as shown in Figs.

4B to 4D. Fig. 5 shows a cross-section of a bulging area with enlarged/coarse grains due to high temperatures. Fig. 6 shows an optical micrograph of a cross-section where a leaking occurred (the most bulged tube), as shown in Fig. 1 (middle tube). Cracking had propagated through joining creep voids and also where only creep evidence has been noticed. Numerous parallel fissures developed.

Both sides of the internal deposit surfaces were analyzed with SEM: the top side facing the boiler water (Fig. 7A) and the bottom side (Fig. 7B) that was attached/adjacent to the tube surface.

Both sides exhibited the presence of dense layers. Surface morphology exposed to the water (Fig. 7A) showed uneven surfaces; with agglomerated, rounded areas with incorporated separate small solid (whitish) particles on the outer surface and cracks (Fig. 7B.) The surface of the bottom side showed a more uniform darker appearance, and it was also composed of clearly pronounced rounded areas.

X-ray viewing methods. EDX results are listed in Table 1

and Fig. 7. The results show that both tube sides had high presences of oxygen (O), calcium (Ca), carbon (C) and phosphorus (P), along with some sodium (Na) and magnesium (Mg) although iron (Fe) was found in small amounts, its content in the bottom side was higher. Generally, elemental composition of both the analyzed side of the deposit was quite similar, while concentrations were slightly different. These elements originated from the boiler water side.

SEM micrographs revealed typical spheroidized pearlite in the bulged sample (Fig. 8A), while a normal ferrite-pearlite microstructure with platelets of iron carbides in pearlite was found in the intact sample (Fig. 8B).

FIG. 2

Photograph showing closer look at the middle tube bulging (A) in Fig. 1. The same tube after halving (B). Note: Heavy deposits covering the inner surface and dislodged part of the deposit at the bulge.

FIG. 3

Photograph showing no other apparent corrosion damage after mechanical removing of the deposit.

FIG. 4

96

I NOVEMBER 2011 HydrocarbonProcessing.com

Light optical micrographs showing microstructural variation, sample tube not affected (A); from tube with minimal bulging (B); C and D from the most affected tube.

MAINTENANCE/HEAT TRANSFER To reveal the elements constituting the scale, a sample collected from the inside of the tubes was analyzed using XRF and XRD techniques. Table 1 shows major elements present within the scale. It is worth noting that Ca, P and Fe were the major elements. In addition, high amounts of Na and Mg, along with small amounts of aluminum (Al) and silicon (Si) were detected.

All these elements originated from the BFW. Table 2 lists the main compounds that were identified in the tube deposit.

Mechanical assessment. To assess the mechanical prop-

erties of the boiler tubes, tensile testing was done using 50kN UTM, according to ASTM E8. Four sample locations were selected for tensile testing and marked as A, B, C and D. Samples B and D were selected from the most affected tubes. Sample D was taken from the location between two bulges and the area exposed to the hot gas. Two tensile samples were cut from the right side, adjacent to the bulges A and C (almost cold side). All test specimens were cut with their long axis in the length direction of the tube. Table 3 summarizes all of the test results. As noted in Table 3, there was little difference in ultimate strength between the affected tubes and the non-affected ones. However, a significant reduction in elongation was found in the affected tube, particularly in sample D located between two bulges. This sample lost its elongation over 68%.

Fig. 9 shows the metallographic examination (SEM) of fracture surface morphology after the tensile test. A well defined cupand-cone type of surface was revealed with clearly pronounced dimples, which are signs of typical ductile failure. The tune material ductility was not fully affected.

ROOT CAUSE INVESTIGATION

Long-term overheating usually occurs in superheaters, reheaters and water-wall tubes as a result of gradual accumulation of deposits or scale, partially in restricted steam or water flow, excessive heat input from burners or undesired channeling of fireside gases.1 Tube metal operating temperatures above 850°F (454°C) or slightly above the oxidation limits of the tube steels, can lead to tube bulging or thick-lipped creep rupture failures, as shown in Fig. 2A. Creep damage in long-term failures can occur with little or no changes in the tube wall thickness. Microstructural examinations are the most effective means of confirming long-term overheating. It had been stated that most—not all—mineral-scale forming constituents are soluble. However, solubility decreases as water temperature increases and becomes saturated. When the saturated water contacts the heat transfer surfaces (such as tubes), solids precipitate out due to their lower equilibrium solubility.1 As the steam generation is underway, contaminants in the boiler makeup water are left behind to accumulate on the tubes’ surface. Common examples of boiler scale are calcium carbonate (CaCO3), magnesium carbonate (MgCO3), calcium sulfate (CaSO4) and calcium silicate (Ca2SiO4).

Scale issues. The precipitation and scale formation from

these compounds are carried by water as soluble constituents and

TABLE 1. Results of XRF analysis Elements

wt%

Elements

wt%

C

2.05

Cl

0.02

Na

1.76

K

0.06

Mg

1.12

Ca

63.81

Al

0.50

Mn

0.10

Si

0.32

Cu

0.22

P

18.40

Zn

0.04

S

0.36

Fe

11.20

TABLE 2. Results of phase analysis Compound

Chemical formula

Calcium phosphorus

Ca2P2

Magnetite

Fe3O4

Calcium oxide hydrate

CaO2(H2O)

Hematite

Fe2O3

TABLE 3. Results of mechanical testing Specimen ID

Proof strength, MPa

UTS, MPa

Elongation, %

A

201

331

29.2

B

219

325

31.5

C

228

334

35.3

D

190

316

21.2

SA-178, Gr. A spec.

179 min

324 min

35 min

FIG. 5

Light optical micrograph showing spheroidized microstructure of the bulged lip, X200.

HYDROCARBON PROCESSING NOVEMBER 2011

I 97

MAINTENANCE/HEAT TRANSFER depend on pressure drops, temperature, flow velocity and pH or alkalinity change, in addition to other water conditions. Changes in pH or alkalinity of the cooling water can have major effects on the solubility of scaling ions. An increase in alkalinity decreases the solubility of CaCO3 and affects the solubility of Ca and iron phosphates. An increase in pH also decreases the solubility of most calcium salts, with the exception of CaSO4. Calcium phosphate, Ca(H2PO4 )2 , is formed when the Ca in the BFW reacts with the phosphate in the water treatment program. This can be avoided if proper treatment is followed. It can form a sludge that can be removed during the blowdown. However, Ca(H2PO4 )2 can deposit as scale if the pH of the boiler water is below 11.4 The deposit within the boiler tube ID in this study revealed considerable amounts of calcium and phosphates.

One property of a formed deposit is its effect on insulation due to very low thermal conductivity, and thus it will retard heat transfer and affect the entire boiler efficiency.5 In addition, the increased scale deposition in those tubes that face the flame (hot gas) will locally increase tube temperature, leading to overheating and causing creep.

98

FIG. 6

Light optical micrograph showing cross-section of the tip of bulged/leaking area. Clearly cracking through enlarged (agglomerated) creep voids can be seen (A, X100, B, X500).

FIG. 7

SEM micrographs showing morphology of deposit surface facing the boiler water side (A, X400) and facing the tube surface (B, X600).

I NOVEMBER 2011 HydrocarbonProcessing.com

FIG. 8

SEM micrographs showing typical normal ferrite-pearlite microstructure away from rupture site (A, X5000) and spheriodized microstructure in the bulged area (B, X4000).

FIG. 9

Tensile samples taken from affected tubes and SEM photomicrographs showing tensile fracture surface as dimples (cone and cup), indicating a typical ductile fracture.

MAINTENANCE/HEAT TRANSFER To see the extent of deposition in this boiler, deposit removal and analysis were carried out. The removed deposit from the inner surface tube weight density (DWD) was determined.1, 6–8 The results showed that DWD values were 117 mg/cm2 in the hottest area and 74.9 mg/cm2 in the cooler area. It is well documented that for such a boiler operating at 42 barg, the DWD should not be above 85 mg/cm2–100 mg/cm2.3, 8–10 This indicates that the boiler tubes were considered as “very dirty” and required chemical cleaning.5,6,8 In the microstructure at the hotter region, pearlite had decomposed to spheroids, resulting in voids. The typical scheme of microstructural transformation in carbon steel usually occurs at temperatures above 800°F (427°C). The plate- or blade-like shape is unstable, and will change to a sphere-like shape, leading to spheroidization and formation of voids. High stress is another factor besides temperature that will lead to spheroidization.11,12 The speed of transformation is temperature dependent. For example, in SA178 or SA210 carbon steels, spheroidization will occur within a few hours at 1,300°F (704.4°C), but will take several years at cooler temperatures of 800°F–825°F (427°C–441°C).1,11,12 The noticeable change was seen in the elongation of the tube; thus, it was indicating spheroidization and voids. All of these changes were the result of increased temperatures in favorable sites (flame) and excessive deposit buildup in tubes ID that supported overheating and led to localized bulging.

ACTION ITEMS

The failure investigated was the result of long-term, localized overheating supported by deposit buildup on boiler water-side tubes. These deposits are most likely associated with BFW quality.

Microstructural analysis of the damaged tube showed evidence of creep-type rupture only on the tube side facing the flame. The back (cooler) side of the tubes showed normal ferrite and pearlite microstructure. According to mechanical testing results, the tubes facing the flame suffered reduced elongation. The tubes facing the flame should be replaced, and the mechanical integrity of other boiler tubes should be checked. The boiler’s cleanliness is considered “very dirty.” It is essential to do a chemical cleaning in this case to enhance boiler efficiency if mechanical integrity will be acceptable. The quality of BFW should be checked and always closely monitored. HP

Al C Ca Cl Cu Fe Mg

Aluminum Carbon Calcium Chlorine Copper Iron Magnesium

NOMENCLATURE Mn K P Si Na S Zn

Manganese Phosphorous Potassium Silicon Sodium Sulfur Zinc

Dr. Ali Babakr has served as a senior corrosion engineer and failure analysis advisor for Saudi Basic Industries Corp. (SABIC), Jubail, Saudi Arabia since 2008. At present, he serves as a consultant for an Engineering firm in the US. He holds a PhD and an MS degree in metallurgy from the University of Idaho, and a BS degree in materials chemistry from Huston-Tillotson University. Dr. Babakr has authored several papers dealing with failure analysis, mitigation of corrosion and other materials degradation problems.

Dr. Avtandil Khalil Bairamov has been the chief scientist of SABIC Technology Center—Jubail, Materials and Corrosion Section since 1995. He graduated from Moscow Institute of Petrochemical and Gas Industry. He earned his PhD in chemical resistance of materials and protection from corrosion from Azerbaijan Academy of Sciences, Baku, where he was the manager of the corrosion and electrochemistry department. He also carried out different research in UMIST (UK), Swedish Corrosion Institute and Brussels University. He has 45 years of experience in the field of corrosion and prevention of metals; published over 100 technical papers including 15 national patents, brochures and book chapters; and has completed numerous failure analysis and materials selection projects. He received the 2010 NACE International Technical Achievement Award for his many contributions to research and corrosion engineering. Dr. Bairamov is a professional member of the Institute of Corrosion (MICorr., UK) and NACE.

LITERATURE CITED The Nalco Water Handbook, 2nd Ed., “Chapter 39: Boiler water treatment,” McGraw-Hill Inc., 1988.

2 American Boiler Manufacturers Association, Boiler Water Limits and Steam Purity Recommendations for Water Tube Boiler, 3rd ed., Arlington, 1982.

3 SABIC Guidelines for Package Boilers in SABIC Affiliates, STC-Jubail, 2006.

4 Furtado, C. H., and I. Le May, “High temperature degradation in power plants and refineries,” Materials Research, vol. 7 no.1, São Carlos Jan./Mar. 2004.

5 Port, R. D., and H. M. Herro, The Nalco Guide in Boiler Failure Analysis, McGraw-Hill, Inc., 1991.

6 Atwood, K. L, and G. L. Hall, “Proceedings of American Power Conference,” Chicago, April 20–22, 1971.

7 Stultz, S. C. and J.B. Kitto, Eds., STEAM, its Generation and Use, 40th Ed., Babcock and Wilcox, New York, 1992.

8 ASTM Standard, Designation D3483-83, 1990.

9 “Guidelines for Chemical Cleaning of Conventional Fossil Plant Equipment,” EPRI, 2002, www.epri.com.

10 Bairamov A. K., NACE Corrosion 2006, Paper 06461.

11 Metals Handbook, 8th Ed., Vol.10, “Failure Analysis and Prevention,” ASM, 1975.

12 French, D. N., “Microstructural Degradation,” National Board Bulletin, 1991.

1

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ENGINEERING CASE HISTORIES

Case 65: Taking risks and making high-level presentations Tips on how to communicate with managers T. SOFRONAS, Consulting Engineer, Houston, Texas

A

n article impressed me recently, and I felt I had something to add.1 It is about engineers taking risks and communicating these risks to management. This column has focused on troubleshooting and using analytical methods.

After the cause is determined, the results must be communicated to management on what the real problem is and what must be done to fix it.

As engineers, we like to limit our risks. As a general aviation pilot and a mechanical engineer, this has served me well over the years. I didn’t do things that were too risky, and I always had a couple of alternative plans in case something went wrong. My requests for a design modification were always supported with adequate calculations. When someone has done a reasonable analysis, their arguments usually carry more weight than those who are speculating on the cause with no supporting data.

There can be problems with this approach, and I learned this early in my career and had to adjust for potential problems.

Remember: There is always risk involved in every engineering decision, and you cannot progress far in your career if you are unwilling to take some risk.

Consider a large steam turbine vibrating slightly above normal levels with blade fouling thought to be the problem. Management wants to know if it can run one week until a planned outage with that level of vibration. Your career will not be enhanced if you say it has to be shut down immediately, with no supporting data.

Likewise, this is not the time to try your first attempt at online washing of a steam turbine while it is in operation. This is a risky business if you have no experience and no operating guidelines for this procedure. However, this would be a good time to monitor the vibration level, talk with the manufacturer and others with similar machines and then determine the risk in just monitoring the vibration levels. Defining at what level it will have to be shut down will still require some risk, but now others are involved.

Obviously, there is much more but this illustrates the need for some risk. You can expect to make some judgment errors, but they should not occur early in your career or consecutively.

Communication is key. Correctly communicating to man-

agement what has occurred and what needs to be done is so important. It would be wonderful if engineers had the verbal ability of attorneys in presenting data to management. An attorney’s job is to make juries feel comfortable with what they are telling them and the decision that has to be made with the evidence and data presented. Unfortunately, many of us don’t have this type of training. Fortunately, it can be learned by experience and watch-

ing other successful engineers. Your company’s senior technical personnel didn’t get where they are via a lack of communication skills or poor judgment.

There are three things that I have found most important when discussing work with senior management. The first two items are self-explanatory, but the last will require an example: 1. Management does not like to hear bad news, so present positive plans.

2. Management does not want to hear a wish list of solutions, so present only your best and most cost-effective choice.

3. Management is not impressed with complex analysis or technical terms. The engineer must simplify explanations of the cause, the solution and the course of action so they can be understood and acted upon.

The management you are presenting to may not be familiar with mechanical engineering, and their expertise may be in a completely different field. It is useful to adjust what you are presenting to suit your audience.

Example. Suppose you are discussing the resonance of a struc-

ture and its failure. Now, as engineers, we know resonance can be a highly damaging vibration caused by exciting a structure’s natural frequency. Resonance could be clearly demonstrated by bringing a tuning fork to the meeting, striking it and showing the resonance of the tuning fork. With no continued exciting input, meaning no additional strikes, the vibration dies out. However, with a continued input and without material damping, the tuning fork would fail in fatigue.

The fatigue failure part could be demonstrated by bending a paper clip back and forth to demonstrate and explain fatigue. At any point, you can stop bending but some of its life has been used up.

When reviewing a technical presentation, I always make a list of all the questions that I think may come up during the meeting and research them thoroughly. This allows the best possible answers for the audience that I’m addressing. HP 1

LITERATURE CITED Bloch, H. P., “Reliability pros: Hear what others say about you,” Hydrocarbon Processing, August 2011, p. 11.

Dr. Tony Sofronas, P.E., was Worldwide Lead Mechanical Engineer for ExxonMobil before his retirement. Information on his books, seminars and consulting, as well as comments to this article are available at http://mechanicalengineeringhelp.com.

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Chesterton . . . . . . . . . . . . . . . . . 16 (153) www.info.hotims.com/35910-153

Cudd Energy Services . . . . . . . . . 56 (166) www.info.hotims.com/35910-166

Curtiss Wright Flow Control Company, DeltaValve . . . . . . . . . . . . . . . . 36 (90) www.info.hotims.com/35910-90

Eaton Filtration . . . . . . . . . . . . . . 94 www.info.hotims.com/35910-97

www.info.hotims.com/35910-156

www.info.hotims.com/35910-158

Events—WGLC . . . . . . . . . . . . . . 4 (151)

www.info.hotims.com/35910-70

www.info.hotims.com/35910-151

Global Data . . . . . . . . . . . . . . . 71 HPI Market Data . . . . . . . . . . . 50a HPI Marketplace . . . . . . . 102–103 Circulation . . . . . . . . . . . . . . . . 93 Hermetic Pumpen GmbH . . . . . . . 35 (160) www.info.hotims.com/35910-160

RS#

Paharpur Cooling Towers, Ltd. . . . 27

(98)

Petro-Canada Lubricants . . . . . . . 39 Rentech Boiler Services . . . . . . . T-74 Rentech Boiler System . . . . . . . . . . 2

www.info.hotims.com/35910-167

Sick AG . . . . . . . . . . . . . . . . . . . . 33 (159) www.info.hotims.com/35910-159

Siemens AG . . . . . . . . . . . . . . . . 17

SoundPLAN Intl LLC . . . . . . . . . . 52 (164) www.info.hotims.com/35910-164

Spraying Systems Co . . . . . . . . . . 40

(73)

SPT Group, Inc. . . . . . . . . . . . . . . 52 (163) www.info.hotims.com/35910-163

(92)

www.info.hotims.com/35910-92

(95)

Total Safety . . . . . . . . . . . . . . . . . 58

(89)

www.info.hotims.com/35910-89

(81)

www.info.hotims.com/35910-81

Trachte USA . . . . . . . . . . . . . . . . 99 (169) www.info.hotims.com/35910-169

(74)

www.info.hotims.com/35910-74

(61)

www.info.hotims.com/35910-61

Neptune Research . . . . . . . . . . . . 54 (165) Novozymes Biologicals . . . . . . . . 46 (162) www.info.hotims.com/35910-162

(66)

www.info.hotims.com/35910-66

www.info.hotims.com/35910-95

www.info.hotims.com/35910-73

Milliken Workwear . . . . . . . . . . . 55

(84)

www.info.hotims.com/35910-84

Team Industrial Services . . . . . . . 21

www.info.hotims.com/35910-154

Maxon . . . . . . . . . . . . . . . . . . . T-68

(52)

Samson GmbH . . . . . . . . . . . . . . 91 (167)

Inpro/Seal Company . . . . . . . . . . 20 (154)

Linde Process Plants . . . . . . . . . . . 6

(83)

www.info.hotims.com/35910-52

Sulzer Chemtech . . . . . . . . . . . . T-76

www.info.hotims.com/35910-72

Kobe Steel Ltd . . . . . . . . . . . . . . . 18

(88)

www.info.hotims.com/35910-83

(72)

Hytorc . . . . . . . . . . . . . . . 61, 63, 65

www.info.hotims.com/35910-165

(97)

Page

www.info.hotims.com/35910-88

www.info.hotims.com/35910-170

www.info.hotims.com/35910-85

Company Website

www.info.hotims.com/35910-98

www.info.hotims.com/35910-51

www.info.hotims.com/35910-59

ABMA . . . . . . . . . . . . . . . . . . . . . 82

RS#

www.info.hotims.com/35910-157

www.info.hotims.com/35910-76

ABB Analytical Measurements . . . 12

Page

TTMC . . . . . . . . . . . . . . . . . . . . T-78

(79)

www.info.hotims.com/35910-78

UOP LLC . . . . . . . . . . . . . . . . . . . 30 Weir Minerals—Lewis Pumps . . . 10

(55)

www.info.hotims.com/35910-55

Zyme-Flow . . . . . . . . . . . . . . . . T-80

(76)

www.info.hotims.com/35910-76

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

I 105

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

Don’t let water be the reason for a turnaround Several years ago, while arriving onsite during another unit turnaround, I joked to a process engineer at the refinery “I get it. . . every time I ‘turn around,’ you have a turnaround.” The site engineer was not amused at my clever play on words.

Turnarounds are serious business. The goal of every plant is to maximize the interval between turnarounds. For most units, the limiting factor that controls the scheduling or turnaround interval is a process-related issue: the gas side of the high-pressure waste-heat boiler at the sulfur unit or catalyst changeouts in a reformer or FCC unit. For other units, the limiting factor is the utility water system.

One of the guiding principles in industrial water treatment is: “Water should never be the cause of lost opportunity.” This principle means that a utility water system should have sufficient robustness and redundancy to avoid interrupting production should one component fail, and these systmes should not be the limiting factor in turnarounds. When the utility water system is the factor controlling the turnaround interval—that’s a problem that needs special attention. The old adage still remains true—“An ounce of prevention is worth a pound of cure.” Here’s my personal list of tactics to prevent water-related failures at hydrocarbon processing facilities.

Turnarounds: 1. Develop procedures to protect against corrosion, deposition and microbiological growth in all water circuits (boiler, steam, cooling and pretreatment) during idle periods. These procedures will include planning and implementation tasks during shutdowns and startups, as well as monitoring during the turnaround event. Contact the water treatment supplier or a consultant for assistance.

2. Designate a member of the turnaround team to track compliance to these procedures—no shortcuts without careful consideration of the consequences!

3. Prior to the turnaround, identify all at-risk heat exchangers and steam generators and any equipment that has experienced a recent water-related failure. Ensure that the utility process engineer, chemical supplier and, if appropriate, the water treatment consultant participate in the inspection and document the water-side condition, their recommendations regarding the reliability and their recommendations for any changes in chemical treatment and/ or configuration of these assets.

4. After the turnaround, conduct a survey of all critical heat exchangers. What is a critical heat exchanger? This exchanger is a unit that operates outside of the original equipment manufacturer specifications or TEMA1 or HTRI2 guidelines for the linear flowrate of the cooling water, the temperature of the heat transfer surface or the “U coefficient.”3

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I NOVEMBER 2011 HydrocarbonProcessing.com

Normal operation: 1. Operate systems according to the specification limits for key operating parameters. Develop a method to track the compliance statistics—the goal should be 100% compliance— to obtain optimal reliability and maximum water and energy efficiency.

2. Document severe nonconformance to water quality specifications in the water system and increase the level of monitoring following all upsets to identify any performance and/or reliability issues.

3. Develop and implement a monitoring program to track the heat transfer efficiency (U coefficient) of all critical heat exchangers on a periodic basis (e.g., during peak operating conditions or on an annual basis).

4. Use water quality data and trend information for the U coefficient to develop a predictive algorithm that identifies at-risk heat exchangers and schedules replacement at the next turnaround.

The ‘cure.’ Utility water issues should never control the

turnaround interval. Plant personnel should implement capital or operational changes to eliminate vulnerabilities in utility water systems that affect the turnaround interval. Prevention of failures is less expensive than corrective actions, especially when considering the costs of lost opportunity and lost production.

Requiring operations personnel, water-treatment suppliers and/ or a consultant to participate in turnaround planning and the development and implementation of customized procedures can increase the reliability of the utility water system and avoid water-related issues from controlling the turnaround interval.

HP NOTES TEMA—Thermal Equipment Manufacturer, http://www.tema.org/highlig8. html 2 HTRI—Heat Transfer Research Institute, http://www.htri.net/articles/ design_manual 3 U coefficient—the overall heat transfer coefficient, U = q / (A ⫻ ΔT) where q = heat flow in input or lost heat flow, A = heat transfer surface area, ΔT = difference in temperature between the solid surface and surrounding fluid area.

1

The author is president of MarTech Systems, Inc., a consulting firm that provides technical advisory services to manage risk and optimize energy and water-related systems including steam, cooling and wastewater in refineries and petrochemical plants. She holds a BS degree in chemical engineering, along with professional engineering licenses in New Jersey and Maryland and is a certified management consultant. She can be reached at huchler@martechsystems.com.

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