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JUNE 2012

HPIMPACT

SPECIALREPORT

TECHNOLOGY

Cyber campaign against gas pipelines

PROCESS/PLANT OPTIMIZATION

Update on valves used in hydrogen services

The myth of energy independence

Latest methods finetune process and information operations

Optimize operator training

www.HydrocarbonProcessing.com

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JUNE 2012 • VOL. 91 NO. 6 www.HydrocarbonProcessing.com

SPECIAL REPORT: PROCESS/PLANT OPTIMIZATION

Use adaptive modeling to revamp and maintain controllers

Cybersecurity for industrial plants

Conserve energy for fired heaters

The right tools can improve refinery APC applications S. Lodolo, M. Harmse, A. Esposito and A. Autuori

Consider five core elements for secure automation networks F. Köbinger

Advanced ceramic fiber veneer insulation reduces heat losses and is more resilient H. Yoon

Recover valuable olefins from offgas streams

Optimize training using a high-fidelity simulator

Improve feedstock selection for your refinery

The Bhopal disaster

Fine-tune relief calculations for supercritical fluids

Catalytic technology aids in removal of acetylenes, NOx and oxygen S. Blankenship, R. Rajesh, M. Sun, M. Urbancic and R. Zoldak

Here are lessons learned from a Russian methanol plant D. Kotsuba, M. Gareyshin, D. Stavrakas, T. Pallis and V. Harismiadis

A simplistic approach facilitates screening of crude oil baskets R. Kumar, P. Parihar and R. K. Voolapalli

HPIMPACT 17

Delta Air Lines buys Trainer refinery complex

Cyber campaign against gas pipelines

Global oil market reveals myth of energy independence

Diesel engine demand to exceed $197 billion in 2015

Understanding the impact of unreliable machinery K. Bloch and B. Jung

Improved process simulation assists with relief load and valve sizing P. Nezami and J. Price

VALVES 2012—SUPPLEMENT

V-85

Cover Future operation centers are built to provide efficient collaboration between people, systems and equipment. Focus on ergonomics and a user environment that hides all system boundaries results in alert operators ready for future operational challenges. Photo courtesy of ABB/CGM.

COLUMNS 9

HPINSIGHT Global solutions wanted for growing industry

HPIN RELIABILITY Pumps and the Bhopal connection

HPINTEGRATION STRATEGIES Making the business case for reliability

Update on valves used in hydrogen service Recommended practices scrutinize performance issues such as design, packing and metallurgy to mitigate failures T. Sequeira

DEPARTMENTS 7 HPIN BRIEF • 21 HPINNOVATIONS 27 HPIN CONTRUCTION • 34 HPINCONSTRUCTION BOXSCORE UPDATE 96 HPI MARKETPLACE • 100 ADVERTISER INDEX

102 HPIN WATER MANAGEMENT Avoid failures in water projects: Part 1

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If you would like to have a recent article reprinted for an upcoming conference or for use as a marketing tool, contact Foster Printing Company for a price quote. Articles are reprinted on quality stock with advertisements removed; options are available for covers and turnaround times. Our minimum order is a quantity of 100. For more information about article reprints, call Rhonda Brown with Foster Printing Company at +1 (866) 879-9144 ext 194 or e-mail rhondab@FosterPrinting.com. HYDROCARBON PROCESSING (ISSN 0018-8190) is published monthly by Gulf Publishing Co., 2 Greenway Plaza, Suite 1020, Houston, Texas 77046. Periodicals postage paid at Houston, Texas, and at additional mailing office. POSTMASTER: Send address changes to Hydrocarbon Processing, P.O. Box 2608, Houston, Texas 77252. Copyright ÂŠ 2012 by Gulf Publishing Co. All rights reserved. Permission is granted by the copyright owner to libraries and others registered with the Copyright Clearance Center (CCC) to photocopy any articles herein for the base fee of $3 per copy per page. Payment should be sent directly to the CCC, 21 Congress St., Salem, Mass. 01970. Copying for other than personal or internal reference use without express permission is prohibited. Requests for special permission or bulk orders should be addressed to the Editor. ISSN 0018-8190/01. www.HydrocarbonProcessing.com

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EDITORIAL Editor Stephany Romanow Reliability/Equipment Editor Heinz P. Bloch Process Editor Adrienne Blume Technical Editor Billy Thinnes Online Editor Ben DuBose Associate Editor Helen Meche Contributing Editor Loraine A. Huchler Contributing Editor William M. Goble Contributing Editor ARC Advisory Group

Because Hydrocarbon Processing is edited specifically to be of greatest value to people working in this specialized business, subscriptions are restricted to those engaged in the hydrocarbon processing industry, or service and supply company personnel connected thereto.

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Refinery Wash Water Injector Constructed of Inconel® 625, this injector is 6 ft. (1.8 m) long, weighs 2600 lbs. (1179 kg) and has a class 1500 flange.

SUPERIOR SPRAY. SERIOUS RESULTS. Using a quill or injector for water wash or chemical injection? We can help improve performance. Here's how: UÊÊNozzle selection assistance. There are dozens of options and a wrong choice can result in wall wetting, corrosion and unscheduled downtime. Using a quill? Consider a change. A slot in a pipe doesn’t provide the same precise flow and drop size control as an injector U Analyze process conditions to determine spray direction – co- or counter-current. Spray direction affects drop size, wall contact, evaporation rate and more – it’s essential to get it right UÊÊDesign validation using Computational Fluid Dynamics (CFD) and our proprietary drop size data. We simulate your environment to verify spray performance, determine injector placement and ensure the materials of construction can withstand thermal stresses, heat transfer, vortex shedding and more We are uniquely qualified to optimize injector performance: spray expertise, manufacturing capabilities for B31.1 and B31.3 code compliance and a proven track record with customers like Jacobs Engineering, Shaw Group, Bechtel, Shell, Conoco Phillips and dozens more.

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HPIN BRIEF BILLY THINNES, TECHNICAL EDITOR

BT@HydrocarbonProcessing.com

Honeywell’s UOP has been selected to provide key production technology to produce propylene via propane dehydrogenation in China. Zhangjiagang Yangzi River Petrochemical Co. will use UOP’s process technology to convert propane to propylene, which is used in the production of materials such as films and packaging. The project is the ninth propylene project Honeywell’s UOP has announced since the beginning of 2011, helping to meet growing demand globally, the company says. The new unit, expected to start up in 2014, will produce 600,000 tpy of propylene at the facility in Zhangjiagang City, Jiangsu Province, China. The process uses catalytic dehydrogenation to convert propane to propylene.

Axens received a top annual safety award in the category of responsible care from the Union of the French Chemical Industries (UIC) for its Salindres plant in France’s Gard region. The Salindres plant is its main catalyst and adsorbent production site in France. The 2011–2012 National Safety Award recognizes the overall approach adopted at the Salindres plant to “improve the safety of employees and the local community, as well as the safety of facilities and products,” according to the UIC group. Axens’ initiatives involved hiring a theater troupe from the Théâtre du Cratère d’Alès to educate employees about occupational safety on the site, the company said. In October 2011, the plant had already received the “Mediterranean Responsible Care Award” from the Languedoc-Roussillon and PACA-Corse UICs, which recognizes efforts to improve health, safety and environmental protection.

Canada-based Methanex has entered into a long-term offtake agreement with Orascom Construction Industries (OCI) for a significant portion of the production from the OCI methanol plant in Beaumont, Texas. The plant, which had been idled prior to its purchase by OCI, will commence commercial methanol production this month. OCI has said that the Beaumont plant will produce 750,000 tpy of methanol. The plant also has a capacity of 250,000 tpy of ammonia, which OCI began producing in December 2011.

Siemen’s automation division was recently awarded a fiveyear deal from Shell to deliver process gas chromatographs through an enterprise framework agreement that covers Shell companies, subsidiaries and joint ventures across the globe. During the term of the agreement, Siemens will supply gas chromatographs together with related systems such as analysis cabinets and shelters, much of which will be manufactured by Siemens in the US, the company said. Additionally, Siemens will provide front-end engineering and after-sales servicing.

UK-based BG Group has agreed to sell its 40% equity interest in the GNL Quintero (GNLQ) liquefied natural gas (LNG) terminal to Spain-based Enagas. The deal, worth up to $352 million, is expected to close by the end of 2012. The agreements reached apply to BG Group’s shareholding in GNLQ—the owner and operator of the 2.5 million tpy regasification terminal in Quintero, Chile. The deal does not impact BG’s 21-year contract to supply up to 1.7 million tpy of LNG to the Chilean market out to 2030, the company said.

The Veracruz ethylene and polyethylene (PE) complex in Mexico, a joint venture between Brazil’s Braskem and Mexico’s Grupo Idesa, will use hypercompressor and booster-compressor technologies from GE. The compressors feature technologies that use less electricity, reduce operating costs and require less maintenance, making the local plant more competitive with imported plastics, GE said. GE’s LDPE compressors feature a scalable design that enables upgrade and capacity additions with little effect on day-to-day operations. Construction on the Ethylene XXI project will begin later this year. HP

■ Hess resolves pollution dispute Hess Corp. has agreed to pay an $850,000 civil penalty and to spend more than $45 million in new pollution controls to resolve Clean Air Act violations at its refinery in Port Reading, New Jersey, according to officials with the US Environmental Protection Agency (EPA) and the US Department of Justice. The refinery has a processing capacity of 70,000 bpd. Once fully implemented, the controls required by the settlement are estimated to reduce emissions of nitrogen oxide (NOx ) by 181 tpy and result in additional reductions of volatile organic compounds (VOCs). High concentrations of NOx and VOCs, key pollutants emitted from refineries, can have adverse impacts on human health, the EPA said. “This settlement is the 31st such agreement with petroleum refineries across the nation. Hess joins a growing list of corporations who have entered into comprehensive and innovative agreements with the United States that will result in cleaner, healthier air for communities across the nation,” said Ignacia S. Moreno, assistant attorney general for the environment and natural resources division of the Department of Justice. The settlement requires new and upgraded pollution controls; more stringent emission limits; and aggressive monitoring, leak-detection and repair practices to reduce emissions from refinery equipment and processing. The government’s complaint, filed on April 19, 2012, alleged that the company made modifications to its refinery that increased emissions without first obtaining pre-construction permits and installing required pollution control equipment. The Clean Air Act requires major sources of air pollution to obtain such permits before making changes that would result in a significant emissions increase of any pollutant. The state of New Jersey participated in the settlement with Hess and will receive half of the civil penalty. The settlement is another example of improved compliance among refiners. HP HYDROCARBON PROCESSING JUNE 2012

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HPINSIGHT

Global solutions wanted for growing industry World War II was one of the defining events that drove innovation for the hydrocarbon processing industry (HPI). During the 1940s, solutions were needed to resolve shortages of transportation fuels and a lack of natural rubber. From WWII, new refining technologies were developed to process 100-octane fuels. A wave of new refining capacity, funded by the US government, was constructed. Likewise, synthetic rubber (SR) manufacturing received a political push to construct new petrochemical capacity to support SR demand. Yet, the HPI continues its cycle of overbuilding and flooding the market with too much product while demand declines from economic downturns. HPI companies have continued to follow a consistent quest over the last 90 years: to find new markets, to develop new products and uses for hydrocarbon-based materials, to improve operations, to increase safe operations, and to reduce operating costs. Continuous improvement is a never-ending task for HPI companies, as demonstrated in the headlines from the past 90 years.

Headlines from Hydrocarbon Processing, June 2002: Asian olefins: A new dawn. The Asian olefins industry has endured two onerous years. Yet, there is hope. The aftershocks of September 11, 2001, created many challenges. In particular, Asian economies that are high-tech oriented were more deeply impacted than others. Taiwan and Hong Kong have entered technical recessions. For the olefins industry, the largest effect was a sharp decline in re-export markets for polymer imports to China and the loss of polymer end-product exports from other Asian countries. However, a reversal is expected in 2002.

Side view of a thermal cracking unit from the 1940s. Refiner and Natural Gasoline Manufacturer 1940.

Polyethylene industry set to recover. The global outlook for the ethylene industry rests on the polyethylene (PE) market. In North America, the PE industry has had difficulties in recovering from the rapid rise in feedstock prices in 2001. The PE industry remains focused on cost reductions. PE processers are consolidating, and inefficient capacity is being rationalized. PE continues to replace traditional packing materials such as glass, paper and metal. The next wave of PE production capacity is estimated to begin in 2005. Australia considers GTL projects. Australia continues to experience declining crude oil production, while demand for refined crude-oil based products increases. By 2005/06, it is forecast that this nation will not be self-sufficient in transportation-fuel production. Australia is investigating several gas-to-liquids (GTLs) projects to bridge this gap. The Australian government has formed a task to evaluate GTL prospects.

Headlines from Hydrocarbon Processing, June 1992: First multi-plastics recycle facility opened. Union Carbide has opened the first US full-scale multi-plastics recycling facility. This plant is capable of recycling 84% of the plastics found in the average household. In the US, plastics recycling capacity is 925 million lb/yr. If the nation is to meet national targets of recycling 25% of its plastic waste by 1995, it must increase recycling capacity by 575 million lb/yrâ&#x20AC;&#x201D;double its present recycling capacity. Carbon energy tax proposals contested in Europe. The European Chemical Industry Council (CEFIC), representing petrochemical and chemical manufacturers, and Europia, representing

Wide view of the Odessa Butadiene Co.â&#x20AC;&#x2122;s 50,000-tpy butadiene plant nearing construction completion. The facility was designed and constructed by the Fluor Corp. Petroleum Refiner 1944. HYDROCARBON PROCESSING MAY 2012

HPINSIGHT regional refiners, have filed anti-tax protests on proposed carbon taxes. Both organizations believe that the carbon tax would destroy the competitiveness of European producers in the global market. Asia-Pacific refining capacity expanding. Present Asian refining capacity is 13.8 million bpd (MMbpd) with 1.5 MMbpd of new supplies to come online by 1995. Overbuilding in this region will be quickly absorbed by new demand growth in the second half of the 1990s. Growing demand is expected with China accounting for 48% of the regional energy demand. Saudi Arabia focuses on downstream developments outside the Kingdom. By the late 1990s, Saudi Arabia downstream production is expected to reach 1.4 MMbpd to 2 MMbpd with a European facility purchase. Brazil begins ‘privatization’ of HPI holdings. The Brazilian government has successfully auctioned a major petrochemical plant located at Copesul, Brazil, for $805 million. The shares were purchased by several buyers—no group holds a majority position. The next plan is the breakup of the Petrobras monopoly.

Headlines from Hydrocarbon Processing, June 1982: Oil usage declined in OECD industrialized nations during 1981—by 6.3% compared to 1980. Net oil imports fell 13.4% according to a new study by the International Energy Agency. Of the 24 OECD nations, crude oil imports declined 708.3 million metric tons while oil production by OECD nations remained the same, approximately 700 million metric tons. More taxes could threaten growth of energy industry. Members of the Independent Petroleum Association of America warn that proposed energy taxes designed to shrink the US national deficit could trigger larger future deficits. Income tax rates for oil companies have increased from 30% for 1953–1963 to nearly 50% in recent years. Present US gasoline taxes are 30¢/gallon. Methanol as a transportation fuel would be expensive and difficult. According to the Synthetic Fuels Association, methanol

as a motor fuel is slow to develop due to several reasons: 1) Excess petroleum-based fuels are available at lower prices than methanol; 2) Methanol is incompatible to the existing fueling distribution system; and 3) Lack of infrastructure that is compatible with methanol. Methanol as a motor fuel is used in token amounts. Coal will be used for long-term methanol production by the US and several other countries. Gasoline from methanol could be a future option to switch from petroleum-based fuels.

Headlines from Hydrocarbon Processing, June 1972: Thermonuclear fusion possible solution to future energy needs. A $3-million long-range research project will investigate the potential of high-power lasers to produce controlled nuclear fusion. Esso R&E and General Electric will work on the study in collaboration with the University of Rochester, Rochester, New York. New process claims 99.9% efficiency for sulfur removal. The Alberta Sulphur Research (ASR) has developed a process that is claimed to remove sulfur compounds from natural gas streams at more than 99.9% efficiency. The ASR process has only been demonstrated in the laboratory. It uses an organic sulphoxide as a liquid catalyst to remove hydrogen sulfide and sulfur dioxide from natural gas. High-octane gasoline converted directly from heavy oils. The Kellogg-Phillips heavy oil cracking (HOC) process can produce high-octane gasoline from either atmospheric residuals (ARs) or vacuum residuals (VRs) without pretreating the heavy feeds. With the HOC process, refiners can eliminate hydrocracking and delayed coking of VR streams. The process acts like a fluid catalytic cracking unit and reacts only the gasoil portion of the VR. The first unit is operating at the Phillips’ Borger, Texas refinery.

Headlines from Hydrocarbon Processing and Petroleum Refiner, June 1962: South Korea is building its first refinery. The 30,000-bpd refinery will be constructed at Ulsan, Korea, with startup planned by mid-1964. New cost-efficient butadiene process unveiled. Shell’s French affiliate has developed a new butadiene process that is more costeffective. The company is planning to build a 40,000-ton plant near Marseilles, France. The process uses a butane-dehydrogenation route to yield butadiene. News for FCC catalyst announced. Sinclair has released a catalyst regeneration process that could reduce refining costs by 50%.

Gulf Refining Co.’s new polymerization unit will produce feed for highoctane gasoline. The new unit is part of Gulf Refining’s Cincinnati, Ohio refinery and was part of the $15 million expansion. Petroleum Refiner, January 1949. 10

I JUNE 2012 HydrocarbonProcessing.com

UN sees pressure on international oil market. The United Nations reported that slacking demand for commercial energy in Western Europe and the US during 1961 impacted oil and coal producers the hardest. Energy consumption via oil and coal has steadily fallen. Reasons for the slowdown are linked to the leveling off of industrial production in Western Europe and a lag in the upturn of the US economy, along with a slow recovery for fuel demand.

To see more headlines from 1952 to 1924, visit HydrocarbonProcessing.com.

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

Pumps and the Bhopal connection In the 2012 June issue of Hydrocarbon Processing, our readers will find a highly informative article that should remind equipment specialists of their professional and ethical responsibilities. These professionals have the responsibility to detect, question and resolve repeat failure events. Human lives may be at stake. Contributing factors. Fig. 1 is a fitting reminder that pumps were involved in the still incomprehensible Bhopal tragedy. The event occured due to serious equipment reliability issues. Erroneous decisions were made in the interest of coping with, and circumventing, a chronic machinery reliability problem. These decisions included devising alternative operating strategies that introduced unknown and potentially unacceptable hazards. Creative alternative operating strategies (process optimization steps) may seem justified in the interest of confronting legitimate personal safety concerns. However, their impact on process safety can be disastrous. Focusing instead on resolving equipment reliability defects often makes it possible to eliminate risk-inducing components or elements. Unswerving focus, early remedial action and zero tolerance for unexplained repeat failures of rotating machinery are the most valuable safeguards against a potentially devastating sequence of events. In the June article “The Bhopal disaster,” two experienced coauthors apply objective investigation principles, using only information in the public domain. They place before us the exceedingly well-documented sequence of events that preceded this disaster and/or followed in the wake of several process-related decisions. The point. Engineers should have a questioning attitude, and

they should demand from themselves the same conduct expected from the medical profession. All must offer authoritative advice, concern for everyone and complete candor. Meeting this mutual expectation is especially important when there are edicts to purchase from the lowest bidder. Engineers should stand firm in demanding to buy from the lowest bidder that also fully meets responsibly written specification requirements. Needless to say, one of the engineers’ primary roles must be to write such specifications. That further implies that the engineers avail themselves of all reasonable post-graduation training opportunities. It also implies that they should never become a party to withholding information from the ultimate equipment users. So, we believe that engineering schools and their industrytraining conference adjuncts should make it their business to teach about the sequence of events that resulted in one of the worst industrial disasters in history. The next generations of engineers must be trained in the importance of good engineering judgment. English critic, essayist and reformer John Ruskin (1819– 1900) knew what would happen if one blindly purchases from the lowest bidder. He stated basic principles and phrased them in common-sense language long before the business schools of the

FIG. 1

A graphic reminder of the most tragic loss of life in the history of process plants. Source: Bhopal Medical Appeal, www.bhopal.org, used with permission.

late 20th and early 21st centuries began dispensing their often misguided and also widely misinterpreted and rarely contested wisdoms. Paraphrasing Ruskin: “It is unwise to pay too much, but is worse to pay too little. When you pay too much, you lose a little money—that is all. When you pay too little, you sometimes lose everything, because the thing you bought was incapable of doing the thing it was bought to do ... The common law of business balance prohibits paying a little and getting a lot—it cannot be done. If you deal with the lowest bidder, it is well to add something for the risk you run, and if you do that, you will have enough to pay for something better.” There is no way that John Ruskin could have foreseen the events in Bhopal on Dec. 3, 1984. Bhopal was an unmitigated disaster that involved disregarding warning signs, disabling critical safeguards and permitting normalization of deviances. The record shows deviations of huge consequences, including choices in materials technology and pump component selection. As modern industry benefits from examining the many historical facts relating to process safety failures, it should be noted that process safety trumps all manner of process optimization. About the Bhopal article, it simply and convincingly makes use of material that is now freely available in the public domain. The topic will be fully appreciated by those professionals who, by virtue of seeing it as their responsibility to avoid similar incidents, draw the right conclusions and take advantage of the information presented. HP The author is Hydrocarbon Processing’s Reliability/Equipment Editor. He greatly elaborates on avoiding repeat failures in his 18th and most recent book, Pump Wisdom: Problem Solving for Operators and Specialists, John Wiley & Sons, Hoboken, New Jersey, 2011. HYDROCARBON PROCESSING JUNE 2012

I 13

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HPINTEGRATION STRATEGIES PAULA HOLLYWOOD, CONTRIBUTING EDITOR phollywood@arcweb.com

Making the business case for reliability The global process industries lose $20 billion, or 5% annual production, due to unscheduled downtime and poor quality. ARC estimates that almost 80% of these losses are preventable. In fact, 40% of these losses are largely attributable to human error. The greater use of automation may have reduced the need for manpower. Conversely, maintenance costs and cost of ownership have increased under these conditions. Ineffective maintenance accounts for $60 billion spent annually. In addition, manufacturers are under pressure to place more emphasis on safety and environmental impact.

16.6%

41.6% Yes, it is documented and supported by a business case. Yes, but it is not documented. No, but planning one. Not planning one in the foreseeable future.

29.1% FIG. 1

12% Answers to survey question, Do you have a strategy and plan for sustaining reliability at your plant?

Reliability and asset performance management.

The “if it isn’t broke, don’t fix it” approach to maintenance is a thing of the past. The increased amount and complexity of automation equipment in use by processing plants requires a higher order approach to maintenance. Maintenance costs are a significant component of total operating costs of all process manufacturing plants, representing about 15% to 60% depending on the industry segment. A maintenance strategy should be driven by an organization’s overall business goals. It should be properly aligned with the associated business strategy. This includes a clear understanding of the benefits and costs associated with the initiative, a cultural commitment to implementing the results, and a commitment to update the program on a continual basis. In asset management terms, “reliability” refers to the probability that an asset will function as intended, over a specified period, under a specified set of conditions. As a component of a comprehensive asset-performance management (APM) strategy, reliability focuses on optimizing asset availability and utilization. From a reliability perspective, adhering to an APM strategy can improve workforce and financial performance. With a combined view of asset availability and other operational constraints, workers can make information-driven decisions. APM also provides key performance indicators for tracking the effectiveness of the programs in concert with each other. In its simplest form, APM integrates and analyzes information from various reliability applications such as reliability-centered maintenance (RCM), risk-based inspection (RBI), preventive maintenance (PM), enterprise asset management (EAM) and other plant asset management (PAM) solutions to provide a comprehensive view of asset reliability and enable reliability to be evaluated against a multitude of benchmarks. ARC recently conducted a web survey of end users in the process industries to learn more about their experiences with reliability initiatives. We asked end users to characterize the status of their reliability initiatives, the drivers behind them, how they were implemented, what worked, what didn’t work, and the metrics applied. Survey respondents included reliability engineers, managers or coordinators, operations managers, maintenance managers,

technicians or planners, facilities managers, and C-level decision makers from a variety of industries. We report our findings here. Reliability and the bottom line. Reliability initiatives frequently require resource allocation or, at minimum, a re-allocation of financial, human and/or equipment resources. To gain the C-level support required for such a substantial undertaking, ARC recommends developing a business case that outlines the objectives and resource requirements and quantifies the business benefits. Support from C-level executives is critical, since they both control the purse strings and have the authority to affect the organizational transformation required for a positive outcome. Decision makers need to understand the impact of reliability on the bottom line. The business case should include a realistic assessment of present circumstances compared with the outlook on the enterprise following implementation. It may be advisable to enlist the services of an objective third party to do the assessment and to make recommendations based on industry best practices. Clearly defined strategic goals, and the associated business risks and benefits, should be presented in financial terms—the language of business. Potential revenue growth from increased uptime and reduced maintenance, labor, inventory, energy and insurance costs that the reliability program can provide should be documented. The business case should also include the costs and risks of maintaining status quo. A documented business case also demonstrates the belief that a reliability initiative will have a positive, measureable and sustainable impact on business results. More than 40% of survey respondents indicated they had a strategy and plan for sustaining reliability at their facility, supported by a documented business case. The minority reported their strategy was not documented, and was thus less likely to produce the intended results. In ARC’s view, embarking on a reliability initiative without first examining the impact on all affected areas of the plant is a recipe for failure. HP The author has been covering field instrumentation and other automation technologies for over 30 years. She currently focuses on enabling technologies and strategies for industrial asset performance management.

HYDROCARBON PROCESSING JUNE 2012

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Select 58 at www.HydrocarbonProcessing.com/RS

HPIMPACT BILLY THINNES, TECHNICAL EDITOR

BT@HydrocarbonProcessing.com

In a move that surprised observers in two industries, Delta Air Lines and its subsidiary Monroe Energy reached an agreement with Phillips 66 to acquire the Trainer refinery complex south of Philadelphia, Pennsylvania. As part of the transaction, Monroe will enter into strategic sourcing and marketing agreements with BP and Phillips 66. The acquisition includes pipelines and transportation assets that will provide access to the delivery network for jet fuel reaching Delta’s operations throughout the Northeast, including its hubs at LaGuardia and JFK. After receipt of $30 million in state government assistance for job creation and infrastructure improvement from Pennsylvania, Monroe’s investment to acquire the refinery will be $150 million, and Monroe will spend $100 million to convert the existing infrastructure to maximize jet fuel production. Production at the refinery combined with multi-year agreements to exchange gasoline, diesel and other refined products from the refinery for jet fuel will provide 80% of Delta’s jet fuel needs in the United States (Fig. 1). “Acquiring the Trainer refinery is an innovative approach to managing our largest expense,” said Richard Anderson, Delta’s chief executive officer. “This modest investment, the equivalent of the list price of a new widebody aircraft, will allow Delta to reduce its fuel expense by $300 million annually and ensure jet fuel availability in the Northeast.” Monroe is partnering with leading energy companies to supply crude oil and receive jet fuel in exchange for Trainer’s non-jet fuel outputs. Under a three-year agreement, BP will supply the crude oil to be refined at the facility. Monroe Energy will exchange gasoline and other refined products from Trainer for jet fuel from Phillips 66 and BP elsewhere in the country through multi-year agreements. “By working with world class partners like BP and Phillips 66, we can benefit from their expertise in energy sourcing and product distribution,” said Ed Bastian, Delta’s president.

Monroe expects to close on the acquisition in the first half of 2012. Jet fuel production is expected to begin during the third quarter, and changes to the plant infrastructure to increase jet fuel production would be complete by the end of the third quarter, resulting in expected 2012 fuel savings of more than $100 million. Located on the Delaware River in Trainer, Pennsylvania, about 10 miles southwest of downtown Philadelphia, the Trainer complex has a crude oil process-

ing capacity of 185,000 bpd and processes mainly light, low-sulfur crude oil.

Cyber campaign against gas pipelines In March, US Homeland Security’s Industrial Control Systems Cyber Emergency Response Team (ICS-CERT) identified an active series of cyber intrusions targeting natural gas pipeline sector companies. Various sources provided information to ICS-CERT describing targeted attempts

TABLE 1. World diesel engine demand, billions of dollars Item

2005

2010

2015

Diesel engine demand (total)

Percent annual Percent annual growth, 2005–2010 growth, 2010–2015

109.1

142.5

197.5

5.5

6.7

North America

19.8

15.6

21.3

-4.7

6.4

Western Europe

36.4

36.8

46.1

0.2

4.6

Asia-Pacific

34.9

64.1

12.9

7.7

Central/South America

5.2

7.9

11.1

8.9

6.9

Eastern Europe

7.5

10.4

14.9

6.8

7.4

Africa/Middle East

5.3

7.7

11.2

7.9

7.7

Delta has become the first airline to purchase a refinery.

FIG. 1

25 20 Million bpd

Delta Air Lines buys Trainer refinery complex

15 10 5 0 1950

1955

1960

1965

1970

Domestic crude Adjustments and domestic biofuels

1975

1980

1985

Domestic NGLs Net imports

1990

1995

2000

2005

2010

Processing gain and stock changes

Source: DOE, EIA

FIG. 2

US petroleum source by origin, 1950 to 2010.

HYDROCARBON PROCESSING JUNE 2012

I 17

HPIMPACT and intrusions into multiple natural gas pipeline sector organizations. Analysis of the malware and artifacts associated with these cyber attacks has positively identified this activity as related to a single campaign with spear-phishing activity dating back to as early as December 2011. Analysis shows that the spear-phishing attempts have targeted a variety of personnel within these organizations; however, the number of persons targeted appears to

be tightly focused. In addition, the e-mails have been convincingly crafted to appear as though they were sent from a trusted member internal to the organization. ICS-CERT is currently engaged with multiple organizations to provide remote and onsite analytic assistance to confirm the compromise, extent of infection and assist in removing it from networks. ICS-CERT does not recommend enabling the intrusion activity to persist within networks,

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and it has been working aggressively with affected organizations to prepare mitigation plans customized to their current network security configurations to remove the threat and harden networks from reinfection. In addition, ICS-CERT recently conducted a series of briefings across the country to share information related to the intrusion activity with oil and natural gas pipeline companies. These briefings provided additional context of the intrusions and mitigations for detecting and removing the activity from networks. ICS-CERT continues to recommend Defense-in-Depth practices and educating users about social engineering and spear-phishing attacks. Organizations are also encouraged to review ICS-CERT’s “Incident Handling” brochure for tips on preparing for and responding to an incident. Asset owners/operators who would like access to the portal or to the alerts can contact ICS-CERT at ics-cert@dhs.gov.

Global oil market reveals myth of energy independence

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The current oil boom is creating economic benefits for the US, but it won’t shield the country from the price volatility that is inherent in the global oil market, according to a new report from business and former military leaders on the Energy Security Leadership Council (ESLC), a project of Securing America’s Future Energy (SAFE). The ESLC report examines the notion of energy independence, which is typically defined as ending reliance on foreign oil, in light of the renaissance in domestic liquid fuel production, rising demand from developing nations, and increased geopolitical tensions in oil-rich regions of the world. “While the new oil boom will alleviate our trade deficit and be an important source of domestic employment growth, unfortunately it won’t break our nation’s dependence on the highly price-volatile global oil market,” said Herb Kelleher, cofounder and chairman emeritus of Southwest Airlines. “Energy independence for the United States is an admirable goal, but even if the US were to produce enough oil to meet our demand, the domestic price is still set on the global market, meaning a potential supply disruption anywhere can impact the price of oil everywhere.” The report comes at a time when the US energy landscape is experiencing a tec-

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HPIMPACT tonic shift—especially in the outlook for oil imports. The US now imports less than 50% of its oil (Fig. 2), which is down from more than 60% in 2005. This growth in domestic production will help reduce the trade deficit and be a source for job growth in the US. However, the report details how a dramatic increase in domestic oil production won’t shield consumers from the economic damages inflicted by high oil prices and price volatility. For example, countries that produce more oil than they consume (like Canada and Norway) meet the typical definition of being energy independent. Yet, because the oil market is global, these exporting nations still must pay the going price for oil—currently around $100 per barrel. This dependence on the global oil market demonstrates that the true measure of energy security is not how much oil a nation produces, but how much it consumes.

Diesel engine demand to exceed $197 billion in 2015 World demand for diesel engines is projected to grow 6.7% per year through 2015 to $197.5 billion (Table 1). Product sales will be driven by an increase in the production of motor vehicles, particularly medium and heavy trucks and buses. Value gains will also be fueled by the growing use of more technologically advanced, higher value products because of increasingly restrictive emission regulations in a number of regions. These and other trends are presented in a new study from The Freedonia Group. The Asia-Pacific region was the world’s largest market for diesel engines in 2010 by a wide margin. China and India will be the primary drivers for growth in the region, as expanding output of motor vehicles and offhighway equipment combine with higher levels of fixed investment to stimulate significant increases in diesel engine demand. The medium and heavy vehicle diesel engine segment will experience the greatest gains in this regional market in dollar terms, accounting for 53% of total sales for the Asia/Pacific region in 2015. Demand for diesel engines in the Africa/ Middle East region is expected to expand 7.7% per year through 2015, spurred by rising output of medium and heavy vehicles and off-highway equipment, in addition to rising fixed investment. Stationary diesel engines will continue to account for a relatively high proportion of the overall market due to the unreliability of electricity

in the region, prompting the use of these products as backup generators. The diesel engine markets in Eastern Europe and in Central and South America will also grow at healthy rates from 2010 to 2015. However, each of these regions will still account for less than 10% of global sales in 2015. Demand for diesel engines in North America and Western Europe will grow with renewed strength following a period of weakness. Continued high levels of off-

highway equipment production will maintain proportionally large demand for offhighway diesel engines in North America. In Western Europe, lower diesel fuel prices and differing cultural factors will maintain the popularity of diesel engines used in light vehicles. Market gains in Japan will advance only 2.3% per year through 2015, although this will represent an improvement over sales declines recorded between 2005 and 2010. HP

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WorleyParsons has successfully completed over 2,100 cumulative petrochemicals and refining projects in 30 countries. We draw on 60 years of comprehensive global experience utilizing innovative, efficient solutions to safely deliver economical, sustainable and responsible business outcomes. In addition to providing exceptional EPCM services across all phases of the asset lifecycle, we have established over 230 strategic, long-term alliance relationships that yield optimized results for our customers. www.worleyparsons.com Select 153 at www.HydrocarbonProcessing.com/RS

Another I/O change? Great. So another wiring schedule. Another marshalling design. And another cabinet... Just make it all go away!

YOU CAN DO THAT Electronic marshalling eliminates the rework, the redesign and the headaches. With DeltaV Electronic Marshalling, Emerson lets you make I/O changes where and when you need them without costly engineering and schedule delays. Our new DeltaV CHARacterization Module (CHARM) completely eliminates the cross-wiring from the marshalling panel to the I/O card–regardless of signal type–so you’re no longer held to predefined specifications. All those wires, gone. All that time and engineering, gone. See how easy it can be by scanning the code below or by visiting IOonDemandCalculator.com Select 63 at www.HydrocarbonProcessing.com/RS

HPINNOVATIONS SELECTED BY HYDROCARBON PROCESSING EDITORS Editorial@HydrocarbonProcessing.com

Linde debuts hydrogen for fuel-cell vehicles The Linde Group’s hydrogen (H2) for fuel-cell vehicles—a byproduct of biodiesel production at Linde’s pilot plant in Leuna, Germany—recently was certified by the global testing and certification organization TÜV SÜD. The company introduced its newly certified H2 for fuel cells at the Hannover Messe 2012 trade show in late April. Linde was the sole supplier of H2 for fuel-cell vehicles organized by the Clean Energy Partnership (CEP). As a byproduct, the H2 can be processed cost-effectively. It is available year-round and does not compromise food supplies. Once the raw glycerine has been distilled to remove water and salt, it is cracked under high pressure and at temperatures of several hundred degrees Celsius. The resulting methane-rich pyrolysis gas is then converted to H2 in a reformer, after which it is purified and liquefied if necessary. The pyroreforming process may be able to reduce greenhouse gas (GHG) emissions by over 50% compared with conventional H2 production processes using natural gas. Advancing the pilot facility to a commercialscale, fully mature production plant would boost potential GHG savings to nearly 80%. At Hanover, Linde used its “traiLH2gas” mobile station to refuel fuel-cell cars provided by CEP members GM/Opel, Volkswagen, Honda and Toyota with green hydrogen. Linde will also supply certified green H2 to existing refueling stations in Berlin and Hamburg, in addition to the 20 stations that Linde and Daimler plan to construct in Germany over the next three years. Select 1 at www.HydrocarbonProcessing.com/RS

LNG expands as ship fuel in Asia, around world The Maritime and Port Authority of Singapore has established a joint industry project (JIP) to investigate the operational feasibility of LNG bunkering in Singapore in collaboration with the Det Norske Veritas Clean Technology Center and 21 industry partners. The shipping industry is looking to LNG as a cleaner marine fuel to meet international environmental regulations, as LNG has lower emissions compared to marine diesel oil.

LNG fuel meets strict environmental regulations and is technically feasible. At present, there are 25 LNG-fueled ships, all of which are operating in the Norwegian Emission Control Area and bunkering from shore facilities. Positive market signals also come from the number of LNGfueled ships being designed and from the 24 ships on order. However, key barriers to the more widespread adoption of LNG as fuel for ships are insufficient local LNG supply and immature bunkering infrastructure, coupled with a lack of regulatory schemes for both shore-based and ship-to-ship bunkering. The feasibility of LNG-fueled shipping also depends on the simultaneous development of the entire value chain; the lack of such concurrent evolution presents a major challenge and increases investment risk for each stakeholder. Singapore’s LNG bunkering JIP was conceived to address these feasibility issues and to reaffirm Singapore’s commitment to sustainable maritime growth. It will also provide recommendations to Singapore government authorities on ensuring operational safety for LNG bunkering; on alignment with industry expectations and best practices; and on compliance with relevant international rules, regulations and standards. As the world’s largest marine fuel bunkering port, it is strategically essential for Singapore to offer LNG bunkering in the near future. Select 2 at www.HydrocarbonProcessing.com/RS

Software helps monitor rotating equipment Lloyd’s Register has designed the industry’s first reliability-based mechanical integrity (RBMI) software to address the maintenance needs of rotating and instrumentation equipment. The new modules integrate with the components of the inspection software package Capstone RBMI, allowing companies to combine maintenance schedules for these types of assets into one program, and thereby raising the efficiency of their processes. Unlike most fixed equipment, rotating and instrumentation equipment have more diverse sets of components, more varied damage mechanisms and higher variations in damage rates and usage-to-failure times.

Therefore, they require more complex lifecycle assessments and typically come with few guidance documents, all of which make it difficult to develop an efficient maintenance strategy. With the Capstone RBMI system, the best maintenance strategy for each piece of equipment is selected by a screening process. This gives companies access to information to create a more efficient and effective maintenance system by supporting real-time testing, which in turn reduces downtime and increases cost savings, according to Efrain Garcia, vice president of Lloyd’s Register Energy Americas. Additional benefits include the identification of critical assets, the prioritization of maintenance and/or inspection tasks, fewer equipment failures, fewer in-service failures, consistent activity work plans that define recommended preventive and corrective maintenance tasks, and the promotion of continuous improvement for changing business and operational conditions. Select 3 at www.HydrocarbonProcessing.com/RS

SABIC’s HDPE meets pipe pressure standards Customers of Saudi Basic Industries Corp. (SABIC) have reported that the company’s new Vestolen A RELY bimodal high-density polyethylene (HDPE) grades are able to meet stringent requirements for typical pressure pipes, and to give considerable energy savings during pipe production. Two grades of SABIC Vestolen A RELY are currently available, and both are suitable for producing pressure pipe that meets the PE 100 standard. SABIC Vestolen A RELY 5924R delivers good low-sag performance for large-diameter pipes and pressure pipes with a low standard dimension ratio. Meanwhile, SABIC Vestolen A RELY 5922R helps customers meet stringent As HP editors, we hear about new products, patents, software, processes and services that are true industry innovations—a cut above the typical product offerings. This section enables us to highlight these significant developments. For more information from these companies, please go to our website at www.HydrocarbonProcessing.com/rs and select the reader service number.

HYDROCARBON PROCESSING JUNE 2012

I 21

HPINNOVATIONS slow-crack-growth requirements for pressure pipe, enshrined in Publicly Accessible Standard (PAS) 1075. Certification to PAS 1075 enables the grade to be used for pipes intended for demanding installation techniques, including new trenchless methods such as guided boring and horizontal directional drilling. Furthermore, the pipes’ unique rheological and morphological properties— created through a combination of pro-

prietary catalysts and fine-tuned reactor and extrusion technology—could provide processors with considerable energy savings, depending on pipe size. Select 4 at www.HydrocarbonProcessing.com/RS

Supercritical H2O oxidation technology handles spent caustic The disposal of spent caustic, which is a byproduct of the refining process— has become an increasingly costly and

environmentally contentious issue for the refining and petrochemical industries. Used as a scrubbing medium, ethylene and refinery spent caustics contain contaminants such as sulfides, mercaptans and naphthenic acids. As a hazardous and odorous waste, spent caustic calls for specialist handling, and it cannot be disposed of through conventional wastewater treatment routes without pretreatment. H o w e v e r, S C F I ’s A q u a C r i t o x supercritical water oxidation (SCWO) technology (Fig. 1) is a sustainable spent caustic handling and disposal solution. The technology delivers a more effective oxidation process than conventional wet air oxidation, and it can be applied to the spent caustic treatment process to destroy all odor and toxicity precursors. As a result, treated spent caustic can be safely disposed of through a conventional wastewater treatment plant or sewer; it is also suitable for final biological treatment. AquaCritox operates at a minimum pressure of 190 bar and at near-critical or supercritical temperatures. Under these conditions, there is a significantly increased oxygen transfer rate to liquid. The high pressure and temperature inside the AquaCritox reactor make for improved efficiency and speed of oxidation reaction— approximately 120% more efficient than conventional wet air oxidation. Sulfides, cresols, mercaptans and phenols are rapidly oxidized to produce an odorless treated effluent, ensuring that environmental discharge quality and permit requirements are easily met. The rapid reaction and short retention time also mean that AquaCritox plants are small in size. The technology is available in four standard sizes, with hydraulic loads ranging from 1–20 metric tons per hour. SCFI has been operating trials for applications in a number of industries,

This bench top analyzer tops all others in its price range for features and performance. It’s equipped with an intuitive user interface, full-color touch screen and on-board Windows XP computer. Ethernet electronics that permit remote access for calibration, diagnostics or service support. Plus, the Phoenix II has a large sample compartment that accommodates spinners and special holders yet requires little or no sample preparation. It all adds up to the lowest cost of ownership, backed by AMETEK’s reputation for reliability and world class customer support. Visit: ametekpi.com

FIG. 1

Select 154 at www.HydrocarbonProcessing.com/RS

SCFI AquaCritox heating process.

HPINNOVATIONS including oil and gas, at its testing facility in Cork, Ireland, since May 2008. Processing undiluted spent caustic consistently produced a > 94% reduction in chemical oxygen demand (COD) and typical oxygen consumption of no more than 120% of COD. Also, operation in autothermal mode is possible when spent caustic contains a COD concentration of 24,000 mg/L or greater. Select 5 at www.HydrocarbonProcessing.com/RS

New application identifies safe operating limits The inBound software application (Fig. 2) from human reliability software supplier PAS improves the vigilance of safe operating limits and exposes process safety risks at plants. InBound is a layered application for PASâ&#x20AC;&#x2122; PlantState Suite alarm management software that aggregates, validates, and displays physical constraints. Such constraints include a vesselâ&#x20AC;&#x2122;s maximum allowable working pressure; design properties, such as relief valve settings; and safe operating limits. These constraints may be manually entered, calculated or imported into the software from engineering applications and databases. The application also enables engineers to develop a boundary hierarchy, and it

automatically detects and reports deviations from that hierarchy, such as an alarm setting that is higher than a pressure-relief valve setting. This capability provides assurance that configuration parameter changes, such as alarm limits and instrument ranges, remain within the safe operating envelope of the plant. By displaying safe operating limits in real time and in context within the plantâ&#x20AC;&#x2122;s existing control system graphics, inBound

enables operators to proactively monitor measurements and take action as needed to prevent violation of limits. Select 6 at www.HydrocarbonProcessing.com/RS

Magnetic float level switches attain SIL certification Select models of Emerson Process Managementâ&#x20AC;&#x2122;s Mobrey Horizontal Magnetic Float Level Switches (Fig. 3) have been certified in accordance with IEC61508 to

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HTRI Xchanger Suite is an integrated, easy-to-use suite of tools that delivers accurate design calculations for s SHELL AND TUBE HEAT EXCHANGERS s JACKETED PIPE HEAT EXCHANGERS s HAIRPIN HEAT EXCHANGERS s PLATE AND FRAME HEAT EXCHANGERS s SPIRAL PLATE HEAT EXCHANGERS

s FIRED HEATERS s AIR COOLERS s ECONOMIZERS s TUBE LAYOUTS s VIBRATION ANALYSIS

It also interfaces with many process simulators and physical property packages either directly or via CAPE-OPEN. FIG. 2

Example of an inBound operating graphic display.

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FIG. 3

Mobrey switches are approved for safety instrumented systems. Photo courtesy of Emerson Process Management.

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*Service Pack 3 includes functionality to load and convert files from Honeywellâ&#x20AC;&#x2122;s UniSimÂŽ $ESIGN 3HELL 4UBE %XCHANGER Modeler files (.STEI), as well as legacy HTFSÂŽ AND !SPEN 3HELL 4UBE %XCHANGER (.TAI and .EDR) files. â&#x20AC;&#x153;Honeywellâ&#x20AC;? and â&#x20AC;&#x153;UniSimâ&#x20AC;? are trademarks of Honeywell International, Inc. â&#x20AC;&#x153;HTFSâ&#x20AC;? and â&#x20AC;&#x153;!SPEN 3HELL 4UBE %XCHANGERv are trademarks of Aspen Technology, Inc. â&#x20AC;&#x153;HTRIâ&#x20AC;?, the HTRI logo, the â&#x20AC;&#x153;H2â&#x20AC;? logo, â&#x20AC;&#x153;Weâ&#x20AC;&#x2122;re changing the future of heat transferâ&#x20AC;? and h8CHANGER 3UITEv ARE TRADEMARKS OF (EAT 4RANSFER 2ESEARCH )NC 4HESE MARKS MAY BE REGISTERED IN SOME COUNTRIES

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HPINNOVATIONS attain Safety Integrity Level 1 (SIL 1) for a single device and SIL 2 for a pair of devices. A SIL 1-level switch is ideal for high- and low-liquid-level alarm duties in the refining, gas, power and chemical industries. The Mobrey switches provide robust and reliable level switching in most liquids. The magnetically coupled design enables reliable operation even when operating in pressure and temperature extremes. Measurements are unaffected by changes in process temperature, dielectric, or the presence of vapors, and there is a wide range of flanges, floats and switching outputs to suit all types of liquid level application. There are no glands or linkages that could cause leaks, or springs that require maintenance. The snap-action mechanism ensures a clean make or break of the switch contacts, and there is the option of a hermetically sealed switch mechanism to eliminate freezing and corrosion of contacts and all moving parts. Other options include versions with marine approvals and ATEX certifications for use in hazardous areas. Select 7 at www.HydrocarbonProcessing.com/RS

Scrubber cleans syngas at Rentech demo plant Synthesis gas (syngas) purification technology manufacturer Bionomic Industries recently provided gas-cleaning equipment as part of a 20-tpd, demonstration-scale gasifier at a Rentech technology center in Colorado (Fig. 4). Integrated with Rentech’s existing product demonstration unit, which consists of Rentech’s Fischer-Tropsch Process and UOP’s upgrading technology, the joint demonstration is designed to produce synthetic, renewable, certified drop-in jet and ultra-low-sulfur diesel fuels. Used to clean the reformer-generated syngas, the gas-purification process begins with removal of the majority of ash and carbon particulate with Bionomic’s dual-stage, high-performance CycloPlus collectors in a dry form. The gas then enters a Bionomic Series 8500 Variable Throat Venturi Scrubber with a combination liquid-entrainment separator and direct-contact syngas absorber and gas subcooler, where it undergoes final cleanup. This final stage cleans the syngas within customer-specified

Asset Longevity Plant & Pipeline Performance

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requirements by eliminating the remaining particulates, acid gases, heavy hydrocarbons and sticky tars to achieve a 99.5% contaminant-free purified gas. The fully engineered system was provided as a complete Bionomic ScrubPac skid-mounted unit containing all necessary equipment, including liquid-loop heat exchanger recirculation pumps, interconnecting piping/valve networks, instrumentation and controls. Select 8 at www.HydrocarbonProcessing.com/RS

Leakless stuffing box addresses environmental issues Robbins & Myers Energy Services Group’s Moyno Environmentally Friendly (EF) Leakless stuffing box is designed to reduce costs and prevent the risks associated with unwanted environmental issues caused by leaking stuffing boxes. Unwanted stuffing box leakage results in costly loss of product, unnecessary cleanup expenses and potential fines for environmental damages. This environmentally friendly solution is critical for all field installations. A simplified clamping system ensures fast and easy installation— whether in a new installation or retrofitting an existing installation—to minimize downtime and reduce incurred costs. The Moyno Leakless stuffing box is adaptable to most electric or hydraulic driveheads for optimal versatility in preventing unnecessary fluid leakage at the wellsite. It is also designed to provide increased bearing support for enhanced stability and to eliminate premature internal drivehead wear, saving time and money. Additional design features include a floating primary seal that is isolated in a fluid bath for reliable performance and long service life; pressure equalization on the primary seal which ensures effective, leakless sealing; and increased bearing support, which optimizes stability. Select 9 at www.HydrocarbonProcessing.com/RS

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Realize Operations Innovation with Exapilot Plants are required to achieve optimal performance by increasing safety, stability, productivity and improving product quality. Exapilot electronically documents Standard Operating Procedures (SOPs) in an easy-to-use ﬂowchart format, monitors and records procedure progress, automates steps selectively by linking to the existing control system, and provides early detection of process abnormalities.

Beneﬁts UÊ,i`ÕViÊ` Ü Ì iÊV>ÕÃi`ÊLÞÊ «iÀ>Ì ÊiÀÀ ÀÃ° UÊ âiÊÛ>À >Ì ÃÊ Ê«À `ÕVÌÊµÕ> ÌÞÊ> `Ê«À `ÕVÌ ÊÛ Õ iÊV>ÕÃi` by different operator skills. UÊ,i`ÕViÊÌ iÊÌ iÊv ÀÊÃÌ>ÀÌ }ÊÕ«]ÊÃ ÕÌÌ }Ê` Ü ]Ê> `ÊÌÀ> Ã Ì Ã° UÊ- « vÞÊ> `ÊÃÌ> `>À` âiÊVÀi>Ì Ê> `Ê > Ìi > ViÊ vÊ-"*Ã

Monitor operational progress Exapilot allows for monitoring the current operation progress by changing the color of the ﬂowchart steps.

Navigate appropriate actions Exapilot allows the board operator and ﬁeld operator to coordinate completion of tasks and adjust process control setpoints.

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

North America Foster Wheeler’s Global Engineering and Construction Group has signed a strategic umbrella agreement with The Dow Chemical Co. to provide project management, consulting, engineering, procurement, and construction management and construction services. This agreement has an initial term of three years. It provides support by Foster Wheeler to selected Dow global capital projects, forming part of its growth strategy across its diversified portfolio of businesses: specialty chemicals, advanced materials, agrosciences and plastics. CB&I has been awarded a contract, valued at about $300 million, by Williams Olefins, LLC, for a petrochemicals expansion project in Geismar, Louisiana. The award includes the license and basic engineering for the ethylene technology; supply of the cracking furnaces; and detailed engineering, procurement and construction of the expansion project. Plant capacity is expected to be increased from 1.35 billion lb/yr to 1.95 billion lb/yr. KBR will design and construct an ethylene furnace for INEOS Olefins and Polymers US. Upon commissioning, the furnace will reportedly provide the highest achievable ethylene yields in the industry. Agreements include provision of a technology license, engineering, procurement, supply of equipment and materials, and furnace construction. The design will add a furnace production capacity of 465 million lb/yr to the INEOS Chocolate Bayou Works Olefins Complex in Alvin, Texas. This furnace will use KBR’s high-performance Selective Cracking and Optimum Recovery (SCORE) ethylene technology and process natural gas liquid (NGL) feedstocks. The furnace will also include KBR’s latest generation Ultra-Low NOx burner technology and a Selective Catalytic Reduction (SCR) bed to reduce nitrous-oxide emissions. Chevron Phillips Chemical Co. LP will build the world’s largest on-purpose 1-hexene plant, capable of producing up to 250,000 metric tpy, at its Cedar Bayou Chemical Complex in Baytown, Texas.

Construction is targeted to commence in the first half of 2012, and the project is anticipated to start up during the first quarter of 2014. The company has executed agreements with S & B Engineers and Constructors, Ltd., to engineer and build the plant utilizing Chevron Phillips Chemical’s proprietary, second-generation, on-purpose 1-hexene technology, which produces comonomer-grade 1-hexene from ethylene with exceptional product purity. UOP LLC, a Honeywell company, will invest $20 million to expand its production facility in Mobile, Alabama, to produce adsorbents and catalysts. The investment will expand production of Honeywell’s UOP IONSIV Ion Exchange adsorbents, which remove radioactive material from liquid, and are being used in Japan in response to last year’s nuclear disaster. It will also support the production of new adsorbents and catalysts used by petrochemical producers and refiners. The expansion is expected to be completed in the fourth quarter of 2012. The Mobile, Alabama, plant also produces Honeywell UOP ADS-47 Parex adsorbent. This latest generation of the company’s Parex adsorbent is said to increase yields of paraxylene by more than 20% over previous technology. CB&I has been awarded a contract, valued in excess of $55 million, by Trans Mountain Pipeline ULC, operated by a subsidiary of a Canadian subsidiary of Kinder Morgan. The scope of the contract includes the design, fabrication and construction of storage tanks and associated works for the Trans Mountain Pipeline ULC’s terminal located in Sherwood Park, Alberta, Canada. The project is scheduled for completion in 2013. The Dow Chemical Co. will construct a new world-scale ethylene production plant at Dow Texas Operations in Freeport, Texas, as part of Dow’s previously announced comprehensive plan to further connect its US operations with cost-advantaged feedstocks available from increasing supplies of US shale gas.

The new ethylene production facility at Dow Texas Operations will employ up to 2,000 workers at its construction peak. Over the next five to seven years, Dow estimates that this project, together with all other planned projects announced as part of the company’s comprehensive US investment plan, will employ up to 4,800 workers during peak construction and support over 35,000 jobs in the broader US economy. The project is on track for start up in 2017, and Dow continues to develop feedstock supply arrangements for this new asset. Dow’s board of directors has authorized capital to finalize detailed engineering and purchase long lead-time equipment for a new, world-scale propylene production facility to be constructed at Dow Texas Operations. Basic engineering work for the new on-purpose propylene production facility at Dow Texas Operations has commenced, and the project is on track for production start up in 2015.

Europe Jacobs Engineering Group Inc. has a contract from Afipsky Refinery, located in the Krasnodarskij Region of Russia, to develop a basic-engineering package for an amine regenerator unit, a sour-water stripper and an expected 55-tpd sulfur recovery unit (SRU). All three units are part of a refinery extension project that includes a hydrotreater unit and a visbreaker unit.

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 JUNE 2012

I 27

HPIN CONSTRUCTION The SRU design is based on Jacobs’ proprietary EUROCLAUS process and is being executed from Jacobs’ office in Leiden, The Netherlands. Jacobs is working closely with the Moscow-based engineering, procurement and construction (EPC) contractor, Giprogazoochistka, which is Russia’s leading engineer of gastreating units and SRUs. A subsidiary of Foster Wheeler AG’s Global Engineering and Construction Group has been awarded an engineering, procurement and construction management (EPCM) services contract by TOTAL Raffinage-Chimie for the revamp of a hydrodesulfurization unit at TOTAL’s refinery in Antwerp, Belgium. The hydrodesulfurization unit revamp should enable the refinery to produce jet fuel with sulfur content below 30 ppm, and diesel with sulfur content below 10 ppm, in accordance with European Union requirements. Foster Wheeler has already completed the front-end engineering design for this revamp, which is expected to be mechanically complete by the end of July 2013.

Jacobs Engineering Group Inc. will provide engineering, procurement and construction management (EPCM) services to support the upgrade of an Olefins 4 plant at Saudi Basic Industries Corp.’s (SABIC’s) petrochemical production complex in Geleen, The Netherlands. Officials did not disclose the contract value; however, they noted that the project is scheduled to be completed in 2013 as part of the scheduled plant turnaround. Jacobs is executing the work from its office in Meerssen, The Netherlands, which is close to the site. The project involves numerous modifications to the existing Olefins 4 naphtha cracker, which are expected to result in a significant increase of energy efficiency, as well as increased ethylene production capacity. BP Raffinaderij Rotterdam B.V. has awarded Jacobs Engineering Group Inc. a contract to provide engineering and procurement services, as well as engineering assistance during construction, commissioning and startup, for a major shutdown of the fluid catalytic-cracker unit (FCCU) at the Rotterdam refinery in The Netherlands.

Officials did not disclose the contract value; however, they noted that the Jacobs’ BP Program task force in Leiden, The Netherlands, and Mumbai, India, are executing the FCCU shutdown as part of an ongoing program portfolio, supported by a site-based team. The 400,000-bpd Rotterdam refining facility, which is said to be Europe’s second largest, is an important part of BP’s production capacity. Jacobs is currently executing a multi-year program of micro, mid-sized and large projects at the refinery. For the FCCU shutdown, Jacobs’ scope of work involves replacement of the end-of-life power recovery train and regenerator ballistic separator and cyclones. GTC Technology has successfully started up and met the guarantees in the commercial test run for the first unit applying the state-ofthe-art GT-BTX extractive distillation technology in the Russian Federation. The unit was licensed and installed at Kirishinefteorgsintez, Ltd. (KINEF), an OJSC Surgutneftegaz subsidiary. The technology produces high-purity benzene out of the plant’s various hydrocarbon streams containing aromatics.

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HPIN CONSTRUCTION KINEF is northwestern Russia’s leading producer and wholesaler of fuel products and chemicals serving the country’s petrochemical, paint and construction industries. The company produces motor gasoline, diesel fuel, jet fuel, fuel oil, petroleum bitumen, liquefied hydrocarbon gases, petroleum aromatics and various solvents. Rosneft has selected Haldor Topsøe’s technology for two hydrogen units at its Kuibyshev and Syzran refineries. Both units will supply hydrogen to produce ultra-lowsulfur diesel. The diesel produced will meet Euro 4 specifications, which come into effect in Russia in 2015. Both units will have a capacity of 50,000 Nm3/h, and they will be based on Haldor Topsøe’s radiant wall SMR technology.

project. ABB provided the basic design, detailed engineering, procurement, commissioning and startup for the plant. The scope of supply included a 10-ton automatic batch blender with a mass-flow metering collector, one drum decanting system, one tanker unloading system with its 8-in. pigged line and the Lubcel control system with a VPN connection for automatic management of production activities. ABB also supplied the valves, instruments, pumps, filters and pipe fittings. This new LOBP started operations in the summer of 2011, and it now runs to the company’s complete satisfaction. Oryx Lubrifiants Togo SA aims to reach an output capacity of 18,000 tpy in one shift to serve all segments and markets in West Africa, especially the needs of the minerals and mining industry.

Africa ABB has started up a new lube-oil blending plant (LOBP) built by Oryx Lubrifiants Togo SA, an affiliate of Oryx Oil and Gas, part of the Addax and Oryx Group, in Togo, West Africa. Located in the free-trade zone of the Lomé harbor, this new LOBP is a grassroots

Saudi Arabia, which will reportedly be the world’s largest chemical complex ever built in a single phase. The onsite gases supply contract includes a HyCO facility for the production of CO and H2, plus an ammonia plant. Linde will be investing $380 million in the project. Sadara, established in October 2011, is a joint venture developed by Saudi Aramco and The Dow Chemical Co. Linde’s Engineering Division will design, deliver and construct the new turnkey gases facilities at Sadara’s site in the Jubail 2 petrochemical cluster. The company will be building a two-stream HyCO plant, plus a single-stream NH3 unit producing waterless liquid ammonia. Linde will also install a large NH3 storage tank. The production units are scheduled to be ready in 2015. Once built, they will be operated by Linde’s Gases Division.

Middle East The Linde Group and Sadara Chemical Co. have signed a long-term contract that will see Linde supply Sadara with carbon monoxide (CO), hydrogen (H2) and ammonia (NH3) at a chemical complex now being built by Sadara in Jubail,

A subsidiary of Foster Wheeler AG’s Global Engineering and Construction Group has been awarded a contract by Abu Dhabi National Chemicals Co. (ChemaWEyaat) to provide project management consultancy (PMC) services for an

HYDROCARBON PROCESSING JUNE 2012

I 29

HPIN CONSTRUCTION aromatics complex (Stage I of the Tacaamol Project) and the supporting infrastructure. The aromatics complex will be located at the Madeenat ChemaWEyaat Al Gharbia site, east of the Ruwais Industrial Complex in the Emirate of Abu Dhabi. It is planned to convert almost 3 million tpy of heavy and medium naphtha, supplied via pipeline from the Takreer Ruwais refinery, into paraxylene, mixed xylenes and benzene. The infrastructure required to support the new complex includes a dedicated export tank farm, jetty and loading berth(s). Foster Wheeler will provide PMC services for the front-end engineering design (FEED) phase of the aromatics complex and infrastructure. The contract also includes an option for Foster Wheeler to provide PMC services for the engineering, procurement and construction (EPC) phase. If ChemaWEyaat elects to award this additional work to Foster Wheeler, a separate and subsequent booking will be made.

Asia Pacific Fluor Corp. has a contract award from PETRONAS Gas Berhad, a subsidiary of PETRONAS, to provide front-end engi-

neering design (FEED) services for a new liquefied natural gas (LNG) regasification terminal in Malaysia. The new terminal will supply gas to an adjacent 300-MW combined-cycle power plant in the town of Lahad Datu, Sabah. Fluor will be utilizing local subcontractors and suppliers for the project’s various facets. This contract further consolidates Fluor’s position in Malaysia, where the company is performing other projects in the oil-refining sector and in the LNG regasification business, and where significant project growth opportunities are expected in the near term. IRPC Public Co., Ltd., has selected Axens to supply technologies for its new Upstream Project for Hygiene and ValueAdded Product (UHV project). The complex is due to come onstream in 2015. The project will convert atmospheric residue to high-value propylene and aromatics-rich gasoline cuts. Axens’ technologies include the following project units: • Atmospheric residue desulfurization unit (Hyvahl)—25,000 bpsd

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• C4-cut purification system (Alkyfining)—11,400 bpsd • C 4 olefins oligomerization unit (Polynaphtha)—11,400 bpsd • Cracked gasoline selective desulfurization unit (Prime-G+)—10,800 bpsd • Unsaturated liquefied petroleum gas (LPG) treatment unit (Sulfrex)—28,000 bpsd. The Hyvahl unit will improve the feed quality to the deep catalytic-cracking (DCC) unit while co-producing a diesel cut that can be subsequently upgraded. The DCC technology is licensed by Shaw’s Energy and Chemicals Group. The technology will maximize propylene production at more than 280,000 tpy through a FlexEne integrated scheme. By further processing the C4-olefinic stream issued from the catalytic-cracking unit, this scheme maximizes propylene production. This stream is processed through an Alkyfining unit (purification step), a Polynaphtha unit (oligomerization step), and then the oligomers are recycled to the catalytic-cracking step. The unconverted C4 from the Polynaphtha unit is a paraffin-rich cut suitable for a steamcracking unit or LPG pool. Synthesis Energy Systems, Inc. (SES) has entered into a cooperation framework agreement for coal to ammonia for the fertilizer market in China with Beijing Zhonghuan Engineering & Project Management Co., Ltd. (ZEP). Under agreement terms, SES and ZEP will jointly explore undertaking a nitrogenous fertilizer retrofit project using SES’U-GAS gasification technology, with the goal of developing it into a demonstration project. If the results of this undertaking are successful, SES and ZEP intend to establish an exclusive cooperation based upon retrofitting many of the existing ammonia projects in the nitrogenous fertilizer industry in China with SES gasification technology, combined with ZEP engineering and project management. SINOPEC SABIC Tianjin Petrochemical Co. (SSTPC) has laid the foundation for a polycarbonate production complex with 260,000-metric-tpy capacity, at a ground-breaking ceremony in the Tianjin Binhai New Area, China. Previously, SINOPEC and SABIC had cooperated on an ethylene-production project with a capacity of 1 million metric tpy. Incepted in October 2009, SSTPC is a joint venture with SINOPEC and SABIC

HPIN CONSTRUCTION each holding 50% equity. The Phase One project, with 1 million metric tpy of ethylene, began production in January 2010. With a total investment of $1.7 billion, and covering a ground area of 67 hectares, this polycarbonate production complex is the Phase Two project. The new polycarbonate production complex, which will include two sets of phosgene-free production systems with a capacity of 130 kilo-metric tpy each, is expected to start up in 2015. Upon operation, it can produce four major classes of polycarbonate. The project uses the world’s leading non-phosgene polycarbonate manufacturing technology, which complies with China’s national energysaving and carbon-emission policy. Mitsubishi Gas Chemical Co., Inc. (MGC) has decided to expand the polyacetal (POM) production facility at Korea Engineering Plastics Co., Ltd. (KEP), an MGC affiliate based in South Korea, to increase its capacity by 35,000 tpy. In 1988, KEP began production of POM using MGC technology at its plant in Ulsan. Production has now reached over 100,000 tpy. The additional 35,000ton capacity made possible with MGC technology will be combined with the current capacity to bring KEP’s total POM production capacity to 140,000 tons. The new facility’s construction will start in the first quarter of 2012 and will be completed in the fourth quarter of 2013. Commercial operation is scheduled to begin in the first quarter of 2014. UGL Ltd., in a 50/50 joint venture (JV) with engineering, procurement and construction (EPC) firm CH2M HILL, has been awarded a $550-million contract (total JV) by JKC Australia LNG Pty Ltd. (a company established by a JV between JGC Corp., KBR and Chiyoda Corp.) for the construction of a combined-cycle power plant for the Ichthys liquefied natural gas (LNG) project in the Northern Territory. As part of the agreement, GE will engineer and supply gas turbines, steam turbines and heat recovery steam generators for the $34-billion Ichthys project. The CH2M HILL-UGL JV will design and supply the balance of the plant based around the GE technology, as well as undertake the complete construction of the project. GE’s gas and steam turbine technology will efficiently and reliably generate elec-

tricity for the onshore facility based at Blaydin Point, Darwin, enabling it to produce more than 8 million tpy of LNG. GE will supply five GE Frame 6B gas turbines and three SC4 single-flow steam turbines that will provide 500 MW of installed power capacity for the facility. Design, procurement and fabrication for the combined-cycle power plant works are expected to commence immediately, with an onsite commencement in mid-2013 and completion expected by the end of 2016. Trafigura Pte Ltd is investing up to $130 million in a significant equity stake (up to approximately 24%) in the Nagarjuna Oil Corp., Ltd. (NOCL) oil refinery. The refinery is being constructed at Cuddalore in the State of Tamil Nadu, India. In addition to acquiring an equity stake, Trafigura will invest a further $120 million into the construction of extensive storage facilities and associated infrastructure at the refinery’s 2,500-acre site. Trafigura’s investment in the NOCL refinery is the first of its kind for the company, enabling it to create operational efficiencies and to add value to its cus-

tomers’ supply chains. Geographically, the facility is well positioned to receive crude oil from Trafigura’s international producer partners. The refinery, to be operated by NOCL, will have a capacity of 6 million tpy. It can process 100% heavy/sour grades of crude and will supply light and middle distillates up to Europe 4 standards. Other partners in the project include TIDCO, a Government of Tamil Nadu enterprise, and Tata Petrodyne, a Tata Group enterprise. Commissioning work at the refinery is expected to start this year with commercial operations scheduled to begin during the first half of 2013. BASF India Ltd. will invest €150 million to set up a new chemical production site at the Dahej Petroleum, Chemicals and Petrochemicals Investment Region (PCPIR), located in Gujarat, India. The new site will be an integrated hub for polyurethane manufacturing and will also house production facilities for care chemicals and polymer dispersions for coatings and paper. The start of production is planned for 2014.

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HPIN CONSTRUCTION UOP LLC, a Honeywell company, has announced that its UOP C3 and C4 Oleflex processes have been selected by China’s Shandong Chambroad Petrochemicals Co. to produce key petrochemicals. The plant will reportedly be the first in China, and only the second in the world, to combine both processes, which are used to produce propylene and isobutylene, respectively. The new units, expected to start up in 2014, will produce 133,000 metrictpy propylene and 87,000 metric-tpy of isobutylene at its facility in Binzhou City, Shandong Province, China. Honeywell’s UOP will provide the engineering design, technology licensing, catalysts, adsorbents, equipment, staff training and technical service for the project. ThyssenKrupp Uhde and representatives of the Mongolian government have signed two memoranda of understanding (MOU) relating to the development, engineering and construction of both a coal-to-liquids plant and a heat-recovery coke-making plant. Feasibility studies for the two projects had already been prepared at an earlier date.

At the same time as the MOU, ThyssenKrupp Uhde also signed a licensing agreement with the Ulan Bator-based company Industrial Corporation of Mongolia for the use of ThyssenKrupp’s proprietary PRENFLO coal-gasification technology. The Mongolian government has been intending to limit fossil-fuel imports for quite some time, and to instead increasingly use its abundant domestic coal deposits. It has, therefore, set itself the goal of upgrading this domestic coal and converting it into high-grade chemical and petrochemical products. As a primary measure, the Mongolian government intends to build a coal-to-liquids plant in Mongolia to produce synthetic fuels from coal. Air Products has signed an agreement with JKC Joint Venture (JV) and INPEX Operations Australia Pty. Ltd. for the supply of the liquefaction technology and main cryogenic heat exchangers for two process trains that will produce a total of 8.4 million tpy of liquefied natural gas (LNG). Air Products’ LNG heat exchanger technology will operate in Darwin, Australia, as part of the Ichthys LNG Project (INPEX

76% Operator; Total 24%), expected to be onstream by the end of 2016. Under the agreement with JKC and INPEX, Air Products will provide two main cryogenic heat exchangers with a proprietary propane pre-cooled mixed refrigerant process using the SplitMR machinery configuration to produce the LNG. The LNG units will process natural gas from the substantial reserves located in the Browse Basin offshore Western Australia. JKC Joint Venture is a JV comprising JGC Corp., KBR and Chiyoda Corp. INPEX Operations Australia Pty. Ltd. is acting as an agent for, and on behalf of, Ichthys LNG Pty. Ltd. Showa Shell Sekiyu K. K., GS Caltex and Taiyo Oil have signed memoranda of understanding (MOU) for a new paraxylene (PX) project. In the MOU, the three companies agreed to cooperate in materializing the new PX project to increase production capacity from 1.35 million tpy to 2.35 million tpy at the GS Caltex Yeosu Complex in Korea. With the completion of this capacity increase, this plant will reportedly become the world’s largest plant at a single site. HP

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CRYO-PLUS™ Get More Valuable Liquid from your Gas Streams Linde Process Plants, Inc. provides engineering, design, fabrication and construction of cryogenic plants for the extraction of hydrocarbon liquid from natural gas, refinery and petrochemical gas streams. Recovered liquid components can include ethylene, ethane, propylene, propane, isobutane as well as other valuable olefinic and paraffinic hydrocarbons. Combine your CRYO-PLUS™ plant with a Linde PSA to recover high purity hydrogen from refinery and petrochemical off-gas streams.

Why choose Linde’s CRYO-PLUS™ – Proprietary technology with a proven track record in: – Refinery Off-Gas – Petrochemical Off-Gas – Natural Gas – Robust, adaptable and flexible design, and operation – Typical payout times of six (6) months to two (2) years

A member of The Linde Group Linde Process Plants, Inc. 6100 South Yale Avenue, Suite 1200, Tulsa, Oklahoma 74136, USA Phone: +1.918.477.1200, Fax: +1.918.477.1100, www.LPPUSA.com, e-mail: sales@LPPUSA.com Select 85 at www.HydrocarbonProcessing.com/RS

HPI CONSTRUCTION BOXSCORE UPDATE Company

City

Project

Egypt Egypt

ETHYDCO Egyptian Refining Co

Alexandria Cairo, Mostorod

Ethylene Hydrotreater, Naphtha

Togo

Oryx Energy Co

Lome

Blending, Lubes

BPCL Pertamina PIHC Petronas Petronas Gas Bhd

Kochi Cilacap Papua Johor Bahru, Pengerang Kuala Lumpur

Refinery Refinery Petrochemical Complex Refinery LNG Terminal

Total E&P Canada Ltd

Fort McMurray, Voyageur

Upgrader, Heavy Oil

Mozyr Refinery Total Raffinage Dist. Dioki d.d. SONHOE Dev. Co. PCK Raffinerie GmbH SABIC Europe State Agency for Inv and Natl Proj of Ukraine

Mozyr Antwerp Krk Teesside Schwedt Geleen Black Sea

Treater, Tail Gas Hydrodesulf (HDS) Polyvinyl Chloride (PVC) Refinery, Heavy Ends Visbreaker (VBU) Olefins LNG Terminal

Itaborai Barrancabermeja Cartagena Cartagena Piura, Talara Refinery

Processing, Heavy Oil Processing, Heavy Oil Refinery, Heavy Ends Treater, Jet Fuel (3) Refinery

Jubail, Jubail 2 Ind Zone Jubail, Jubail Ind City Jubail, Jubail Ind City Yanbu Yanbu Yanbu Abu Dhabi

Gas Processing Complex Fatty Alcohols Coker, Delayed Mercaptans Storage, Oil NGL Fractionation

Roxana, Wood River Cameron Parish Hahnville Baytown Freeport Freeport Houston

Processing, Heavy Oil LNG Liquefaction Plant (4) Ethanolamine Hexene Ethylene Propylene (2) Storage, Oil

Ex Capacity Unit

Cost Status Yr Cmpl

Licensor

Engineering

Constructor

AFRICA 460 t/a 22600 bpsd

600 2044

E H

2015 2015

2012

U E P F F

2015 2014

2006

2016

240 t/a None 120 Mtpy 250 Mbpd 35 Mbpd None 5 Bcm

3300

E U H S C E P

2013 2013 2012 2014 2012 2013 2015

150 250 165 22 95

Mbpd bpd Mbpd Mbpd Mbpd

8400 3400 1400 800 1300

U U F U E

2013 2016 2013 2015 2015

3 83 114 12 6 27

None MMtpy Mtpy Mbpsd Mbpsd t/a Mtpd

380 20000

U U P E E H U

2015 2016 2013 2014 2014 2014 2013

Mbpd Bcf Mm-tpy m-tpy None 900 tpy 3.2 MMbbl

3000 3900

U U U U P U U

2015 2018 2012 2014 2017 2018 2013

18 t/a

KTI|ConocoPhillips Co. Technip|Axens

Enppi|Toyo Engineering Corp. Mitsui|GS E&C GS E&C ABB Cellier

ASIA/PACIFIC India Indonesia Indonesia Malaysia Malaysia

EX RE EX

120 340 2 300

bpd bpd MMtpy bpd None

2800 5200 1670

2016

Technip Fluor

CANADA Alberta

200 Mbpd

EUROPE Belarus Belgium Croatia England Germany Netherlands Ukraine

Jacobs

LATIN AMERICA Brazil Colombia Colombia Colombia Peru

Petrobras Ecopetrol Reficar Ecopetrol Petroperu

TO RE RE EX

Merichem

CB&I CB&I Tecnicas Reunidas

MIDDLE EAST Saudi Arabia Saudi Arabia Saudi Arabia Saudi Arabia Saudi Arabia Saudi Arabia UAE

Sadara Chemical Co. Sadara Chemical Co. SABIC Saudi Aramco Saudi Aramco Al Rajhi Petrochemical GASCO

1100 1202

Lurgi Zimmer Conoco Phillips Co Conoco Phillips Co

Tecnicas Reunidas Tecnicas Reunidas

Linde Linde|ABB Lurgi Zimmer Tecnicas Reunidas Tecnicas Reunidas

Shell|WorleyParsons

GS E&C

Bechtel

S&B

UNITED STATES Illinois Louisiana Louisiana Texas Texas Texas Texas

ConocoPhillips Cheniere Energy, Inc. Union Carbide Chevron Phillips Chemical Dow Chemical Dow Chemical Oiltanking

EX RE

240 16.9 45 200

400 200

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Use adaptive modeling to revamp and maintain controllers The right tools can improve refinery APC applications S. LODOLO, Aspen Technology Inc., Bologna, Italy; M. HARMSE, Aspen Technology Inc., Houston, Texas; A. ESPOSITO and A. AUTUORI, ENI R&M, Rome, Italy

NI Refining and Marketing (ENI R&M), like many other operating companies, found itself challenged to properly maintain its large, installed base of existing advanced process control (APC) applications with a reduced workforce. Frequent lube oil production changes were being made to capitalize on supply chain opportunities. The limited APC resources were struggling to keep up, as these changes required updates to the controller models to ensure that the APC solutions continued to generate the highest value. After reviewing new tools and methodologies to improve efficiency, ENI R&M selected performance monitoring, automated testing and adaptive modeling tools for APC from a trusted technology provider. ENI R&M tested the adaptive modeling tool at its Livorno refinery in Italy with positive results, prompting the company to deploy adaptive modeling programs at its other refineries.

ENI R&M Livorno refinery. The Livorno refinery is a fuels

and lube oil refinery with a significant number of installed APC applications. Fig. 1 shows a simplified refinery layout. The refinery runs 13 medium- to large-scale model-predictive controllers (MPCs) and 24 inferential modeling applications, for a total of 210 manipulated variables (MVs) and 92 inferential properties. Fig. 2 shows the refinery’s APC coverage. APC applications cover all major process units, and additional controllers are planned for the remaining plants. Since it is a lube oil refinery, Livorno’s frequent lube oil production changes affect operations and, therefore, the APC application’s performance. This is a significant change in addition to normal crude oil changes and crude oil quality disturbances. For these reasons, APC maintenance for best performance is an ongoing task that keeps the site APC engineer continually engaged.

• Internal staff familiar with the application move to a different position, and new staff may not be able to immediately support the application or may require significant training to understand and support it • Processes are often changed, and these changes can affect controller performance • Catalyst changes, exchanger fouling and changes to valves and other instrumentation can lead to degradation • Routine maintenance on instrumentation and equipment can impact performance • Economic changes affect the steady-state solver solutions, and if they are not recognized and accommodated, performance may degrade or the controller may lose money instead of accumulating profits. Typical signs of performance degradation are: • Sub-controllers in “off ” status and MVs or controlled variables (CVs) are routinely out of service or in distributed control system (DCS) “local” status • Some CVs never reach steady-state targets before these targets change • Some CVs remain outside limits for extended periods • Many MV limits are clamped or MVs are at setpoint—i.e., with high/low limits set to identical values

Gasoline components (LCN, ETBE) Intermediate product (Gasoil, full-range, LCO)

Crude

Sustaining APC benefits. It is something of a misnomer to

say that APC applications require maintenance. If nothing in the plant ever changes, then almost no maintenance and no model updates are required. However, if significant changes are made to the process, or if feedstock characteristics change significantly, then the APC models must be made “aware” of these changes. When model updates are not performed, or when regular controller maintenance is not carried out due to significant process and instrumentation changes, the performance of the APC system starts to degrade. There are many potential reasons for performance degradation, but some of the most likely are listed below:

Atmospheric distillation

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HYDROCARBON PROCESSING JUNE 2012

I 37

SPECIALREPORT

PROCESS/PLANT OPTIMIZATION

• Some MVs show “noise” response with frequent change of direction • Almost all MVs in a controller are moving on every controller execution • MV dynamics are often limited by the maximum move limit • CV prediction error tends to be positive and then negative for extended periods, indicating model mismatch • Cycling CVs or MVs • Unstable linear programming (LP) solution—i.e., steady-state targets flip frequently • Primary controls do not hold setpoints • Control is too aggressive, even with insignificant CV error • Controller is overly aggressive, with secondary objectives. The typical manual APC maintenance workflow is labor-intensive and inefficient, since it is largely reactive and not proactive. The APC maintenance workflow goes through the following major steps: 1. Control • There is a change in process or operating mode • The controller begins to oscillate or perform badly • Operators begin clamping MVs or taking out MVs/CVs, or entire sub-controllers. 2. Detect • The control engineer usually is not automatically alerted to the problem • Operators will likely call for help only when the problem becomes too severe to tolerate

Carb. BAL Lube

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• The control engineer may spot the issue while checking trends or controller limits, or when passing by the control room. 3. Diagnose • At some point, the control engineer spots the issue or is notified by a keen operator • The control engineer will attempt a manual diagnosis by speaking with operators and analyzing data either online or offline. 4. Repair • Diagnosis is completed • The problem may be ignored or manually repaired; often, a sub-optimal solution is implemented (e.g., the controller is de-tuned or gains are manually adjusted) • Small problems tend to build up until parts of the controller or the entire application are switched off; a major revamping step then must be undertaken. The control engineer must often manually extract process data to isolate the root cause. After the nature of the problem has been determined, the manual model-building method prolongs the amount of time needed to correct the problem and return the controller to full service. If maintenance is deferred, the problems slowly accumulate until a major revamp must be undertaken. This approach is inefficient, and it causes a loss of benefits that can be as high as 50%–60% during the four- to five-year application lifecycle. With supporting automation, this workflow can be

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APC coverage at the Livorno refinery.

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SPECIALREPORT

PROCESS/PLANT OPTIMIZATION

significantly streamlined, and the time and effort needed to keep the controllers at peak efficiency can be reduced. Successful APC application maintenance requires plans and practices to be aligned with business strategy and supported by management, which ensures that tools, people and processes are in sync (Fig. 3). A proper APC maintenance methodology should have the following characteristics: • Incorporates APC best practices • Minimizes effort by automating and simplifying maintenance tasks • Uses proper baselines, as well as key performance indicators (KPIs) covering both controllers and models • Uses automated reports to rapidly detect changes in performance • Employs diagnostic rules to isolate root causes of performance degradation and make quick assessments of problems • Uses automated step testing to quickly generate high-quality data for improved models, which relieves engineering from manual testing • Prepares data for modeling using preprocessing rules, establishes automated data-cleaning tasks, and minimizes the need to manually slice data • Automatically generates new models without extensive engineering effort

5. KPIs 1. People

4. Training

2. Work processes

FIG. 3

3. Tools and technology

Successful APC maintenance requires alignment of plans and practices.

Sustained value tools. The sustained value tools supporting detection, diagnostics and repair are described below. Performance monitoring. A proprietary performance-monitoring tool has the capability to create a history of controller and process data, build baselines, calculate controller and process KPIs, and automate reporting. Using these performance KPIs, the user can rapidly detect when the process is not operating at peak performance. Model KPIs show the specific MV/CV pairs that are contributing to poor performance. Automated step testing. An MPC is used to maintain the process within specifications at all times. The automated steptesting tool supports single-test and multi-test methods, and it produces richer data more quickly than manual step testing, since it enforces APC best practices and estimates the largest possible MV steps while maintaining the process within constraints. Much of the plant testing can now be performed without engineering supervision. Adaptive modeling. This tool automates the maintenance lifecycle of a controller by enabling the collection of historical data; automating calculations for data cleaning; scheduling online model quality (MQ) assessments; and running standard and custom KPIs to assess MQ, model diagnostics and online model identification (ID). All of this automated workflow is performed online, from a web interface, directly on the running controller. There is no need to start a data collection task, extract data, move data between systems, model or tune offline, or start or stop applications. The process is fully streamlined, and it enforces APC best practices at all stages. It also gives the APC engineer the capability to control and influence the results while eliminating routine manual activities. The methodology is designed to enable APC end-users to perform regular, proactive APC maintenance on their own, without involving an external consultant. End-users should hire an external consultant only in the case of a major process revamp and never for routine maintenance, since the tools and Repair methodology now enable non-experts to efficiently maintain APC applications.

Control

Detect

Diagnose

Operating mode changes

Control engineer is alerted by process, and models KPIs

Drill-down tools to provide performance diagnostics

Automated model creation leads to faster model repair

Model quality analysis pinpoints the models to be repaired

Automated retesting reduces model revamp

Controller begins to oscillate Operators clamp feed and product draws FIG. 4

• Avoids manual data collection and the movement of data through different servers, and does not use flash memories or other media to cross firewalls • Simplifies and streamlines to be proactive instead of reactive. Technology continues to improve, and tools that enable a proactive maintenance methodology are available on the market. With this kind of automation, the four steps to maintain an APC application described previously can now be performed differently, as depicted in Fig. 4.

Automated APC maintenance workflow.

I JUNE 2012 HydrocarbonProcessing.com

Livorno refinery proof of concept. Among the Livorno refinery’s APC

applications, there are two hot oil circuits: HOTOIL1 and HOTOIL2. The first circuit delivers around 65 MM Kcal/h, and the second delivers around 25 MM Kcal/h, to reboilers and other exchangers in plants throughout the refinery. Fig. 5 shows a simplified screenshot of the circuits. The adaptive modeling evaluation focused on the HOTOIL1 circuit control-

PROCESS/PLANT OPTIMIZATION ler, and specifically on the F1 furnace. The HOTOIL1 controller design includes the following attributes: • 11 MVs, 54 CVs, and nearly 100% service factor o Most MVs are related to the F1 furnace o Most CVs are valve outputs of hot oil user control loops o Controller was originally deployed in 2005. • Controller objectives and benefits o Operations flexibility and maximization of delivered duty when required o Rejection of disturbances o Temperature and loop pressure stability o Optimization of furnace combustion. • Controller main constraints o Loop pressure and return temperature o Feed pump capacity o Furnace skin temperature, draft and excess O2. Likewise, the F1 furnace design includes four cells, eight passes, mixed fuel gas/fuel oil burners, four dampers and one blower with backup, as shown in Fig. 6. An evaluation of the new tool and methodology was conducted in a meeting room near the control room, with around 15 APC engineers from several ENI R&M refineries. Efficiency control of the F1 furnace—which uses a multivariable MPC—was found to have been running with limited capability for some months, due to model degradation after field equipment maintenance. The service factor was still around 100%, but significant benefits were left on the table. A model revamp for that section was required, since the old models could not run on a closed-loop system after the process changes. The furnace was found to be an ideal candidate for an adaptive modeling pilot project.

SPECIALREPORT

Six MVs were involved in the maintenance activity, which began with the scenario described in Table 1. The two-day evaluation encompassed the following steps: 1. Controller performance assessment through baselines and KPIs 2. Automated step-testing tool configured and run throughout the entire process 3. As-is MQ assessment performed 4. Automated data cleaning and case setup on the performance monitoring system 5. Model ID iterations 6. Online model update and deployment 7. Post-revamp MQ assessment. A virtual machine connected to the ENI R&M control network was used for the evaluation. All work was done online from the production control web server operator interface. During automated testing activity, the engineer group had time to discuss maintenance methodology, and revise baselines and KPIs. The most interesting KPI that was discussed and enabled is a modified version of the utilization factor (UTL), which is available as part of a collection of built-in KPIs in the refinery’s performance monitoring system. The idea of a UTL was first proposed by Allan G. Kern in Hydrocarbon Processing in October 2005. This KPI, modified by ENI R&M engineers, is defined as follows: ENI_UTL = (CCS + MFU + MOK) ÷ IPMIND ⫻ 100 where: CCS = Number of CVs at high/low limit, setpoint, ramp or external targets MFU = Number of MVs at external target or engineering limits

TABLE 1. Furnace 1 specifications prior to maintenance activity MV

Description

00DC2AOP

Chamber A damper position

00DC2BOP

Chamber B damper position

00DC2COP

Chamber C damper position

00DC2DOP

Chamber D damper position

Strategy

Constraints

Status

Cost maximize

Chamber draft and balancing

Out of service

Cost maximize

Chamber draft and balancing

Out of service

Cost maximize

Chamber draft and balancing

Out of service

Cost maximize

Chamber draft and balancing

Out of service

90FC23ASP

Blower flowrate SP

Cost minimize

Excess O2, air-to-fuel ratio

Overconstrained

90FC23BSP

Backup blower flowrate SP

Cost minimize

Excess O2, air-to-fuel ratio

Overconstrained

FIG. 5

Simplified screenshot of hot oil circuit controllers.

FIG. 6

Simplified screenshot of F1 furnace.

HYDROCARBON PROCESSING JUNE 2012

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SPECIALREPORT

PROCESS/PLANT OPTIMIZATION

MOK = Number of MVs at minimum movement, wound up, in bad status or taken out of service by the engineer IPMIND = Actual number of MVs in the controller. A favorable performance for this KPI guarantees that the controller is not only on, but that it is also moving and using all available MVs to push constraints—i.e., to accumulate APC benefits. A multi-test mode was used in the MPC from the beginning. This allowed the MVs to be tested simultaneously to

FIG. 7

Complete model matrix plot.

FIG. 8

Models can be inspected as step responses or as bode plots.

FIG. 9

Step-test data for three hours vs. 20 hours.

I JUNE 2012 HydrocarbonProcessing.com

minimize step-testing time, while minimizing MV correlation and maximizing the signal-to-noise ratio to enhance MQ. As the automated tester evaluated the unit, the group concentrated on adaptive modeling usage and results, as outlined below: • View and clean up the MQ data o User can view the data used in the MQ analysis evaluation o Some data cleaning is automatically performed o The engineer can manually clean the data further, using a web viewer o Calculations for automated data cleaning can be configured (e.g., when an MV is moved to DCS control or when a CV control error is too high). • Run an MQ test o Run the test from the web viewer o Schedule a recurring MQ test at a designated time and interval o Model KPI carpet plots are automatically updated. • Configure and run a model ID case o Browse the performance monitor’s database for tags to include in the model ID case o The ID case can be run on demand or scheduled to run automatically, at a particular time and interval. • Review model and deploy o Multiple model ID cases can be compared with the current model directly in the web viewer o Bode plot analysis is available in the web viewer, to assess model uncertainty o Once satisfied, the model can be assembled and deployed online. All of these activities have been carried out online, through a web interface, using data available in the performance-monitoring database. MQ data appear as a KPI plot where each model (MV/CV pair) is flagged with different colors. The colors indicate how functional the models used by the controller are compared to those assessed with only a few MV moves. The complete model matrix is shown in Fig. 7, and the models on which the project team concentrated are highlighted in red within an oval. When an MQ case is executed, an estimated gain multiplier (gmult) value is calculated in such a way that the prediction errors

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of the corresponding dependent variable are minimized. The estimated gmult will then include contributions from the model uncertainty, not only in the steady-state gain, but also in the accuracy of the dynamics. The patented MQ technology uses the existing controller model as a reference to calculate an MQ index, which is a combination of the estimated gmult value and the calculated model uncertainty error bound. This index represents the accuracy of the model pair in predicting the process response: • Good (green) means the model pair has a high degree of accuracy • Fair (light blue) means the accuracy is somewhere between good and bad • Bad (red) means the model accuracy is low • Unknown (yellow) means a clear answer could not be derived from the data provided, likely due to insufficient significant data. During the evaluation, focus was placed on a small portion of the matrix, and MV steps were performed in that portion; this is the reason that so many red and yellow blocks can be seen in Fig. 7. In a routine maintenance activity, three to four steps should be performed for all relevant MVs for MQ analysis. After assessing if and where models need further improvement (via the MQ analysis), more steps should be implemented for the models that need to be re-identified, and the model ID results should be checked every few hours. Step testing is only performed for the MVs for which new models are needed, and only for as many as are required to obtain a sufficiently accurate model. A proper maintenance routine will require tests of only a few MVs, as models typically show some local degradation following an event. It is uncommon for the entire matrix to exhibit model accuracy issues.

FIG. 10

Reassessment of model matrix plot shows quality improvement.

Models can be inspected as step responses or as bode plots, as shown for the HOTOIL1 controller in Fig. 8. The starting model is shown in blue, while the newly identified model (based on 20 hours of step testing) is shown in pink. Note the substantial differences on the diagonal, which is exactly where the MQ analysis previously reported the model accuracy to be poor. Bode plots have been useful in monitoring modeling progress during step testing. In Fig. 9, three hours of step-test data are compared against nearly 20 hours of step-test data. It can be seen that the uncertainty bands become narrow, while the signal-tonoise ratio improves as the step test proceeds. The evaluation was stopped after 24 hours of unattended step testing, and then the updated models were replaced online from the web interface without needing to restart the controller. The effects of models and tuning changes can be directly checked online, through the production control web server interface, using a “what-if ” simulation that permits a comparison between old and new responses before deployment. Model quality was reassessed after deployment to confirm the improvement, as shown in Fig. 10. HYDROCARBON PROCESSING JUNE 2012

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SPECIALREPORT

PROCESS/PLANT OPTIMIZATION

■ Successful APC application maintenance requires plans and practices to be aligned with business strategy and supported by management, which ensures that tools, people and processes are in sync … Proactive maintenance prevents benefits degradation and nearly eliminates the need for costly “full-controller” revamps. It also permits the APC engineer to spot new opportunities to increase delivered benefits. Results. The HOTOIL1 controller was brought back into

full operation at the end of the evaluation, with the following significant results: • Correct operation for HOTOIL1’s multivariable MPC was restored, allowing for tighter control of excess O2 and draft in F1 furnace cells • Operating target was increased for dampers and decreased for blowers, since the updated models exhibited favorable performances • Excess O2 was significantly reduced • F1 efficiency increased by 1.2%, on average, after the revamp, which is significant for a 65-MM Kcal/h furnace in

terms of reduction in fuel consumption, and worth well above €100,000/year at the current cost of fuel oil. Advantages of the solution. The entire maintenance process is performed online, directly from a web viewer and on the running controller. It enforces best practices and moves maintenance from reactive to proactive, thereby maximizing controller uptime and benefits. Also, controller performance checkups become a regular activity that requires limited effort. With the use of the sustained value tools, maintenance activities are triggered by a few properly designed controller KPIs and model KPIs. These KPIs can be easily compared against one or more baselines that can be manually or automatically built in minutes. Automatic reports can be scheduled and designed to include KPIs, calculations and trends; these reports are then sent to operators, engineers and managers. KPI carpet plots, diagnostics and drill-down capabilities enable control engineers to rapidly detect and diagnose the problem, whether it is instrumentation, DCS proportionalintegral-derivative (PID) controller tuning, MPC tuning, MPC design or MPC models. Fixing the problem is then mostly automated (although still under engineer control), but it avoids the need for time-consuming manual tasks or controller downtime. A streamlined APC maintenance process with proper tools is now available to preserve APC know-how, even with APC engineers moving into other positions. Proactive maintenance prevents benefits degradation and nearly eliminates the need for

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costly “full-controller” revamps. It also permits the APC engineer to spot new opportunities to increase delivered benefits. Takeaway. The evaluation performed at ENI R&M’s Livorno

refinery clearly demonstrated the validity of the methods and tools used. The HOTOIL1 multivariable MPC section was successfully revamped in only two days through non-continuous work, with an automated tester taking care of nighttime plant testing. Models were updated and all MVs were put back in service, which delivered immediate and significant benefits of greater than €100,000/year. Other advantages included a faster model ID process due to the use of adaptive modeling features, and the capability to run MQ assessment and model ID from a web interface. The maintenance activity was completed in around 24 hours, with almost no engineering supervision during step testing, and with plenty of time to become familiar with the tools and technology. Time was available to discuss what KPIs to put in place, and how to improve controller performance. The key lesson learned from the experience was to spend available time optimizing operations and increasing benefits, and not to execute repetitive tasks. In a refinery with numerous APC applications, such as ENI R&M’s Livorno facility, there are many opportunities to improve performance, even with favorable onstream factors. These opportunities are not always noted or taken advantage of, however, due to a lack of proper tools and methodology. Also, there is not always enough time to address them when conducting work in the traditional way. HP Stefano Lodolo is a senior advisor and industry consultant with Aspen Technology in Italy. He has more than 25 years of APC field experience in the refining, chemical and petrochemical industries. Mr. Lodolo has successfully implemented dozens of MPC and other automation projects at a wide variety of process units. He holds a master’s degree in chemical engineering from Bologna University in Italy.

Michael Harmse is the senior director of APC product management at Aspen Technology in Houston, Texas. He has 28 years of experience in process control, and has completed 45 APC applications since 1994. He is the inventor of the SmartStep constrained multivariable testing technology and the SmartAudit co-linearity detection and repair tool. He is listed as the principal inventor on multiple US and EU patents. Mr. Harmse has also introduced several new APC products: Aspen SmartStep, Aspen PID Watch, Aspen Nonlinear Controller (Aspen Apollo), Aspen Fuel Gas Optimizer and Aspen State-Space Controller.

With over 50 independent subsidiaries and more than 220 engineering and sales ofﬁces spread across the world, SAMSON ensures the safety and environmental compatibility of your plants on any continent.

Andrea Esposito is a senior APC engineer at ENI R&M’s Livorno refinery in Italy. He is in charge of project development and application maintenance for APC, as well as automation at the DCS level. Before joining ENI in 2006, Mr. Esposito worked as a software engineer. He has an engineering degree in telecommunications from the University of Pisa in Italy.

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Augusto Autuori is responsible for APC project coordination

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at ENI refineries. After earning his bachelor’s degree in chemical engineering from the University of Salerno in Italy, he joined ENI in 2002 as an APC engineer. Between 2002 and 2006, Mr. Autuori participated in several APC projects, including DMCplus and inferential implementation. In 2006, he moved to the technology department at ENI R&M’s headquarters to manage APC project coordination, oil movement systems implementation at ENI’s primary logistics hubs, innovative systems implementation for plant monitoring, and operator training.

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 · www.samson.de SAMSON GROUP · www.samsongroup.net HYDROCARBON PROCESSING JUNE 2012

I 45

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PROCESS/PLANT OPTIMIZATION

SPECIALREPORT

Cybersecurity for industrial plants Consider five core elements for secure automation networks F. KÖBINGER, Siemens AG, Nuremberg, Germany

Security management. The top priority and the most

important task is to establish a security process and/or security management. In order to be able to make sound decisions regarding which measures must be taken in the end, first you must analyze which specific risks are present that cannot be tolerated. Both the probability of occurrence of a risk and the potential degree of damage play a role here. If risk analyses and

Very high

Unacceptable risk

High

Degree of damage

thernet-based communication plays a key role in the automation sphere and industrial Ethernet is being used more and more in the field area. The advantages of this are evident: with the use of open and standardized IT technology, such as wireless LAN or a web server, uniform networking also be achieved. However, this also increases the danger of access violation and so-called malware, so, at the same time, the potential risk for the automation networks is re-evaluated and security concepts are implemented accordingly. IT security in office IT networks has not been an issue for a long time—not because it is not important, but because it has become standard. Security patches and updates, encryption and passwords have been commonplace for a long time. The situation in the automation sphere is quite different. The task of making automation networks secure presents a considerable challenge as it collides with other important requirements such as “performance” and “usability.” Naturally, the additional costs here also play an important role. Furthermore, securing a network requires constant monitoring and cannot be achieved with a single set-up. Nevertheless, security is a topic that must be given top priority in automation and/or industrial plants. Uniform networking and the use of open IT standards do not only guarantee, but are also prerequisites for competitiveness in most cases. Furthermore, the ever ubiquitous reports in the media of security incidents clearly indicate that the dangers are real. The more challenging topic of “industrial security” is addressed in both national and international norms and standards, and places increasing demands on automation systems and plants. Here, particular attention is paid to securing crucial infrastructures. If security incidents in production plants largely “only” constitute monetary losses (even if sometime large), when it comes to critical infrastructures, public interest also comes into play since the general public can also be affected by disruptions. How can potential risk be significantly minimized and both sufficient and affordable security in industrial automation be achieved? There is not a panacea or a patented solution that can be used every time, since every plant has individual framework conditions, dangers and protection objectives. However, there are best practices and/or a manageable number of key points for an efficient security concept that must be considered, as individual security measures alone are patchy and insufficient, thus optimal protection can only be achieved with an overall concept. The operator is responsible for secure operation, but the manufacturer can offer support by providing corresponding consultation services and “secure” products and components.

Medium

Low

Acceptable risk

Very low

Low

Very low

Medium

High

Very high

Probability of occurrence FIG. 1

Decision table for evaluating risks according to a plantspecific risk analysis that should be verified regularly.

1 Risk analysis

2 Validation and improvement

Guidelines, organizational measures

3 Technical measures

FIG. 2

The four continuous steps of the security management process to be performed. HYDROCARBON PROCESSING JUNE 2012

I 47

SPECIALREPORT

PROCESS/PLANT OPTIMIZATION

processes to determine the protection objectives are neglected or not performed at all, there is significant risk that unsuitable, excessive or ineffective measures will be taken and that the weaknesses will not be identified and rectified (Fig. 1). The risk analysis then yields protection objectives that serve as a basis for specific measures, which must be added to both organizational and technical measures. The measures must be verified after implementation. From time to time, or if changes have arisen, the risk must be reevaluated, as the threat posed may have changed meanwhile. The process then starts again from the beginning (Fig. 2). The following elements are also part of security management: • Establishing a fundamental understanding of security among all employees (security awareness)

FIG. 3

Use of a “demilitarized zone” for data exchange between company and plant network.

• Identifying responsibilities • Defining endangered processes and corrective measures • Developing emergency plans, like what to do in the event of plant disruptions due to malicious software. Securing interfaces. This element is necessary if there is a network connection between company and plant networks. Above all, this falls within the parameters of the IT department, as it primarily concerns the definition of authorized company network to plant network access and what data may be transferred in the reverse direction. These definitions must be rendered as rules and access rights that must be implemented with technical measures. Top priorities here are network intrusion detection systems (NIDSs) and firewalls, which identify intrusion attempts across the whole network and regulate the data traffic in both directions. It is also possible to establish a so-called demilitarized zone (DMZ) in which both network participants can exchange data between them, without having to have a direct connection (Fig. 3). Protection of PC-based systems. Just as office PC systems must be protected against malware and possible gaps in the operating system or gaps in user software due to updates that must be patched, PCs and PC-based control systems in the plant network also require corresponding protective measures. Many of the tried and tested office protection systems can also be used here. One of the most well-known measures here is a regularly updated virus scanner. However, you must bear in mind that virus scanners can only identify one part of the virus (approximately 70% to 80%) and are powerless against new viruses for which patterns are not yet available. Furthermore, in the automation sphere, they cannot always be updated promptly if there is no maintenance window. Therefore, the use of whitelisting software is a good alternative to virus scanners. Whitelisting works with so-called positive lists, in which the user can specify which processes or programs may run on the computer. So if a user or malware attempts to install a program, the installation may be successful but the processes necessary for operation do not run, meaning the program cannot be started and thus no damage will occur. Manufacturers of industrial software can support users here by testing the compatibility of their software with virus scanners or whitelisting software. Just to clarify, a white list, also known as a positive list, indicates a collection of equal elements that are classified as trustworthy. Whitelisting for PCs ensures that only desired programs can be run. Protection of control levels. It has

FIG. 4

Overview of the cell protection concept.

I JUNE 2012 HydrocarbonProcessing.com

long been known that PCs and networks can and must be protected. But what measures are available for the protection of most manufacturer-specific, proprietary systems? How do you protect programmable logic controllers (PLCs) and operator stations that use neither a commercial operating system nor an older version because they have been in used for many years or even decades? Here it is not pos-

PROCESS/PLANT OPTIMIZATION sible to use third-party security software, and access to the system functions of the devices is mostly not possible at all or only possible to an extent. Therefore, at this stage, the manufacturers of automation hardware are asked to implement corresponding security mechanisms and to provide the users with plantspecific setting options. However, in order to do this, the users are prompted to ask the manufacturers about the availability of such mechanisms and to ask them to activate these, whereby setting options are offered. The fundamental robustness of the system in relation to the impact of defective data telegrams and larger, unwanted data traffic is important. The manufacturer must ensure that devices are tested for possible weaknesses and are “hardened” using specific measures, such as secure coding. Similar to PC-based systems, unused services (like an unnecessary web server), protocols and even unused interfaces in SPS and HMI systems should also be deactivated. If, for example, the functions provided by controllers—such as password protection, component encryption and copy protection—are used, further essential foundations for securing the plant network are laid. Network security. The fifth element of an industrial security concept concerns the network security. This is an important step toward a “secure” plant, since it concerns the security of the data transfer and access to the network. Very few automation devices currently have security functions that can protect communications against espionage or manipulation using encryption and/or can securely authenticate the communication partners. The situation is not likely to change soon due to the long life cycles of automation plants and their devices. Although more and more devices are equipped with these functions by the manufacturer, there will still be devices that have no such security functions due to cost optimization or other reasons. In addition, in many cases, there are real-time requirements that currently do not allow the use of performance-intensive security functions, such as encryption or secure authentication. Network segmentation and cell protection. The proven solution to this dilemma is the so-called cell protection concept. The idea is simple: You use a “security appliance” i.e. a special “hardened” network component that has security functions, such as a firewall and virtual private network (VPN). These security appliances, also known as security modules, assume the protection of the automation devices, whereby they are arranged upstream and create exclusive access to each device to be protected. The protected area is also known as cells and corresponds to a network segment, mostly to its own sub-network. Thus, the network is segmented in terms of security. The firewall can now control the access to the cells, whereby it can be determined, which network participants may communicate with each other and, if necessary, also which protocols they may communicate with. Thus not only can unauthorized access be prevented, but also the network load can be reduced as not every communication, e.g. broadcasts (reports to all network participants) may pass. The security modules can also establish secured VPN channels, so that the communication to, and from, cells can be encrypted and authenticated. Thus, the data transfer is protected against manipulation and espionage. In the future, automation system suppliers will offer these security functions in communication processors for controllers and PCs.

SPECIALREPORT

■ The security modules can also establish secured VPN channels, so that the communication to, and from, cells can be encrypted and authenticated. Thus, the data transfer is protected against manipulation and espionage. The advantages are evident: one security module can protect several other devices; therefore, you do not have to install and manage these functions in each device. Real-time communication within the cells, such as Profinet I/O communication, is unaffected by performance-intensive security functions and thus access to the cells is protected (Fig. 4). Secure automation. The effective implementation of an industrial security concept requires the involvement of the manufacturer, the user and the operator of automation technology. Norms and standards committees also must impose corresponding rules, develop standard solutions and identify appropriate preventative measures. To ensure the utmost in security, a comprehensive approach is required. Securing plant networks from malicious attacks will be an ongoing issue that plant managers must address. The five-step security solution proposed here is a step in the right direction. HP Franz Köbinger is system manager for security in the industrial communication department at Siemens AG, Industry Sector, in Nuremberg, Germany.

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Conserve energy for fired heaters Advanced ceramic fiber veneer insulation reduces heat losses and is more resilient H. YOON, SK Innovation, Ulsan, South Korea

s energy costs increase, more hydrocarbon processing companies will focus on new technologies to save energy and reduce heat loss. The petrochemical industry uses many fired heaters. These furnaces and heaters consume significant levels of energy. Energy consumption is a major cost component, and it is a determining factor for industry and facility competitiveness. New furnace linings are more efficient than older designs. Advanced linings are also more energy-efficient insulating materials. However, for older design fired heaters, total thermal efficiency is usually low, and hot spot problems occur due to partially worn-out refractory, which is less energy efficient and can increase heating costs. Consequently, maintenance engineers must find ways to conserve fuel so that the facility can remain cost competitive and profitable. With higher energy costs, investments for new thicker (more insulating) furnace linings are easily justifiable. However, the turnaround timing and shutdown production loss can be equally significant hindrances.

be done by applying a veneering system over the existing refractory. It is reported that this technology was adopted by the steel applications for many years. However, the petrochemical industry has resisted the new lining solution mainly due to fears of the veneering peel during operations. In the case of total insulation replacement with ceramic fiber modules, insulation performance will improve. But high lost-production costs from long shutdowns to dismantle existing linings, weld new studs and install the lining systems were prohibited. Another method to conduct necessary maintenance work within the allotted time was needed. In this case, the better alternative strategy was to apply a ceramic fiber veneering module system. The insulation can be improved with minimum production disruption. In addition, material costs can be reduced by 20% to 30% and increase the reliability of the furnace insulation. Retrofitting the ethylene furnaces with the ceramicâ&#x20AC;&#x201C;fiber veneering provided multiple benefits. It would increase energy efficiency and reduce maintenance costs. More importantly, it could be installed without extending the scheduled turnaround, thus minimize lost production costs, as summarized in Table 1.

Alternative method. In this case history, an ethylene unit

experienced a significant temperature rise within a few months before a scheduled turnaround. If no proper maintenance to the refractory is done during the scheduled turnaround, the longterm low-efficiency operation would continue until the next turnaround. In addition, no planned maintenance work items or material packages for the refractory lining were scheduled in the upcoming turnaround. Serious thoughts and consideration were directed on what proper actions could be taken at this time. What actions could this ethylene facility use to resolve this unforeseen development while still adhering to the scheduled shutdown and budget? Fortunately, there is a way to improve the energy efficiency of existing fired heaters without a long-term shutdown to upgrade or replace the existing refractory. Revamps of furnace linings can

Mortar line Veneering module Existing refractory FIG. 1

Schematic of veneering module construction.

TABLE 1. New refractory vs. veneering Work sequences

Experience

Cost, $ million

Schedule, day

Reliability

Risk

New refractory

1. Demolition 2. Anchor weld 3. New refractory

Mostly accepted practices

500

Good

Low

Veneering

1. Surface preparation 2. Mortar 3. Veneering module1

Very few; used in steel industries

200

High (peel-out)

2 in. to 4 in. thick ceramic fiber (121 lb/ft3 density), 300 X 300 mm module

HYDROCARBON PROCESSING JUNE 2012

I 51

SPECIALREPORT

PROCESS/PLANT OPTIMIZATION

Quality application. Despite clear advantages in both cost and schedule, caution is warranted when using veneering modules over a prolonged operation period. The key aspect of a veneering application is to minimize the risk level. In this regard, simulated shop tests should be conducted to confirm the bonding strength before it is applied to the actual fired heaters. From the shop tests, effective installation procedures

TABLE 2. Summary of casing temperature— before and after veneering installation South wall Before After Emissivity Avg. temperature, °C

East wall Before After

West wall Before After

166.2

113.9

68.1

60.9

65.2

57.1

Min. temperature, °C

25.4

22.4

66.7

58.6

48.3

Max. temperature, °C

301.7

212.2

69.5

62.4

66.9

58.4

TABLE 3. Energy savings calculation for retrofitted ethylene furnaces Before After veneering veneering Casing temperature, °C

Heat loss, Btu/ft2

462.07 1

347.76

Total loss/day

$1,591 2

$1,198

Total saving/yr

Remarks Average wall temperature Total surface area, 600 m2 Fuel unit price, $0.87/l

$143,445

can be developed for quality assurance. Critical points to be investigated as part of the shop testing include: • Reviewing the mortar consistency, especially in the mixing rate and troweling method • Preparing modules—proper layout and placement of modules • Checking bonding strength after dry-out. As for the actual field application, it is very important to ensure the structural integrity of the existing base refractory to have a proper bonding strength. If the surface to be veneered is smooth, level and structurally sound, the only surface preparation required will be brushing the surface to remove any loose dust or particles. If the surface is covered with any form of oxide or glaze coating, it is necessary to remove this coating by either chiseling or sand blasting the surface before the veneering is applied, as shown in Fig. 2. The final stage of construction is the commissioning of the lining. If there is moisture in the mortar, then the residual moisture will generate steam in the mortar layer during heat-up and crack the mortar. This cracking can seriously separate the veneering from the existing refractory. To ensure the bonding strength of the mortar, following the dry-out procedures is crucial: • The mortar holding the modules to the furnace lining should be allowed to dry before the installation is brought up to operating temperatures. • The veneered furnace should be warmed to 250°F–350°F and maintained at this temperature for at least six hours before increasing to operating temperature. • Heating rates after drying on the initial heat up should not exceed 100°F/hr when increasing to operating temperatures. • Heating rates after drying on the initial heat up should not exceed 100°F/hr.

FIG. 2 Select 165 at www.HydrocarbonProcessing.com/RS

Installing a veneering module.

PROCESS/PLANT OPTIMIZATION

SPECIALREPORT

within the scheduled 15-day shutdown. The ethylene facility improved energy efficiency with a total savings 0.3%. The insulation effectiveness was achievable by using monolithic shape veneering modules of the highest density (greater than 12 lb/ft3). The ceramic-fiber veneering module system is not a new invention or technology product. However, this insulation upgrade system has not been fully embraced by the petrochemical industry. FIG. 3 Thermal imaging of the revamped furnace with new ceramic insulation. Fears over low reliability undermine the merit and energy efficiency for ceramicfiber veneering systems. Results. After three months of operation, an inspection and As shown in this case history with a time-constrained turnperformance check of ceramic-fiber veneering modules was conaround, the proper application of veneering will decrease heat ducted. An infrared camera was used to check the fired- heater casloss, improve reliability and save installation time. The veneering ing temperature, as shown in Fig. 3. Table 2 summarizes the casing module system could be a good alternative. HP temperatures of the heaters before and after the turnaround. BIBLIOGRAPHY “After” refers to the post-installation of the veneering modules Reed, R. D., Furnace Operations, refer to Table 3–2. within three months after start-up. As evident from the infrared camera inspection report (Fig. 3), the heater casing temperatures significantly dropped from 88°C to Hyunjin Yoon is the team leader of stationary equipment 75°C. This temperature reduction translates into a major energy engineering with SK Innovation at its Ulsan Complex in South cost saving of $143,445/yr, as summarized in Table 3. This repreKorea. He has over 25 years of petrochemical industry experience. Mr. Yoon has a wide range of experience in fired-heater design, sents a 0.3% reduction of total energy input to the fired heaters. Overview. All of the veneering work for the three ethylene

furnaces was successfully done without any quality problems

troubleshooting and maintenance works. He is credited with major roles and involvement in the development of various maintenance procedures of stationary equipment. Mr. Yoon graduated with an MS degree in material science and engineering from Stanford University.

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Recover valuable olefins from offgas streams Catalytic technology aids in removal of acetylenes, NOx and oxygen S. BLANKENSHIP, R. RAJESH, M. SUN, M. URBANCIC and R. ZOLDAK, SĂźd-Chemie Inc., Louisville, Kentucky

o effectively separate valuable hydrocarbons from fluid catalytic cracking (FCC) and deep catalytic cracking (DCC) offgas streams, much depends on the catalytic design concept applied for selective hydrogenation. In the past, FCC and DCC offgas streams typically have been used only for fuel. However, these streams contain hydrocarbons and other materials that have considerable additional value, such as hydrogen, ethylene and propylene, in significant concentration ranges of 5â&#x20AC;&#x201C;20 vol%. Until relatively recently, it has been economically prohibitive to recover these components because the offgas streams usually also contain a wide range of problematic impurities, such as heavy metals and sulfur, that can poison downstream catalysts. Other impurities, such as oxygen and NOx, are also present and pose safety hazards in downstream processes if not removed or converted to less hazardous substances. Furthermore, these streams also contain acetylene and methyl acetylene, as well as diolefins, such as propadiene and butadiene. Such highly unsaturated compounds pose difficulties in treatment systems due to their high coking potential. Due to these and other factors, the cost of recovering valuable products from offgas streams using conventional purification technologies has more than offset the commercial benefit. As a consequence, these streams have been used as fuel. However, as outlined in several case studies discussed in this article, existing, new and advanced selective hydrogenation catalyst technologies have been appropriately applied over the last several years to overcome these difficulties and successfully monetize these offgas streams.

Process objectives. The primary goal is to recover valuable olefins from the offgas stream so they can be sold or used to make other products. However, these streams have other contaminants in them, such as heavy metals and sulfur, that cannot be sent to downstream process equipment or tolerated in the finished products. Therefore, it is necessary to remove these contaminants when treating the offgas. Also present are other hydrocarbons, such as dienes (e.g., methyl acetylene, propadiene and butadiene), that will cause polymer formation in downstream reactors and also contaminate olefin products. Selective hydrogenation of these compounds is desirable to the extent that it is possible. Applications and process overview. Typical FCC offgas generation

and recovery schemes are outlined in Figs. 1 and 2. As shown in Fig. 1, the various streams from the FCC unit are separated

downstream, while the offgas is sent for separate purification in a selective hydrogenation unit, followed by recovery of the olefins and hydrogen. The catalyst used for the removal of acetylene and the partial removal of methyl acetylene, propadiene and butadiene is a uniquely sulfided nickel catalyst that has a long history of use in early front-end ethylene purification systems. In this appliTABLE 1. Test feeds containing MAPD and BD Components CO, ppmv Ethylene, mol%

Test Feed A

Test Feed B

10,000

5,300

Propylene, mol%

Acetylene, ppmv

174

1,000

MA, ppmv

115

350

PD, ppmv

100

250

1,500

8,500

1,3-BD, ppmv

FCC offgas Additional LPG Propylene

C3 splitter Naphtha FCCU

LCO

Amine Caustic wash wash Propane

HCO Bottoms Main fractionator FIG. 1

Absorber stripper

FCC gasoline C4s to alkylation unit or MTBE

Debutanizer

LPG splitter

Typical FCCU product recovery scheme showing source of offgas.

HYDROCARBON PROCESSING JUNE 2012

I 55

SPECIALREPORT

PROCESS/PLANT OPTIMIZATION

cation, it can also convert NOx and O2. Furthermore, due to the excellent poison resistance of nickel, the catalyst also has the ability to remove arsine from the gas stream without significant activity loss. After purification, the gas is sent further downstream for fractionation into ethylene, propylene, LPG, and other products. Since this sulfided nickel-series

catalyst can convert acetylene to specification levels, no additional catalysts normally are required. Sulfided nickel catalyst series.

This series of catalysts is well known and applied in the treatment of FCC offgas streams. Starting in the 1950s, this catalyst was used in C2 front-end selective hydro-

TABLE 2. Comparative test results of Catalyst A and Catalyst B With Feed A

OleMax 101

OleMax 104

Pressure, MPa

0.97

Inlet: H2, mol%

Inlet: H2S, ppm

Average bed temperature, °C

202

215

203

214

Reactor outlet C2H2, ppm Conv., %: MA PD BD C2H4 loss (C2H4 basis), %

0.4 89 44 39 0

0.06 96 61 55 0.07

0.04 99 73 67 0.17

0.02 99 83 76 0.25

Acid gas removal

FCC offgas

Hydrogen Fuel gas

Hydrogenation catalyst

Ethylene

genation applications for the conversion of acetylene, methyl acetylene, propadiene, and butadiene. This catalyst series is now being used to perform the same function, but with a different type of stream. The catalyst has the ability to convert O2 and NOx to reduce the potential of hazardous unstable chemicals being formed in the cold box. The dienes are converted selectively to their respective olefins, which can be recovered in a fractionation portion of the process. Since the catalyst is sulfided and reduced prior to operation, and it requires sulfur for selectivity, the presence of sulfur does not impact its performance when kept within certain limits. Furthermore, the catalyst’s unique properties give it the ability to adsorb heavy metals, such as arsine, and still selectively hydrogenate dienes. Table 1 lists two different feed compositions; the main differences are higher levels of CO in Feed A and higher levels of dienes in Feed B. For Feed A, the results at acetylene cleanup showed that one version of the sulfided nickel catalyst (Catalyst A, 2% nickel) had better selectivity than another with a higher nickel content (CatTABLE 3. Test result of Catalyst A with Feed B

Offgas puriﬁcation reactor

C3 splitter Cold box

Dryer

Temp., °C

204

231

230

Pressure, MPa

0.97

0.02

–0.24

–0.28

H2, % Inlet H2S, ppm

Ethane

Ethylene loss, % LPG Demethanizer Deethanizer

FIG. 2

Process flow scheme showing enhanced recovery of olefins and hydrogen.

C2H2

100

99.7

100

93.8

90.3

PD conv., %

87.8

53.4

46.9

BD conv., %

82.4

42.8

37.5

OM104 with Feed B OM101 with Feed B

0.8

OM101 with Feed A OM104 with Feed A

0.6

Ethylene loss, %

C2H2, MA, PD conversion,%

50 40 30

0.4 0.2

Feed A

0.0

Test resuls with Feed B Test results for Feed A

Feed B

-0.2 -0.4

FIG. 3

100

MA conv., %

1.0

100

Acetylene conv., %

40 50 60 BD conversion,%

Correlation between C2H2, MA, PD conversion and BD conversion.

I JUNE 2012 HydrocarbonProcessing.com

100

0 FIG. 4

40 60 BD conversion, %

100

Correlation between ethylene loss and BD conversion.

PROCESS/PLANT OPTIMIZATION alyst B, 3.2% nickel). However, the latter (3.2% nickel) had better diene conversion than Catalyst A, as shown in Table 2. Tests were also performed with Feed B focusing on the sensitivity of the catalyst performance to various levels of sulfur (Table 3). At acetylene cleanup across Catalyst A (2% nickel), selectivity improved but dienes conversion decreased with higher levels of sulfur. The graphs shown in Figs. 3 and 4 indicate the relationship between butadiene conversion vs. acetylene, methyl acetylene and propadiene conversions (Fig 3), and ethylene loss (Fig. 4). At a given butadiene conversion, the acetylene, methyl acetylene and propadiene conversions are relatively fixed, regardless of feed composition. However, Fig. 4 shows that the ethylene loss depends on the feed composition. The higher the level of dienes, the more selectively the catalyst behaves at a given butadiene conversion.

TABLE 4. Parametric studies done for precious metal Catalyst D Typical feed composition CO, %

Test conditions

0.5–2.0

NO, ppm

1.4

P, MPa

O2,%

0.3

GHSV,h–1

1,500–3,500

H2,%

5–15

Temp.,°C

190–250

H2S, ppm

0–20

C3H6, %

C2H2, ppm

650

PD, % MA, % BD, %

0.03 0.05 0.2–0.5

TABLE 5. Testing conditions of precious metal Catalyst D in high-CO feed Typical feed composition CO, % NO, ppm

Test conditions 4

60–100 ppbv

P, MPa

1.9

O2,%

0.29

GHSV, h-1

H2,%

9–10

Temp.,°C

190–250

C2H4, %

H2S, ppm

0–20

C3H6, %

C2H2, ppm

700

C2H6, C3H8

Trace

PD, %

0.03

streams contain large amounts of CO. The presence of CO has little effect on the performance of the nickel catalysts, but there is concern about the formation of nickel carbonyl. Nickel carbonyl is a highly toxic substance formed by the reaction of CO with reduced nickel at low temperature and under high pressure. Various forms of nickel sulfide can also form nickel carbonyl, but the equilibrium constants are 5–7 orders of magnitude lower than those for reduced nickel. However, the need to develop a catalyst for offgas feeds containing high levels of CO was identified. It would also be beneficial if the catalyst did not require sulfiding prior to operation or sulfur injection during operation.

MA, %

0.06

BD, %

0.2

developed precious metal catalyst, called Catalyst D, hydrogenates acetylene and dienes selectively, along with O 2 and NO x. The test conditions for the parametric studies are shown in Table 4. The presence of CO enhances the catalyst’s selectivity. Precious metal Catalyst D can tolerate small amounts of sulfur and maintain its performance, but it does not require any sulfur addition to maintain its selectivity. Further testing at a higher CO concentration (Table 5) revealed an increase in the selectivity of Catalyst D at high levels of CO, although the catalyst was still able to maintain conversion of oxygen, NOx and acetylene at moderate temperatures (Table 6).

1.4

C2H4, %

Nickel carbonyl. Some FCC offgas

Precious metal catalyst. A newly

SPECIALREPORT

Summary. Two types of catalysts can

be effectively used for the purification of FCC-type offgas streams. The sulfided nickel catalyst is commercially proven at normal CO concentrations, whereas a precious metal catalyst is developed for high-CO concentrations. For streams that have little or no sulfur and contain a few percent of CO, precious metal Catalyst D is the best choice. Selecting a catalytic design that consists of a traditional sulfide nickel catalyst or a precious metal-based catalyst, according to feed composition, allows for the removal of impurities from the offgas stream, thus adding extra value to cracking operations. HP Steve Blankenship is a senior research chemist at Süd-Chemie Inc. in Louisville, Kentucky. He has 31 years of experience in catalyst testing and development. He holds a BS degree in chemistry from the University of Kentucky.

Raj Rajesh has worked at Süd-Chemie since 1991, when he joined the company’s US office as an R&D engineer. During his career, he has held a number of positions in R&D, engineering services, sales, and business management. Mr. Rajesh holds BS and MS degrees in chemical engineering, as well as an MBA.

Mingyong Sun is the R&D group leader for selective hydrogenation catalysts with Süd-Chemie Inc. He has over 20 years of experience in catalyst preparation, testing and development. Dr. Sun earned a BS degree

2,500

TABLE 6. Results from the high-CO study of precious metal Catalyst D Temp., °C

176

188

201

NOx , ppbv

< 10

1.2

< 0.5

Ethylene loss, %

0.48

0.65

1.09

C2H2 out, ppmv

MA conv., %

60.7

97.6

100

PD conv., %

39.9

39.5

48.7

BD conv., %

20.8

24.2

23.6

O2, ppmv

in chemistry from Nankai University in China and a PhD in technical chemistry from ETH Zürich in Switzerland.

Mike Urbancic is the R&D manager for petrochemical catalysts at Süd-Chemie Inc., and he has over 30 years of experience in catalyst testing and development. During his 22-year career at Süd-Chemie, he has held a variety of positions in both R&D and technical services. Dr. Urbancic earned a BS degree in chemistry (with honors) from Purdue University and a PhD in inorganic chemistry from the University of Illinois. Richard Zoldak is a senior technical service engineer for Süd-Chemie, where he has worked for the past 20 years. He has been in the chemical processing industry for 35 years, in a variety of roles including manufacturing, sales, marketing, product development, and technical service. He has previously published articles on catalyst technology and heat exchangers. Mr. Zoldak holds BSc and MSc degrees in chemical engineering from Fenn College of Engineering at Cleveland State University, and a master’s degree in business administration from State University of New York in Buffalo. He is a licensed professional engineer in the state of New York. HYDROCARBON PROCESSING JUNE 2012

I 57

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Select 68 at www.HydrocarbonProcessing.com/RS

PROCESS/PLANT OPTIMIZATION

SPECIALREPORT

Optimize training using a high-fidelity simulator Here are lessons learned from a Russian methanol plant D. KOTSUBA and M. GAREYSHIN, JSC Metafrax, Gubakha, Russia; D. STAVRAKAS, T. PALLIS and V. HARISMIADIS, Hyperion Systems Engineering, Athens, Greece

simulator to a methanol plant in Russia. First, a short description odern plants are heat-integrated and increasingly autoof the methanol plant will be provided, followed by some modelmated. This fact diminishes the operator’s ability to ing highlights and the architecture of the delivered system. After intervene in a quick and effective manner should an that, a focus on operator training methodology, with insights on incident occur. Under normal working conditions, the operamalfunctions and training scenarios, is offered. Wrapping up the tor can apply basic knowledge successfully. At the first sign of a observation of the methanol plant will be a list of benefits profault condition, the operator acknowledges the event in a clearly vided by the simulator, along with plans for the future. defined manner. As the abnormal situation continues, interdependent events propagate and a multitude of alarms go off. This causes the human response to deteriorate, forcing decisions to be Simulator scope. A simplified process and flow diagram made based on experience and best judgment.1,2 for methanol production at the JSC Metafrax site in Gubakha, How can this challenge be addressed? A solution incorporating Russia, is presented in Fig. 1. Natural gas is heated in a fired automated procedures and operating disciplines is required. The heater and fed to the sulfur removal section. Process steam is best operational knowledge needs to become part of the plant’s added and the mixture is preheated using flue gas and sent to the operating procedures. Further, it should include the most appropritube-furnace for reforming. The high-temperature reformed gas ate response to abnormal events, and it needs to be applied to all is cooled down by generating steam and by heating up the boiler modes of operation, from normal running to startup and shutdown. feed water, the demineralized water and the methanol distillaUsing a dynamic process simulator can support the need for developing plant Reforming operator skills while maintaining process Sulfur understanding and engineering analysis. removal MP steam Natural gas Modern simulators are detailed, highCompression HP steam fidelity, real-time simulation systems custom-built to match the dynamic behavior of single or multiple plant units and their associated control systems. These powAir Fire heater erful systems are utilized for a variety of purposes, including DCS checkout for Condensate grassroots plants, operator training, engiBTW Synthesis Demin. neering studies for operational improvewater 3 ments and debottlenecking projects. An operator training simulation system Purge to fuel Product CW typically consists of: methanol • A number of process models describDistillation ing the plant behavior as a function of time Fuel oil • A complete copy of the distributed control and the emergency shutdown system, including a series of operator consoles • The instructor/engineer station, used CW to control the simulator and the training Crude Reﬁning column bottoms methanol sessions, as hardware and software must communicate seamlessly. FIG. 1 Typical flow diagram of a methanol unit. A variety of useful lessons can be derived from the delivery of an operator training HYDROCARBON PROCESSING JUNE 2012

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SPECIALREPORT

PROCESS/PLANT OPTIMIZATION

tion/purification columns. The furnace heat is further used for producing high-pressure steam and for heating the air used in the burners. The high-pressure steam drives the turbines of the synthesis gas and circulation compressors. The cooled down reformed gas (synthesis gas) is compressed and sent to the methanol synthesis loop. This consists of one isothermal reactor and two adiabatic bed-type reactors with cold-gas bypasses. After heat recovery and cooling, the crude methanol is separated from the circulation gas. Due to high contents of inerts (hydrogen) in the gas, a part of it is used as fuel for the methane reformers. The crude methanol produced is refined in two distillation columns. The first column is used to remove the volatile compounds, while the second column removes water and fusel oil (higher order alcohols) and provides the final product for storage.

• Reformers were modeled by using a combination of standard simulation blocks (fired heater, pipes and heat exchangers) in order to represent the reaction side of the system and the heat transfer from the furnace radiant section • The synthesis compressor and converted gas compressor were modeled • All control loops used the tuning parameters of the actual DCS. The local controllers were tuned, so that the reaction to disturbances is quick but stable. • The emergency shutdown system (ESD) was also included to the simulator, using a series of simple logic blocks. • Simulation of Woodward and Sulzer sequence turbine controllers was incorporated for the control and startup/shutdown of the compressors/turbines. Anti-surge control was also incorporated into the model. Thus, the operator could be trained in following the exact compressor startup procedure.

Modeling highlights. A commercial off-the-shelf dynamic process simulator software package was used to model all plant equipment in high fidelity. A typical screenshot for a model flow sheet is given in Fig. 2. The model structure matches the P&ID layout. Further, the valve status and current stream conditions (information on flows, temperatures and pressures) are displayed. Process modeling included the following: • The methanol synthesis process has been modeled in detail. The following equilibrium reactions were incorporated into the model: (1) o CO + 2H2 , CH3OH o CO2 + 3H2 , CH3OH + H2O (2) o 4CH3OH , C4H9OH + 3H2O (3) o 2CH3OH , C2H5OH + H2O (4) o 2CH3OH , CH3OCH3 + H2O (5)

System architecture. A typical operator training simulator

FIG. 2

Process model flow sheet in a simulator.

I JUNE 2012 HydrocarbonProcessing.com

is composed of four main elements, as shown in Fig. 3. These are: • Instructor station • Field operator duties (FOD) station • Calculation engines • Operator stations (like DCS consoles). The master simulator environment provides the necessary tools to prepare and seamlessly integrate the aforementioned elements. Instructor station. In this case, it was built in the native simulator system. It contains graphics that are based on those in the DCS and includes the field-operator duties. It provides the necessary graphical interface for the instructor to navigate through the plant, generate equipment malfunctions, create training scenarios and review the performance of the operators. Typically, there is one PC used by the instructor. Fig. 4 shows a typical instructor station graphic. Field operator duties. Field operator duties (FOD) are those actions that cannot be performed from the control room and require physical access to the actual plant. Those actions that have training value and are therefore required in the OTS model have been incorporated in the FOD station. In our case, the FOD station was built in the native simulator system. It contains graphics that are based on those for the instructor. However, they include only the local transmitters rather than any of the DCS versions. These graphics include all the FODs (such as start/stop buttons for the fan motors and the pumps, valve hand-jacks and local switches). Typically, there is a single PC used by all operators to simulate any actions that are to be performed in the field. Fig. 5 shows a typical FOD graphic. Calculation engines. The process model calculations are performed in a series of “engines.” The overall process model is divided over a number of smaller models. These individual models are interconnected by multi-component streams, using physical property information obtained directly from the simulator’s

PROCESS/PLANT OPTIMIZATION physical property and thermodynamic database. Each one of these models is running on a single CPU-core. A number of PCs may be used to run a process model. The DCS engineering station. The station performs all the DCS functions, like controller calculations and alarm management, and allows a control engineer to modify the controls database. It is connected to the operator stations as in the real plant. The connection between the simulator master environment and the DCS engineering station is through a special link designed to allow it to function as an integral part of the dynamic simulation system. Cross-reference tables. These tables are used in the simulator to link process mode variables and instructor functions with the DCS and ESD input and output points. In this particular project, there was one instructor station PC, one FOD station PC and two simulator workstations. The model calculation load is shared across all available multi-core PCs. This was done in order to ensure that the simulator system can achieve at least two times real time (in other words, simulate the plant phenomena in half the time that would be needed in reality) in all operating conditions. The aforementioned workstations were connected to an Emerson DeltaV DCS system consisting of six dual-screen operator stations, one engineering station and one server. The architecture of the delivered system can be seen in Fig. 6.

SPECIALREPORT

Malfunction scenarios. A malfunction can be defined

as an unexpected, abnormal occurrence. The introduction of malfunctions is one of the most important aspects of simulatorbased training. They are used by the instructor to test a traineeoperator’s ability to analyze and correctly respond to similar challenges in the physical plant. Table 1 shows typical standard malfunctions that are available in most commercial off-the-shelf simulation software. Custom malfunctions. We can define “custom” malfunctions as those that the simulator vendor has to configure especially for a specific simulator (examples include heat exchanger tube rupture and catalyst poisoning). A custom malfunction can be introduced by the instructor or be the result of the operator’s actions. These are special equipment malfunctions that the simulator vendor has to configure especially for the delivered simulator. In the delivered simulator, there is a graphic in the instructor station that contains a summary of the custom malfunctions. This graphic can display which malfunctions are active and which are not. Further, it contains reset buttons for the malfunctions. Part of this page can be seen in Fig. 7. The main malfunction page has navigation buttons that lead to pages with detailed schematics showing the result of the activated malfunction. Fig. 8 shows part of an instructor station graphic in which a heat exchanger is in normal operation (left side) and the tube rupture malfunction has been activated (right side).

TABLE 1. Common malfunctions by equipment type Equipment type

Malfunction

Valve

Fail to position

Simulation master environment

Positioner bias Valve blockage Valve leakage Broken valve stem Transmitter

Fail to value

Instructor station

FOD station

Four calculation 1 DCS engineering stations station

Fail in place Bias PV by a value Noise Relief valve

Six operator stations (DCS consoles)

Relief valve leakage Fail to open Fail to reset

Electrical motor

FIG. 3

Base simulator architecture.

Trip

TABLE 2. A compilation of milestones reached during the implementation

LV-7701

Milestone Kickoff meeting

54.0%

1253

Detailed functional specification (DFS)

Build the dynamic process model Stage simulation hardware (four workstations)

P17701 2.572 kg/cm2

Model validation test (MVT) in Athens, Greece Stage DCS hardware and software in Moscow, Russia

3253/1

P17702 0.355 kg/cm2

3253/2

Load plant DCS database System integration (Simulator and DCS) Factory acceptance test in Moscow

FIG. 4

Typical instructor station graphic.

Site acceptance test in Gubakha, Russia HYDROCARBON PROCESSING JUNE 2012

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SPECIALREPORT

PROCESS/PLANT OPTIMIZATION

Running switch

HZA5101 70 88 %

On/off switch 4343/1-1 Off On

4343/1-3

Off On

4343/1-11 Off On

4343/1-9 4343/1-10 Off On

Off On

4343/1-17 4343/1-18 Off On

FIG. 5

4343/1-8

Off On

4343/1-12

4343/1-13

4343/1-14

Off On

4343/1-20

4343/1-21

4343/1-22

Off On

Operator station 2

4343/1-15 4343/1-16 Off On

Operator station 3

Operator station 4

Operator station 5

Simulator PC 1

Simulator PC 2

Delivered simulator system architecture.

1537 Exchange tube rupture Reset

1656 Tube depressurization on radiant zone Reset

Inactive

1401/1/2 Rupture of the reaction tubes Reset Reset

1401/1/2 Liquid (methanol) coming to the auxiliary burners of the furnace

Inactive

Part of the main malfunction page.

I JUNE 2012 HydrocarbonProcessing.com

Active

Off On

4343/1-23 4343/1-24 Off On

Operator station 6

Engineering station

Instructor station

4343/1-7

Typical FOD graphic, depicting the on/off switches and the stop buttons for a multi-motor air cooler.

ProPlus/ PPN server

FIG. 7

Stop buttons

4343/1-6

4343/1-19

Off On

Operator station 1

FIG. 6

1643/1 4343/1-4 4343/1-5

4343/1-2

FOD station

Off On

Training scenarios. Scenarios enable the plant instructors to record and replay predefined sequences of events. Such events may be simple (the closing of a valve or the tripping of a pump), or quite complex (a normal plant shutdown). Scenarios contribute to operator training on emergency situations and the following of plant operation procedures. This is because the operators get hands-on experience troubleshooting rare and complex situations and the instructors can closely track the operators’ activities. Trainee evaluation. The trainee operator evaluation is based on the operator’s ability to maintain the plant at its nominal steady state. This steady state is characterized by a series of variables, their accepted operational limits and their relevant importance. When a malfunction is triggered, the operator is expected to: • Recognize that the area of the plant for which he is responsible is not operating at the usual state • Understand what is not functioning correctly • Mitigate any adverse effects. The sequence of the operator’s actions during normal operations or plant startup/shutdown is monitored carefully by instructors and used as a method for the operator’s training assessment. The instructors use the simulator to track specified variables. For each tracked variable, the system will report the time that the variable in question is above or below the acceptable limits. The smaller the areas above/below these limits, the higher the skills of the operator are rated. In these cases, weighted average of the above will provide the “score” for each operator. This is shown schematically in Fig. 9.

Project milestones. The main project milestones are outlined in Table 2. Here are some useful guidelines to incorporate along the path of simulator integration: • During model acceptance tests, local model stability tests, training scenarios, detailed custom malfunction reviews and plant shutdown and startup simulations should be performed • The earlier that any modeling challenges are identified the better, so that the simulator vendor will have enough time to review modeling without impacting the delivery schedule • The factory acceptance test for the training simulator should be performed as a dry run of the actual plant startup, using actual startup procedures and manuals • A commitment to this approach should be obtained from all involved parties including proponent, turnkey contractor and simulator vendor

PROCESS/PLANT OPTIMIZATION

TI 1030 -3.133 °C

PI 1022 3.30 kg/cm2

PI 1021 3.30 kg/cm2

SPECIALREPORT

TI 1030 -3.133 °C

PI 1020 3.30 kg/cm2

PI 1022 3.30 kg/cm2

AAH1003

AAH1003 Damage 1537

1537 AAH1002

FIG. 8

PI 1020 3.30 kg/cm2

PI 1021 3.30 kg/cm2

82.2% TV1033

AAH1002

82.2% TV1033

A schematic for a heat exchanger in normal operation (left) vs. when the tube rupture malfunction has been activated (right).

• A simulator is a multipurpose tool that should be used for early identification of any DCS modifications or design changes required, that would normally be uncovered during commissioning. simulator have been the following:4, 5 • Facilitating the operator training o Familiarization with the normal operation of the unit o The simulator provided a series of custom malfunctions and training scenarios o Continuous personnel training and operator certification o Familiarization with procedures o Training of students with job-specific education to create hands-on experienced specialists • OTS can be used as a platform for process-oriented experiments by setting different parameters o Optimum plant performance o Validation of new control strategies o Engineering and debottlenecking studies • This personnel training assists methanol plant operator Metafrax in fulfilling all the requirements of the Federal Service on Ecological, Technological and Nuclear Supervision. After model troubleshooting and delivery of the simulator system, experienced operators commented favorably on the similarity between the dynamic response of the simulator and existing plants using the same technology. The simulator is providing significant benefit to the real plant, resulting in: • A faster and smoother startup • Increased process understanding both for engineers and operators • Safer and more efficient operation under transient and abnormal conditions • Significant economic benefits via reduction of emergency shutdown possibilities (for instance, one day of downtime could reduce Metafrax’s revenue by more than €300,000) • Longer plant runs and prolonged catalyst life due to avoidance of extreme conditions. One year after the simulator delivery, some control logic equipment and instruments were modified or replaced. The simulator was updated to reflect the new reality in the plant. Thus, it will continue to offer: • Valuable insight to engineers for verification of plant design updates, controllability and debottlenecking studies • Continuous training and certification to plant operators • Increased value for the shareholders for years to come. HP

High area

80 Level, %

Benefits. The main benefits from this plant operator training

Operator evaluation chart

100

Time above high limit is 8 seconds High limit

60 40

Low limit

Low area

0 0 FIG. 9

15 Time, sec

Time below low limit is 1 second 20

An operator evaluation methodology using the system variables’ deviations.

LITERATURE CITED Resnik, C., “Better operator ergonomics increase plant KPIs,” Automation World, December 2009. 2 Pankoff, J. A. Sr., “Training today’s process plant operator,” Hydrocarbon Processing, August 1999. 3 Harismiadis, V. I., “Dynamic process simulation: Integration, quality assurance and operator training,” 3rd Pan-Hellenic Chemical Engineering Conference, May 31–June 2, 2001. 4 Gareyshin, M., “High-fidelity OTS at Metafrax,” 1st Hyperion Russia Technology Meeting, June 3–4, 2010. 5 Gareyshin, M., Kotsuba, D., Pallis, T., Stavrakas, D. and V. Harismiadis. “Effective use of operator training simulation in methanol,” Automation in Industry. No 7/2011, 2011. 1

Dmitriy Kotsuba graduated from the Polytechnic Institute. He is trained as a chemical process engineer. He has worked at Metafrax’s methanol production plant for 25 years, the last 10 of them as chief specialist on automated control systems.

Malik Gareyshin graduated from the Polytechnic Institute and is trained as a mechanical engineer. He worked at Metafrax for 30 years, the last eight as head of the IT department. Mr. Gareyshin now runs Management Automation. Dionysios Stavrakas is a senior engineer at Hyperion Systems Engineering. He has five years of experience delivering high-fidelity engineering studies and developing operator training simulators. He holds a MSc degree from NTU Athens in chemical engineering and energy production and management. Theocharis Pallis is a senior process simulation engineer at Hyperion Systems Engineering. He has 11 years of experience in dynamic modeling and operator training simulators. Mr. Pallis holds a MSc degree in chemical engineering from the University of Patras, Greece. Vassilis Harismiadis is the real-time optimization and training simulation manager at Hyperion Systems Engineering. He has 12 years of experience in the oil and gas industry with particular emphasis on using dynamic process modeling to improve plant effectiveness. Mr. Harismiadis holds a PhD from NTU Athens in the thermodynamic modeling of complex systems. HYDROCARBON PROCESSING JUNE 2012

I 63

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PROCESS/PLANT OPTIMIZATION

SPECIALREPORT

Improve feedstock selection for your refinery A simplistic approach facilitates screening of crude oil baskets R. KUMAR, P. PARIHAR and R. K. VOOLAPALLI, Bharat Petroleum Corp. Ltd., Greater Noida, Uttar Pradesh, India

Crude oil processing—Worldwide trends. At present, the refining industry is processing opportunity crude oils, as benchmark crude prices surpassed $100/bbl. These crude oils are available at cheaper prices due to inferior qualities.1 Also, fuel specifications have become more stringent with stricter environmental regulations. Result: Producing cleaner fuels is more difficult. Processing poorer quality crude oils to yield higher-quality products may add exorbitant costs through hydroprocessing.2 In this scenario, processing opportunity crude oils and meeting tighter product specifications is the real challenge while achieving higher refinery margins. We must ask the question: “Is processing opportunity crude oils always a profitable option for refiners throughout the world?” It can be “yes,” if a refiner is a lower-cost producer. However, there are many uncontrollable factors, such as crude oil prices, economic conditions and environmental regulations for fuel specifications; all affect refinery economics and profitability. Benefiting from the least expensive crude oils in the market, such as high-acid crudes (HACs), heavy-sour crudes and extra-heavy oil produced from oil sands, refiners can keep margins high and stay ahead of the competition.3 The answer can be “no.” Not every refiner can handle crude oils with a high corrosion propensity and a disproportionate amount of heavy residues. Crude cost is the single most important determining factor for profitability. The differential between a

particular crude oil and benchmark crude oil can be great (more than 20%) and it widens as market oil prices rise. Strategy. Several methods have been used to relate these differentials to the qualities of crude oils.4,5 For refineries that have more freedom in crude oil choices, selecting the optimum crude oils is vital. These crude oils are available at discounted prices with compromised qualities such as API, sulfur (S), total acid number (TAN) and many other impurities.6 Assessing the refining processes for such crude oils is crucial, as the differential margin offered by opportunity crude oils could justify modifications or expansions to facilitate efficient processing of such feedstocks.7, 8 These crude oils produce inferior quality product streams including diesel, vacuum gasoils (VGO) and more residues that require additional processing and/or evacuation at lower cost. In hydroprocessing, such streams consume large quantities of hydrogen; there is an exorbitant additional cost due to high hydrogen prices. The cost of crude oil has the larger influence on refining business; it involves 80%–90% of the total product cost. Cheaper crude oils, however, require additional processing to meet critical product specifications of Euro III, IV and V grades. More capital and operating costs, likewise, squeeze profits. Opportunity crude oils not only influence the processing cost due to hydrogen deficiencies, but they also produce more byproducts and residuals that must be upgraded or blended off with cutter stocks such as kerosine/diesel or as lower50

40 °API

il price variations impact the selection process for refinery crude slates. When considering crude and product prices, product demand, refinery configurations and other constraints, the evaluation process can be exhaustive. Software tools are comprehensive and time-consuming to screen and rank crude oils on a regular basis. To simplify this process, a quick methodology was developed to screen a crude oil basket. The differential in crude oil price and processing costs are the most influential factors that determine crude selection. Typically, the differential in crude oil prices is in relation to the benchmark crudes like Brent price and the quality. The differential in processing cost is primarily associated with hydroprocessing and residue evacuation at lower prices. The sensitivity analysis should include crude, hydrogen and residue prices. The crude selection model presented in this study is an Excelbased tool; it requires minimum data input to determine crude oil potential and rankings. With this method, refiners, crude-oil traders, supply-chain optimizers and crude schedulers can make quick and accurate business decisions.

20 0

Sulfur, wt%

FIG. 1

Typical classification of crude oils by sulfur content and API. HYDROCARBON PROCESSING JUNE 2012

I 65

SPECIALREPORT

PROCESS/PLANT OPTIMIZATION

cost fuel oils (FOs). Accordingly, refiners have the flexibility to re-evaluate options when processing opportunity crude oils for profitability.2 The presented study discusses how to investigate more accurately discounted, poorer-quality crude oils against processing costs and profitability. This study is supportive for quick decisions on selecting crude oils and ranking them on a regular basis. Detailed crude evaluation and selection. The classical evaluation method to identify the potential of crude oils is done through laboratory experiments and analyses, which are lengthy processes. Typically, crude oils are classified in nine different categories by qualitiesâ&#x20AC;&#x201D;API (light/medium/high) and sulfur (sweet/medium/ sour), as shown in Fig. 1. This is an indication of preliminary qualities for the crude oils; it can be used to judge the characteristics and performance of the crude oil and the processing measures needed. On the basis of these two qualities, a discount is offered. It is one of the factors considered during crude oil trading.9 However, it is not completely accurate for refining business decisions. Thus, a detailed crude oil evaluation is done at the laboratory to obtain more important information, which is very useful for refinery operations and processing of the crude oils. The detailed crude oil evaluation provides the valuable database to counter the processing difficulties and assist in planning the processing of the opportunity crude. To achieve optimal crude oil selection and processing decisions, the refiner always needs detailed evaluations that refer to 0.8700 0.1 wt% of feed 0.25 wt% of feed 0.5 wt% of feed 0.75 wt% of feed 1 wt% of feed

0.8650 Density, gm/cc

0.8600 0.8550 0.8500 0.8450 0.8400 0.8350 0.8300 0.0 FIG. 2

20 18 16 14 12 10 8 6 4 2 0

0.5

1.0

1.5 Sulfur, wt%

2.0

2.5

3.0

Hydrogen consumption as wt% of feed to the hydrotreater and as a function of DHDS feed properties.

Increasing VR

Seria export light Labuan Mirri Light Champion Palanca Tapis Bonny Light Brass River Saharan blend Forcados Qua lboe Mumbai High Esravos ZUIETINA Murban Brega Brent Blend Sarir Azeri light Nemba Antan Masila

RPC, $/bbl

RPC calculated RPC predicted

FIG. 3

Refinery processing costs for LS crudes (S < 1 wt%).

I JUNE 2012 HydrocarbonProcessing.com

the quality of the crude oil. This includes true boiling point (TBP) distillation yield profile data for the atmospheric and vacuum distillation units to meet product demand and refinery capacity utilization. The detailed crude oil evaluation also covers the characterization of the crude oil and cut-wise analyses for all important fractions including liquefied petroleum gas (LPG) potential, naphtha, kerosine, diesel, vacuum gasoils (VGOs), atmospheric residue (AR) and vacuum residue (VR). Standards. This detailed information is obtained through

standard laboratory test methods, normally API and/or ASTM.10 This extensive laboratory analysis of the crude oil is a costly and a time-consuming process. Such analysis is expensive, and, generally, it takes four to six weeks to complete. However, the detailed information is typically unavailable during the selection of crude oils. It does not consider the processing costs involved, which are very important parameters for decision making. Even during actual refining operations where multiple feeds and blends are processed, the refining process decisions are not accurate for hydrogen consumption, residue evacuation and intermediate distillate routings for maximum values.11 The detailed crude oil evaluation is vital when considering the process based on crude oil qualities (API, S), detailed crude assay and simulation/linear programming (LP) tools. Laboratory evaluation and historical crude oil data are used in synergy and its compatibility with the refinery configuration.12, 13 Accurate crude oil quality data are essential for precise scheduling and planning inside the refinery. This can be achieved by commercially available rigorous software tools that are comprehensive, time-consuming and complex. Rigorous models are not always suitable when solving complex problems over refinery margins, which are more conceptual and economic than scientific and technical. Rigorous models are not designed for fine-tuning actual refinery operations. They do not use available information; instead, they require tremendous input data that may not always be available during the selection process. It is even difficult to obtain economically relevant results to operate the crude distillation unit.14 Integration of best practices in refinery planning and scheduling, along with crude oil selection based on economics, is essential to make better business decisions.15 Therefore, a quick estimate of relative crude oil potential, accounting for real-life scenarios with minimum inputs becomes a necessity. The procedure is accurate, tunable to the existing reference operation and flexible for any new proposed refinery operation and crude data. More importantly, this evaluation is easily understood by both the trader and refinery economist. To achieve these objectives, a simplistic approach was proposed; it considers Brent crude price variations, the differential of the crude oil price due to its qualities, hydroprocessing cost, resid-evacuation cost, crude and product prices, product demand, refinery configurations and constraints. This is a simple and swift Excel-based tool, and it can be used to determine crude oil potential and their rankings quickly. This tool can be part of a comprehensive simulation software. Crude oil processing can be monitored on a regular basis for benefits. Processing costs. Refinery processing costs (RPCs) mainly

include the hydroprocessing costs for diesel and VGO streams and residue evacuation. In this study, a heavy-sour crude oil processing train with a diesel hydrotreater and VGO hydrocracker as secondary processing units are considered while evaluating crude oils under different scenarios. VR is evacuated as FO by adding distillates as cutter stocks.

PROCESS/PLANT OPTIMIZATION

oil basket for hydrogen savings may not be a feasible economical option. There are many implicit factors involved in crude oil trading such as oil production, scheduling, planning, price fluctuations and availability, etc. The approach to select a crude basket for hydrogen savings would not have meaning unless it is provided several benefits. In this scenario, it is essential to carry out detailed analyses for hydrogen savings and total processing benefit. The contribution of residue evacuation on refinery processing costs should also be considered. Recently, residue is the key focus for 24 22 20 18 16 14 12 10 8 6 4 2 0

Decreasing API

FIG. 4

Arab Heavy

Al-Shaheen

Arab Medium

Suez Mix

Arab mix (60 40)

Dubai

Iran Heavy

Kuwait

Upper Zakum

Arab Light

Basrah Lt.

Iran Light

Arab Ex.Light

UMM Shaif

RPC calculated RPC predicted

Lower Zakum

RPC $/bbl

Diesel and VGO derived from the heavy-sour crude oils are sent to hydroprocessing where sizable hydrogen consumption occurs. Primarily, the poor quality of the diesel and VGO is the main reason for high hydrogen consumption. Hydrogen is used to remove sulfur from the diesel-product streams via the diesel hydrodesulfurization (DHDS) unit, as shown in Fig. 2. When qualities of the diesel (density and sulfur) are poor (high-density and high-sulfur), large quantities of hydrogen are necessary. From Fig. 2, the lines in the nomogram are for constant hydrogen consumption (expressed as wt% of feed) with varying feed quality. This nomogram is also helpful in hydrogen management of DHDS unit vs. diesel qualities. Hydrogen supply and demand. When VGO is sent to the hydrocracker unit (HCU), the characteristics of VGO such as aromatic content, sulfur and other impurities (V, Ni, basic N2, etc.) are the main culprits for maximum hydrogen consumption. The characteristics of VGO are mainly influenced by the vacuum tower operations, endpoints and the crude oils processed.16 These properties also affect the HCU catalyst and run length. In addition, they restrict throughput capacity of the hydroprocessing units as hydrogen capacity is a limiting factor. It is essential to select crude oils and/ or blends that minimize hydrogen consumption. The study would also be helpful in hydrogen management in both DHDS and HCU for feed qualities vs. hydrogen availability within refinery premises. To reduce hydrogen consumption, superior quality of VGO must be sourced, which may be obtained from more expensive crude oils.2 However, it would be a challenging task to meet both the requirements of processing opportunity crude oils and minimizing hydrogen consumption. The random selection of the crude

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Refinery processing costs for HS crudes (S > 1 wt%).

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refinery profitability. Crude oils are traded at high cost, and typically up to a 25 wt% portion is the residue content, which has very low value. Without residue-upgrading facilities, such as delayed coker, solvent de-waxing, visbreaker, etc., the residues are evacuated at the lowest cost.17 It is either used to produce FO/low-sulfur heavy stock (LSHS) where vacuum residues are blended with cutter stock (kerosine/diesel) or bitumen production. However, not all crude oils are suitable for bitumen production. Thus, VR is a burden to refineries, where up to 20 wt%–25 wt% portion of the costly crude oils are diverted to low-cost products. It is very essential to understand residue yields and the evacuation process during the selection process. Modeling approach for crude oil selection. High API and low-sulfur crude oils yield superior quality of diesel and VGOs. These crudes are more suitable for hydrogen savings and they also yield low residual products. From the total optimization perspective, several criteria should be examined closely and major issues include: • Price difference between crude oils • Hydroprocessing costs and hydrogen capacity limits • Residual generation and disposal. 100

RPC, % contribution

80 60 40 20

Hydroprocessing cost SR evalcuation cost Seria export light Labuan Mirri Light Champion Palanca Oman Tapis Bonny Light Brass River Saharan Blend Forcados Qua lboe Mumbai High Esravos ZUIETINA Murban Brega Brent Blend Sarir Azeri Light Nemba Antan Masila

FIG. 5

Contribution of RPC for LS crudes (S < 1 wt%).

100

RPC, % contribution

80 60 40 Hydroprocessing cost SR evalcuation cost

FIG. 6

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Arab Heavy

Arab Medium

Suez Mix

Contribution of RPC for HS crudes (S >1 wt%).

Al-Shaheen

Iran Heavy

Arab mix (60/40)

Dubai

Kuwait

Upper Zakum

Arab Light

Basrah Lt.

Iran Light

UMM shaif

Arab Ex.Light

Lower Zakum

Price. Crude price is mainly a function of Brent crude oil price and its quality is given as:9 Crude price = Brent price [1-m1 (ΔAPI)–m2 (Δ sulfur)] Where m1 and m2 are constants. Hydroprocessing and resid-evacuation costs and unit constraints are given as: RPC = (DieselPC )DHDS + (VGOPC )HCU + VR evacuation Where: (DieselPC )DHDS = Diesel processing cost at DHDS (VGOPC )HCU = VGO processing cost at HCU (VR evacuation)PC = VR evacuation processing cost. The model considers two elements for crude selection: • Differential with Brent crude oil price, D1 • Differential of refinery processing cost with Brent crude processing cost, D2. The net differential of D1 and D2 decides the position of crude oil for their rankings and selection based on net margins. In this modeling approach, the balance of carbon (C), hydrogen (H) and impurities (I) are considered across the system to determine hydrogen consumption via hydroprocessing operations.18–20 Correlation models were developed for crude and refinery processing costs. The RPC consists of the processing cost of hydrogen at the hydrotreater, hydrocracker and evacuation of VR with additional cutter as FO/LSHS. This study was conducted with crude oils, which are processed globally. The additional costs through hydrogen consumptions are observed for diesel and VGO to upgrade product quality and to meet product specifications. Also, an additional cost for evacuation of residues to FO/LSHS and/or bitumen production is included in the model. The cutter requirements for disposal of VRs are categorized as low-sulfur VR (LSVR) and high-sulfur VR (HSVR). The cutter requirement for HSVR and LSVR are assumed to be 50 wt% and 30 wt%, respectively, as per refinery practices. The sensitive analyses were done with regard to hydrogen and FO prices to check the profiles for RPC. Selection of crude oils from the basket and/or selection of new crude oils and/ or blends is possible through the model. In the current case, due to lack of major residue upgrading facilities, the RPC contribution is 5%–15% of the crude oil cost. The differentials of LS and HS crude oils do have a major impact on crude selection. The proposed crude selection model considers theses assumptions: • The cut-points of diesel and VGO are 240°C–360°C and 360°C–565°C, respectively • All components other than C and H are considered as impurities for the calculations • Price of hydrogen is five times the Brent crude price • Price of FO is 50% of Brent crude price. • Cutter requirement for high S (Scrude > 0.5 wt%) VR is 50 wt% • Cutter requirement for low S (Scrude < 0.5 wt%) VR is 30 wt% • Sensitive analyses with variations in hydrogen, FO and Brent price have been considered • The listed inputs can easily be modified into the tool with varying price scenarios. Crude selection model equations: Crude price = Pricebrent [1 + A (APIcrude–APIbrent ) + B (Scrude–Sbrent )]; error < ±3% FO cost ($/kg) = X % of Brent cost ($/kg)

(1)

PROCESS/PLANT OPTIMIZATION

(RPC )Brent = C + D Brent crude price

(3)

(RPC )Crude = (RPC )Brent (1+ E (Crude API – Brent API) – F (Crude S – Brent S ) + G (Crude VR ) – (Brent VR ); error < ±5% (4) D1 = Crude price differential ($/bbl) = (Brent crude price – Crude price)

(5)

D2 = RPC differential ($/bbl) = Refinery processing cost (Brent – Crude) (6) Where: (Crude)cost = Cost of crude oils ($/bbl) RPC ($/bbl) = f (Crude properties, hydroprocessing cost, VR evacuation cost) Results of RPC. The existing crude oil basket was analyzed to estimate the RPC. The crude oils were categorized as LS (S < 1 wt%) and HS (S > 1 wt%). Fig. 3 depicts the RPC for LS crude oils; it was observed that the calculated and model-predicted RPC values are in good agreement. The LS crude oils are arranged by increasing the order of VR yields, which indicates the influence of VR yields content on RPC. Fig. 4 depicts the RPC values for HS crude oils. Again, the calculated and model-predicted RPC values are in good agreement. The HS crudes are arranged in the plot by decreasing API value to study the influence on RPC. Due to varying sulfur content and VR yields, the influence of API was not distinct. Thus, API is not the only factor influencing refinery processing. There are other factors to consider as part of the selection process. The RPC for Seria Ex Light (source: Brunei) and Arab Heavy (source: Saudi Arabia) crude oils are found to be lowest and highest, respectively. This data, however, are not for the final decisions as it must be compared with the crude oil price, which has a major contribution. The RPC includes cost of hydrogen consumed by the diesel hydrotreater and by the VGO in the HCU and VR evacuation. The percentage contribution of hydrogen consumption and VR evacuation on RPC is shown here. The crude oil basket is categorized as LS and HS for this study. Figs. 5 and 6 show the RPC contribution for LS and HS crude oils. The RPC of LS crude oils is lower than HS crude oils of similar API. As LS crude oils yield higher amounts of distillates, thus lowering the quantity of the VR evacuation, it has a low RPC value. The cost of diesel processing is the lowest for all the crude oils. Brega and Saharan blend crude oils have minimum hydroprocessing costs. Among hydroprocessing and VR evacuation, the contribution of VR evacuation is up to 80% for HS crude oils, as shown in Fig. 6. However, the hydroprocessing cost is higher than VR evacuation for some LS crude oils, e.g., Seria Export Light and Labuan, etc., as shown in Fig. 5. It depends on the qualities of the crude oils and residue yields. All of these influencing parameters were incorporated in the model to improve accuracy. In this scenario, the minimum input data of crude oils would be required for quick decisions. The calculated and model-predicted values are in agreement. Thus, the model equations can be used for any unknown crude oils/blends and/or synthetic crude oils to estimate RPCs. This approach would be helpful in optimization of crudes and blends to minimize hydrogen consumption and overall RPCs. The net result is improved margins.

Sensitivity analysis for RPC. Under the present refining environment, naphtha is facing significant competition from natural gas (NG) with regard to hydrogen production. In this scenario, growing NG usage including liquefied NG (LNG) and compressed NG (CNG) may be the cheaper option for hydrogen production. Thus, the variation in hydrogen prices can influence RPC. Varying hydrogen prices, up to ±50%, were studied. The variation in RPC for LS and HS crude oils with varying hydrogen price was analyzed and reported in Fig. 7. The variation in FO price on RPC was also studied for LS and HS crude oils, as shown in Fig. 8. From the results, the effects of hydrogen and FO prices are significant on processing trends (RPC). Processing LS crude oils (premium crude oils) has a lower RPC vs. hydrogen and FO price scenarios. Processing opportunity (poorer quality) crude oils has a high RPC. The variation in differential for RPC of LS and HS crude oils range up to $15/bbl and for FO price variations up to ±50 %. Similarly, the variation in differential of RPC of LS and HS crude oils range up to $7/bbl–$15/bbl for hydrogen price variations up to ±50%. The sensitive analyses of RPCs indicate that processing opportunity crude oils may not be a prudential option unless the differentials of crude oil prices (LS/HS) are large compared with RPC. Conversely, processing LS crude oils may be the better choice when the differential price of LS/HS becomes low at the prevailing prices of crude oils, hydrogen, FO and RPC.

TABLE 1. Crude selection model parameters Parameter Values

2.26E-04 3.97E-02 1.702 0.117 4.18E-06 2.31E-01 6.71E-02

20 15 RPC, $/bbl

(2)

10 5 0 -50

FIG. 7

HS crude LS crude -30

-10 10 30 Change from base hydrogen cost, %

Sensitivity analysis for RPC with regard to hydrogen price.

25 HS crude LS crude

20 RPC, $/bbl

VR evacuation cost ($/bbl) = [VR (kg/bbl) + Cutter (kg/bbl)] [(Crude cost – FO cost) ($/kg)]

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15 10 5 0 -50

-30

-10

Change from base FO cost, % FIG. 8

Sensitivity analysis for RPC with regard to FO price.

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Crude potential with varying Brent prices. The differential in crude oil prices vs. RPC continue to impact crude oil selection. Implicitly, these factors are influenced by crude and product prices, product demand, refinery configurations and constraints, and hydrogen. In the modeling approach, these parameters are included and simplified to facilitate the crude selection process with minimum inputs. In the presented study, processing opportunity crude oils and hydrogen savings is a contradiction. Thus, processing crude oils, such as low API and HS, may not always be beneficial unless the differential costs of LS/HS crude oils are large enough. However, residual upgrading options, which can evacuate the residues at higher price than crude oil prices would be the probable solution for processing HS and low-API crude oils. Thus, a detailed evaluation of the selected crude oils is essential to fully address suitability of the refinery configurations and breakeven points. Conversely, high-API and LS crude oils are more suitable for hydrogen savings and minimizing RPCs. However, these crude oils are available at higher prices. The crude selection model is based on a simplistic approach where the differential in crude oil prices is compared with differential in RPC for net margins. The differential in crude oil prices (D1 ) is f (Brent prices and qualities) and the differential in RPC (D2 ) is f (crude qualities, hydroprocessing cost, VR evacuation cost). Using the model equations, the differential in crude oil prices vs. Brent crude oil prices was studied and reported in Fig. 9. From

Arab Mix (60:40) Brega BH crude Saharan Blend Kuwait

Net differential (D1), $/bbl

14 13 12 11 10 9 8 7 6 5 4 3 2 1 0 -1 -2 40

FIG. 9

80 90 100 110 120 130 140 150 Brent crude $/bbl

Variation in crude differential (D1 ) with Brent crude oil price.

8 Arab Mix (60:40) Brega BH crude Saharan Blend Kuwait Arab extra light

Net differential (D1 + D2), $/bbl

7 6 5 4 3 2 1 0 -1 -2 40 FIG. 10

80 90 100 110 120 130 140 150 Brent crude $/bbl

Variation in crude differential (D1 + D2 ) with Brent crude oil price.

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this figure, the differential in crude oil prices for HS crude oils such as AM and Kuwait, are increasing steadily. Thus, processing poorer quality crude oils can be beneficial at higher Brent crude oil prices. However, the variations in premium-grade LS crude oils are less with Brent crude oil prices. Thus, processing LS crude oils such as BH, Saharan Blend and Brega may be the better option at lower Brent crude oil prices. The differential in D1 and D2 represents the net margins offered by a particular crude. The net margin (D1 + D2 ) was studied with varying Brent crude oil prices and reported in Fig. 10.The crossover between HS (Kuwait) and LS (Saharan) blends occur when Brent crude oil price is $90/bbl. It implies that up to $90/bbl of Brent crude oil price, Saharan Blend crude oil is a better option over Kuwait for net margins. Beyond $90/bbl of Brent crude oil price, Kuwait processing is beneficial. The model is generic to capture various scenarios of prevailing prices for Brent crude oils, crude oil qualities, refinery processing and constraints for selection. The present modeling approach facilitates quick pre-screening of crude oil baskets. This would be a useful tool for crude oil trading, where the ranking of crude oils is possible in a short time. Options. The study of crude oil for the refining business was

reviewed, and many intrinsic details were discussed with traders, scheduler and planning, supply-chain optimization, technologists and refiners to develop a swift tool for the pre-screening of crude oils. The study highlights are: • Premium (high API, LS) crude oils are more suitable for hydrogen savings and minimizing processing costs. But these crudes may not be economical under all scenarios because they are available at higher costs. The price differential of benchmark and premium crude oils is less at lower crude oil prices. Thus, processing premium crudes may be economical at lower crude oil prices. • Poorer-quality (low API, HS) crude oils are available at comparatively low costs. But processing them is more difficult and it entails higher costs. This option may be economical when higher discounts are offered on these crude oils. However, the suitable refinery configurations may support reducing the RPC and making them suitable (optional). • To make the economical decisions, comprehensive tools are available, which required a detailed database. Such databases are not always available, especially for new crude oils/blends. • A user-friendly tool with minimum input data information for quick business decisions is sought by the refining industry. Such a tool would facilitate pre-screening of crude oils under different scenarios. A simple and accurate tool can provide crude oil selection under real-life scenarios with prevailing price variations of benchmark crude oils, products, hydrogen and refining processes. The tool is also useful for hydrogen management within refinery premises on a regular basis. There is no alternative to a detailed crude oil evaluation done through rigorous experimentation following API/ASTM methods; however, the crude selection model is a step forward for unlocking the true value of crude oils for quick business decisions. HP ACKNOWLEDGMENTS The authors express their sincere thanks to Mr. K. V. Seshadri, ED (R&D) for constant support and permission for publication. Many thanks to Mr. Ravitej and Mr. Sandip Agarwal from Scheduling and Blending department of the Mumbai Refinery for their inputs and validation of the crude selection model with actual refining processing data.

PROCESS/PLANT OPTIMIZATION LITERATURE CITED Goldhammer, B., et al., “Future of opportunity crudes processing,” Petroleum Technology Quarterly, Winter 2011. 2 Kumar, R., P. Parihar and R. K. Voolapalli “New crude oil basket for hydrogen savings,” Petroleum Technology Quarterly, Spring 2012. 3 Kumar, R., et al., “Processing opportunity crude oils—A catalytic process for high-acid crudes,” Hydrocarbon World, Vol. 4, No. 2, pp. 64–68, 2009. 4 Bacon, R. and S. Tordo, “Crude oil price differentials and differences in oil Qualities: a statistical analysis,” Energy sector management assistance programme technical paper 081, 2005. 5 Fattouh, B., “The dynamics of crude oil price differentials,” Centre for Financial and Management Studies, SOAS and Oxford Institute for Energy Studies, January 2008. 6 Keamer, L., “Crude oil and quality variations,” Petroleum Technology Quarterly, Autumn 2004. 7 Blume, A. M. and T. Y. Yeung, “Analysing economic viability of opportunity crudes,” Petroleum Technology Quarterly, Autumn 2008. 8 Yeung, T. W., “Evaluating opportunity crude processing,” Petroleum Technology Quarterly, Winter 2006. 9 The World Bank, “Crude oil prices, predicting price differential based on quality,” note No. 275, October 2004. 10 HandBook on Crude Oil Evaluations, Vols. 1 and 2,Corporate R&D Centre, Bharat Petroleum Corp. Ltd., 2007. 11 Parihar, P., et al., “Routing of intermediate distillate streams for refinery margins—Optimization,” Hydrocarbon Processing, February 2012. 12 Lambert, D., “Determination of crude properties,” Petroleum Technology Quarterly, Spring 2007. 13 Hartmann J. C. M., “Crude valuation for crude selection,” Petroleum Technology Quarterly, Winter 2002. 14 Swafford, P. and M. McCarthy, “Improving crude oil selection,” Petroleum Technology Quarterly, Autumn 2008. 15 Stommel, J. and B. Snell, “Consider better practices for refining operations,” Hydrocarbon Processing, October 2007. 16 Rajeev Kumar, R. et al.,”Maximization of VGO through deep-cut distillation,” Petroleum Technology Quarterly, Spring 2011 pp. 87–91, 2011. 1

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17 Kumar,

R., et al., “Diverting low-sulphur heavy stocks for fuel oil production,” Summer, Petroleum Technology Quarterly, pp. 43–47, 2011. 18 Scherzer, J, and A. J. Gruia, Hydrocracking Science and Technology, Marcel Dekker New York, 1996. 19 Ancheyta, J., S. Sánchez and M. A., “Kinetic modeling of hydrocracking of heavy oil fractions: a review,” Catalysis Today, Vol. 109, pp, 1–4, 76–92, 2005. 20 US Bureau of Standards, Miscellaneous Publication No. 97 (9.11.1929).

Rajeev Kumar is deputy manager (R&D) with Bharat Petroleum Corp.,Ltd., India. His areas of interest are crude oil processing, refining processes, modeling, simulation and optimization. He also has research interest in process development for biodiesel and biolubricants. Mr. Kumar holds an MS degree in chemical engineering from the Indian Institute of Technology, Kanpur, India.

Prashant Parihar is deputy manager (R&D) with Bharat Petroleum Corp., Ltd., India. He has more than six years of research experience in hydroprocessing and optimization of refining processes. He holds an MS degree in chemical engineering from the Institute of Chemical Technology, Mumbai.

Ravi K. Voolapalli is chief manager at Corporate R&D Centre, Bharat Petroleum Corporation Ltd., India. He has 22 years of research experience. His areas of interest are refinery processes, coal-to-liquid technologies, modeling, scale-up and optimization. Dr. Voolapalli holds a BTech degree in chemical engineering from Andhra University, Visakhapatnam, an MTech degree in chemical engineering from the Indian Institute of Technology, Kanpur, and a PhD in chemical engineering from Imperial College of Science Technology and Medicine, London.

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The Bhopal disaster Understanding the impact of unreliable machinery K. BLOCH, Consultant, Rosemount, Minnesota; and B. JUNG, Consultant, Woodbury, Minnesota

common misconception lingering today is that the toxic chemical release in Bhopal, India, was an extreme, outlier event. However, when the public record is considered, a different picture emerges. What follows is a careful and recent evaluation of information that has slowly been released into the public domain over a twentyseven year period. The warnings this assessment offers should be of poignant interest and concern for all organizations responsible for the lives of others. Methyl isocyanate release. Union Carbide began pro-

ducing methyl isocyanate (MIC) in Bhopal, India, on February 5, 1980.1 MIC is a highly reactive intermediate chemical that Union Carbide used to manufacture various pesticides. It is also a very lethal substance that can be harmful or fatal if inhaled or absorbed through the skin.2 MIC reacts exothermically with a variety of potential contaminants including rust and particularly water.2 Routine maintenance activities were taking place in the factory on the evening of December 2, 1984. Sometime around 10:45 p.m., a large quantity of water began entering a chemical storage tank containing over 40 tons of MIC. The reaction mixture inside the tank progressively warmed as conditions moved closer to a thermal runaway reaction. Water continued entering the tank until shortly after midnight (December 3, 1984), when the thermal runaway reaction took place. This caused the MIC storage tankâ&#x20AC;&#x2122;s pressure gauge, shown in Fig. 1, to suddenly spike above scale.3 Although this drew attention to the tank, it was too late to stop the catastrophic loss of process containment. Shortly after the runaway reaction occurred, hot MIC vapor burst through the tankâ&#x20AC;&#x2122;s automatic pressure relief system and into the relief valve vent header (RVVH).3 Although this prevented an explosion, a major release involving up to 40 tons of toxic MIC drifted downwind into the surrounding community. By morning, thousands of people and animals were dead.4 Systems that should have prevented the release, including a refrigeration unit and alarms, failed. None of the safety equipment capable of containing the potential release or at least minimizing its consequences had worked either. The factory never reopened and Union Carbide, once an undisputed leader in the chemical manufacturing industry, struggled to survive before selling off its remaining business in 1999.5

can clog pipes.6 Therefore, stainless steel is recommended in MIC service.6 In theory, more economical carbon steel components could be substituted when protected by a corrosion inhibitor4 such as nitrogen. If so, then the inert gas would be critical for mechanical integrity (corrosion and fouling resistance). However, stainless steel represents an inherently safe choice that eliminates the reactivity hazard associated with carbon steel.4 Designing the disaster. In March 1985, Union Carbide issued an investigation report3 that included the piping and instrumentation diagram (P&ID) shown in Fig. 3. The P&ID shows the MIC storage tank design. Fig. 3 provides design information that explains how equipment reliability contributed to the Bhopal disaster. The MIC produced at the factory was stored in two stainless steel storage tanks, designated as Tanks 610 and 611.4 An identical tank (Tank 619) received contaminated material from either Tank 610 or 611 on an emergency basis only.3 This tank provided extra storage volume to allow for an adequate response to a potential thermal runaway reaction.3 A nitrogen blanket4 was used to main-

FIG. 1

a) MIC storage tank 610 control room pressure gauge. b) MIC storage tank control room temperature gauge.

Methyl isocyanate (MIC) (gas or liquid)

3H3C-N=C=O

Catalyst

Fe2O3

MIC trimer (solid) O H3C O

N N

Heat

CH3 + 298 cal/g O

CH3

About MIC. Carbon steel is incompatible with MIC.4 Rust

(Fe2O3) catalyzes the exothermic MIC trimerization reaction shown in Fig. 2.4 This reaction forms a nuisance deposit that

FIG. 2

MIC trimerization reaction.

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PROCESS/PLANT OPTIMIZATION

ppm5 compared to a 10 ppm TLV for H2S. MIC could therefore not safely be released MIC storage tank into the environment.2 To process vent header (PVH) From high purity nitrogen header Although the transfer pumps were proFrom transfer pump return vided to export MIC into the derivatives To relief valve vent header (RVVH) From refrigeration unit unit, there is no record of their use at any time while the factory was in operation. From MIC reﬁning still (MRS) PIC Safety valve Instead, an alternative transfer method To derivatives unit PI was developed that excluded the pumps. TIA LIA This method involved raising the MIC Rupture Transfer Refrigeration storage tank pressure to at least 14 psig pump Concrete Earth mound disc unit with nitrogen.9 Under these conditions, deck the MIC would reverse-flow directly into To reject line the derivatives unit through the alternaCirculation tive pathway shown in Fig. 5. This practice pump minimized the potential for transfer pump PI Pressure indicator Ground seal failures to expose factory workers to PIC Pressure indicator/controller level Mixing eductor Sump TIA Temperature indicator/alarm the lethal process.6 LIA Level indicator/alarm However, nonstandard operating procedures10 may address one hazard while FIG. 3 Original MIC storage tank P&ID. introducing others. In this case, pressurizing the tanks in order to bypass the transfer pumps required isolating the tanks from the PVH. As the P&ID shows, this interrupted excess nitrogen flow into the PVH.4 Loss of excess nitrogen flow was an issue because the PVH and RVVH were made of carbon steel.4 Fig. 6 shows the vent gas scrubber (VGS) piping configuration. The photograph shows that the vent header inlet pipes enter above the VGS caustic overflow line. Therefore, air migrated into the atmospheric VGS when nitrogen was isolated to pressurize the tanks. Afterward, the inert environment inside the PVH and RVVH ceased to exist. The vent lines started to corrode,4 which produced rust. Rust catalyzes the formation of MIC trimer deposits, according to Fig. 2. After sealing the tanks, other MIC vapor sources continued venting into the PVH.3 This prompted the creation of a maintenance procedure to remove MIC trimer deposits polymerizing inside the PVH and RVVH. The procedure involved flushing out FIG. 4 MIC storage tank 610 side-head nozzle configuration. the MIC trimer deposits with water.11 Although MIC could still be exported without the transfer pumps, there was no way to refrigerate MIC without operattain slight pressure6 inside the MIC storage tanks while continuing the circulation pumps. A seal failure on or before January ously purging MIC vapor into the process vent header (PVH). 7, 1982,8 provided a maintenance opportunity to “upgrade” The tanks were equipped with the two centrifugal pumps the original metallic seal with a more fouling resistant, but appearing in Fig. 3. Each of the pumps had a specific function. weaker ceramic seal.6 In MIC fouling service (reactive environment), using a ceramic seal may seem logical. But if a The “transfer pump” exported stored MIC into the derivatives force-related failure mechanism is causing unacceptable seal unit as needed to produce pesticides. The “circulation pump” performance, then a lower strength ceramic material may not processed MIC through a fluorocarbon-based refrigeration sysbe the best choice.12 tem.7 The refrigeration system kept the stored MIC temperature 3 2 near 0°C to prevent a thermal runaway reaction. On January 9, 1982, the fragile ceramic substitute seal was shattered in an unprecedented catastrophic failure.8 This failure The pumps were connected to four flanged nozzles on the side of each tank head. Fig. 4 shows how these nozzles were produced a massive MIC release that sent about 25 workers to configured on Tank 610. Both pumps circulated MIC through the hospital with serious injuries.13 On January 12, 1982, a internal pipe extensions that dropped to the tank bottom, as formal notice was issued to declare that the refrigeration sysshown in the P&ID. The discharge lines returning to the tank tem was being shut down.8 In doing so, a third non-standard were provided so that the pumps would operate continuously. operating procedure was introduced: running the plant without MIC refrigeration. Procedures. The factory suffered from a series of chronic MIC leaks.8 MIC is a highly volatile compound that represents an Disabling instruments and alarms. After shutting down immediate exposure hazard upon its release.2 For reference purrefrigeration system, the MIC storage temperature varied from poses, the eight-hour threshold limit value (TLV) for MIC is 0.02 about 15°C to 40°C.14 This new operating range exceeded the 74

I JUNE 2012 HydrocarbonProcessing.com

PROCESS/PLANT OPTIMIZATION

SPECIALREPORT

11°C MIC storage tank high temperature alarm14 in the control room (Fig. 7). MIC storage tank Therefore, the high temperature alarms To process vent header (PVH) From high purity nitrogen header were disconnected.3 Likewise, the actual From transfer pump return temperature inside the tank was unknown8 To relief valve vent header (RVVH) From refrigeration unit after shutting down the refrigeration system because the control room temperature From MIC reﬁning still (MRS) PIC Safety valve gauge (Fig. 1) was not scaled for operation To derivatives unit PI above +25°C. Similarly, the normal operatTIA LIA ing pressure inside the tank increased from Rupture 2 Transfer Refrigeration less than 2 psig with an unobstructed tank pump Concrete Earth mound disc unit 6 3 vent open to the PVH to about 25 psig deck after bypassing the MIC transfer pumps. To reject line In April 1982, factory workers printed Circulation hundreds of handouts expressing their pump concern about decisions being made PI Pressure indicator Ground inside the factory that might influence PIC Pressure indicator/controller level Mixing eductor Sump TIA Temperature indicator/alarm the community outside the factory. 8 In LIA Level indicator/alarm May 1982, an independent audit team from the US arrived in Bhopal to perform FIG. 5 Alternative MIC storage tank operating method. a safety audit.6 The audit report formalized several recommendations that might improve managing the MIC pump hazards. For example, it was recommend that a nitrogen purge system with low flow alarms at an alternative MIC system venting into the PVH6 should be installed (this would restore the inert environment inside the PVH and RVVH without operating the transfer pumps). Installing dual seals on centrifugal pumps6 was also recommended. Another recommendation was to provide water spray protection for the MIC pumps in the storage area, for vapor cloud suppression.15 The audit team complimented the factory’s creative approach to improving workplace safety with nonstandard operating and maintenance procedures.4 It is, therefore, understandable why the decision to shut down the refrigeration system was not questioned.8 Accordingly, the factory’s safety manuals were FIG. 6 Vent gas scrubber pipe configuration. rewritten in 1983 and 1984 to reflect actual operation without 8 MIC refrigeration. The fateful night. On the evening of December 2, 1984, the

vent lines were corroded and choked with MIC trimer deposits.4 The pipes were being flushed with water to remove the MIC trimer deposits.13 MIC trimer deposits form in the presence of rust. Rust forms on carbon steel pipes not protected by an inhibitor. The inhibitor (nitrogen) was isolated from the PVH and RVVH in order to pressurize the MIC storage tanks. The MIC storage tanks were pressurized to bypass the transfer pumps. Somehow, water entered Tank 610, which contained over 40 tons of MIC. Under normal circumstances, this would have activated the tank’s high temperature alarm. But the high temperature alarm was disconnected when the refrigeration system was shut down. Likewise, the control room MIC temperature gauge could not be trusted because it normally read above scale without refrigeration. The refrigeration system was shut down almost three years before the incident4 because pump seal failures exposed factory workers to the hazardous process. The contamination event inside Tank 610 remained hidden while the reaction mixture temperature continued rising. Tank 610’s vent valve was leaking on the evening of December 2, 1984. 4 The MIC storage tank pressure increased as the reaction mixture evolved more vapors into the PVH. 3

Although the control room pressure gauge seemed to be within normal range for a sealed tank, 3 the tank was not sealed. 3 Therefore, contamination was not detected until a thermal runaway reaction took place, which sent the tank’s pressure gauge off scale.13 Although factory workers responded immediately, by that time it was too late. The refrigeration equipment and process alarms were provided to prevent a thermal runaway reaction should the MIC be contaminated by any means. But process safety was compromised in an attempt to manage personal exposure hazards represented by potential pump seal failures. Can we learn more from Bhopal? Bhopal forever

changed the way industry approaches process safety management (PSM). Increasing clarity around the events leading up to the release complements and reinforces these important lessons. Time has allowed us to take an even closer look at regrettable decisions that resulted in disabling the system whose purpose it was to prevent the scenario that resulted in the release. Most industry professionals no doubt plainly see from this examination that we confront the same decisions at work every day. Perhaps this is the message contained in HYDROCARBON PROCESSING JUNE 2012

I 75

SPECIALREPORT

PROCESS/PLANT OPTIMIZATION process isolation during a routine maintenance procedure (perhaps even during a maintenance activity required to contain the process in a factory like yours). What can you do? When you report for work tomorrow,

remember Bhopal. And when you return to the comfort of your home, convince yourself it is because you did. HP PHOTO CREDITS Figs. 1, 6 and 7: Dennis Hendershot Fig. 4: Paul Cochrane LITERATURE CITED Deposition of Vinod Kumar Tyagi, “Proceedings before the chief judicial magistrate, Bhopal on March 6, 7, and 8, 2000 in criminal case No. RT-8460/96,” 2010, http://bhopal.net/oldsite/oldwebsite/new2depo.html. 2 Union Carbide Corporation, “Review of MIC production at the Union Carbide Corporation Facility Institute West Virginia April 15, 1985,” Danbury, Connecticut, 1985, http://nepis.epa.gov/Exe/ZyPURL. cgi?Dockey=2000W9PM.txt. 3 Union Carbide Corporation, “Bhopal MIC incident investigation team report March, 1985,” Danbury, Connecticut, 1985, http://nepis.epa.gov/Exe/ ZyPURL.cgi?Dockey=2000W9PM.txt (at Attachment 1). 4 District Court of Bhopal, India, “State of Madhya Pradesh vs. Warren Anderson & Others,” June 7, 2010, http://www.indiaenvironmentportal.org. in/files/UCIL.pdf. 5 Willey, R., D. Hendershot and S. Berger, “The accident in Bhopal: Observations 20 years later,” 40th Loss Prevention Symposium, Orlando, 2006, http://www.aiche.org/uploadedfiles/ccps/about/bhopal20yearslater.pdf. 6 D’Silva, T., The Black Box of Bhopal, Trafford Publishing, Victoria, BC, Canada, 2006, ISBN 978-1-4120-8412-3 7 Worthy, W., “Methyl Isocyanate: The Chemistry of a Hazard,” Chemical & Engineering News, p. 30, February 11, 1985. 8 Supreme Court of India, “Curative Petition (Criminal) No. 39-42 of 2010 in Criminal Appeal No. 1672-75 of 1996 on Bhopal Gas Disaster,” April 2011, http://www.indiaenvironmentportal.org.in/files/CriminalCurativeBhopal.pdf. 9 Kalelkar, A. S., “Investigation of large-magnitude incidents: Bhopal as a case study,” Institution of Chemical Engineers Conference on Preventing Major Chemical Accidents, London, UK, 1988, http://www.bhopal.com/~/media/ Files/Bhopal/casestdy.pdf. 10 Wines, M., “Firm calls ‘deliberate’ act possible in Bhopal disaster,” Los Angeles Times, March 21, 1985, http://articles.latimes.com/1985-03-21/news/ mn-20658_1_bhopal-disaster#.Tr6AWuGD4LY. 11 Examination of Dr. S. Varadarajan, “Proceedings before the chief judicial magistrate, Bhopal on January 10 and 11, 2000, in Criminal Case No. RT-8460/96,” http://bhopal.net/oldsite/oldwebsite/newdepo.html. 12 Bloch, H. P., Pump Wisdom, John Wiley & Sons, Hoboken, NJ, 2011. ISBN 978-1-118-04123-9 13 Agarwal, A. and S. Narain (editors), “The Bhopal Disaster,” State of India’s Environment 1984-85: The Second Citizens’ Report, p. 207, 215, 1985, http:// www.cseindia.org/userfiles/THE%20BHOPAL%20DISASTER.pdf. 14 Supreme Court of India, “Supreme Court Judgment on Bhopal Gas Disaster,” September 13, 1996, http://www.indiaenvironmentportal.org.in/files/SC%20 judgement%20of%201996.doc. 15 Union Carbide Corporation, “Operational Safety Survey,” Danbury, CT, 1982, p. 6, http://bhopal.net/source_documents/1982%20safety%20audit.pdf. 1

FIG. 7

MIC storage tank 610 high temperature panel alarm.

“recognized and generally accepted good engineering practices.” The decisions we make throughout the life of a process, especially before its construction, can and will affect us as well as all those who follow. As an industry professional you will make decisions daily that as a whole define your process safety identity. We can’t tell you what the right answers are. It is therefore important to allow your conscience be guided by what took place in Bhopal. This is where Bhopal has even more redeeming value. With these thoughts in mind, the focus is on insightful advice: • When you choose not to investigate a chronic failure, remember Bhopal. • When the right choice is not the most economical choice, remember Bhopal. • When choosing to accept actual operation because you cannot get expected or design operation, remember Bhopal. • When designing a solution that manages a hazard instead of eliminating it, remember Bhopal. • When tempted to execute a procedure the way you think it should be written instead of how it is actually written, remember Bhopal. • When thinking about substituting engineered equipment with people, remember Bhopal. • When you perform a safety audit, remember Bhopal. • When redesigning a system to make it “safer,” remember Bhopal. • When operators have concerns with a decision you are about to make, remember Bhopal. • When making changes for the sake of improving personal safety, remember Bhopal. Finding your identity. After 27 years, there are two prevailing theories that may explain how water entered the MIC storage tank. An examination of the events preceding the incident supports the argument that this detail is irrelevant.5 However, the explanation you favor is governed by your process safety identity. If you believe that a single event can cause a process safety incident of extraordinary magnitude, then the cause was probably sabotage. But if you believe that significant process safety failures result from a complex series of interacting events that may include design defects, repeat failures and missed warning signals, then maybe the cause was inadequate 76

I JUNE 2012 HydrocarbonProcessing.com

Kenneth Bloch is a PHA/loss control engineer who specializes in petrochemical industry incident investigation and failure analysis. He speaks regularly at AFPM, API, and AIChE process safety symposiums on experiences that help prevent process safety failures in the manufacturing industry. Mr. Bloch graduated with honors from Lamar University in Beaumont, Texas, in 1988.

Briana Jung is a senior operations engineer in the petrochemical industry. She is a certified PHA facilitator with over 10 years of process plant troubleshooting and optimization experience. Ms. Jung graduated from the University of Minnesota with a BS in chemical engineering in 2001.

PROCESS/PLANT OPTIMIZATION

SPECIALREPORT

Fine-tune relief calculations for supercritical fluids Improved process simulation assists with relief load and valve sizing P. NEZAMI, Jacobs Engineering, Houston, Texas; and J. PRICE, Jacobs Consultancy, Houston, Texas

48 47

36 46 35

45 44

34 43 33

42 41

Mass method 1 Mass method 2 Volume method 1 Volume method 2

40 39 505 FIG. 1

510

515

520 525 Temperature, °F

Volume relief rate, 100 ft3/hr

where: VR = Volumetric relief rate Q = Heat input h1 = Initial specific enthalpy h2 = Final specific enthalpy 1 = Initial density 2 = Final density The mass relief rate can be determined using the average of the initial and final densities for each interval. ⎛ ρ + ρ2 ⎞⎟ M R = ⎜⎜⎜ 1 ⎟×V (2) ⎝ 2 ⎟⎠ R where: MR = Mass relief rate

Both the volumetric and mass relief rates will change during the course of a relief as the specific volume and enthalpy of the fluid change. To estimate the relief rates at different intervals, one can generate a property table in a process simulator to calculate the densities and specific enthalpies of the fluid at a constant relief pressure over a given temperature range. The volumetric and mass relief rates for each interval can be calculated using Eq. 1 and Eq. 2, respectively. In this study, a series of calculations were conducted for randomly selected n-paraffins, i-paraffins and aromatic compounds from C1 to C16 , using the Peng-Robinson equation of state (EOS). The results indicate that the maximum mass relief rate occurs at lower temperature than the maximum volumetric relief. Both temperatures where the maximum relief rates occur are greater than the critical temperature. Improving the calculation precision by reducing the temperature increments does not affect the temperatures at which the mass and the volume relief rates peak. (Smaller temperature increments result in a smaller enthalpy change, Δh, which translates to a smaller time span.) In fact, it is possible to mathematically prove that the two peaks occur at two different temperatures for real gas. This is where this article differs from the one presented at the API meeting.3

Mass relief rate, 1,000 lb/hr

n the past 40 years, several different methods have been suggested for relief load and pressure relief valve (PRV) orifice sizing calculations for a supercritical fluid exposed to an external heat source. The following sources include some of these methods: • API 521 suggests the use of a latent heat of 50 Btu/lb for hydrocarbons near the critical point. In the absence of a better method, this led to the use of 50 Btu/lb for even supercritical fluids. • “A Calculation of Relieving Requirements in the Critical Region”1 • “Rigorously Size Relief Valves for Supercritical Fluids”2 • “Calculation of Relief Rate Due to Fluid Expansion and External Heat.”3 The most recent method, “Calculation of Relief Rate Due to Fluid Expansion and External Heat,” was presented at the API 2010 Summer Meeting. As the title suggests, the relief load is calculated based on the expansion of the fluid due to absorbed heat. This method can be used for any fluid, including vapor and liquid, as long as no phase change occurs. To maintain a constant pressure at a fixed volume, the relief rate at any interval must be equal to the additional volume created by the change in specific volume from heat input to the fluid. However, some assumptions must be made and some basis must be set to make this method viable: • Other than the relieving stream, no fluid enters or leaves the vessel during the course of relief • There is no change of phase during the course of relief. A simple equation can be set to calculate the relief rate at each interval: ⎛1 Q 1⎞ VR = ×⎜⎜ − ⎟⎟⎟ (1) ⎜ h2 − h1 ⎝ ρ2 ρ1 ⎟⎠

530

535

31 540

Volumetric and mass relief rates (10 data points).

HYDROCARBON PROCESSING JUNE 2012

I 77

SPECIALREPORT

PROCESS/PLANT OPTIMIZATION

The subject was examined using two different approaches to calculate maximum relief rates (volumetric and mass) for n-hexane at 660-psia relief pressure with 5 million Btu/hr absorbed heat and a one-hour duration. In the first approach, the relief rates were calculated by setting up property tables and using Eqs. 1 and 2 for three different temperature increments. The second approach was based on stepwise simulation models with three different time spans. The initial and final temperatures were made the same to apply the same bases for all calculations. Results are plotted in Figs. 1, 2 and 3. The time spans in these plots are six minutes for Fig. 1, three minutes for Fig. 2, and two minutes for Fig. 3. It is clear that the impact of reducing time span on the temperatures at which the relief rates peak is insignificant. It is also obvious that the two methods yield almost the exact same results for the volumetric relief rates and very similar results for the mass relief rates. The small difference in mass relief rate is due to the fact that, in the first approach, at each interval the average of the initial and the final densities are used to convert volumetric relief rate to mass 37

48 47

44 34 43 42

Mass method 1 Mass method 2 Volume method 1 Volume method 2

40 39 500 FIG. 2

505

510

515 520 525 Temperature, °F

530

535

PRV orifice calculation. The API 520 equation for compress-

ible gas, which is derived from an ideal gas along an isentropic path, is not a suitable method for supercritical fluids, since supercritical fluids are far from ideal gas. Instead, an isentropic mass flux expression should be used for sizing relief valves in supercritical service: P ⎡ ⎤ ⎢ −2 v×dP ⎥ ⎢ ∫ ⎥ ⎢ ⎥ (3) P1 2 ⎢ ⎥ G = 2 ⎢ ⎥ vt ⎢ ⎥ ⎢ ⎥ ⎢ ⎥ ⎦ MAX where: ⎣ G = Mass flux v = Fluid-specific volume P = Fluid pressure vt = Specific volume at throat conditions P1 = Fluid pressure at the inlet of the nozzle 120 100 Maximum value, %

Volume relief rate, 100 ft3/hr

Mass relief rate, 1,000 lb/hr

36 46

relief rate. In the second approach, only the final density is used to convert volumetric relief rate to mass relief rate. The main objective of this exercise (and the next step in the relief valve calculation) is to size the PRV orifice area. The PRV orifice area is a function of relief valve set pressure, relief load, density and some other properties of the relieving fluid. In a scenario where a vessel or container is exposed to external heat, the fluid properties (and the relief load) vary during the course of a relief. The goal is to find the maximum required orifice area, as outlined below.

31 540

80 60 40

0 1.05 37

Volume Mass Oriﬁce area

Volumetric and mass relief rates (20 data points).

FIG. 4

1.15

1.25

1.35 1.45 1.55 Reduced temperature

1.65

1.75

Methane relief at 1,346 psia.

44 34 43 33

42 Mass method 1 Mass method 2 Volume method 1 Volume method 2

41 40 39 500

FIG. 3

505

510

515 520 525 Temperature, °F

Volume Mass Oriﬁce area

100 80 60 40 20

530

535

Volumetric and mass relief rates (30 data points).

I JUNE 2012 HydrocarbonProcessing.com

120

Maximum value, %

Volume relief rate, 100 ft3/hr

Mass relief rate, 1,000 lb/hr

36 46

31 540

0 1.05 FIG. 5

1.10

1.15

1.20 1.25 1.30 Reduced temperature

Iso-octane relief at 745 psia.

1.35

1.40

Select 72 at www.HydrocarbonProcessing.com/RS

SPECIALREPORT

PROCESS/PLANT OPTIMIZATION

Eq. 3 is the result of a volumetric energy balance for an isentropic nozzle, and it is valid for any homogeneous fluid regardless of the non-ideality or compressibility of the fluid. Derivation details of the equation and the numerical examples for mass flux calculation are presented in Appendix B of API 520. Eq. 3 can be solved with a numerical integration technique. With the use of a process simulator, a property table can be generated along the isentropic line to find specific volumes at various pressures, beginning at relief pressure and moving down to the relief valve back pressure. Solving Eq. 3 for each downstream pressure will result in a series of mass fluxes, which will peak when the flow is choked in the nozzle. The required orifice area for the relief valve may be simply calculated by dividing the mass flux by the mass relief rate and the discharge coefficient: (4) MR A= G Kd where: A = Required orifice area Kd = Relief valve discharge coefficient It is surprising that the maximum required orifice area is not in line with either the maximum mass relief rates or the maximum volumetric relief rates. Figs. 4–7 illustrate the relationship

between the maximum relief rates (mass and volumetric) and the maximum required orifice area for the relief valve for some of the hydrocarbons used in this study. Fig. 8 shows the relationship between the maximum mass relief rate, the maximum volumetric relief rate, and the maximum required orifice area for n-pentane at various relief pressures. The maximum required orifice area appears at a temperature between the corresponding temperatures of the maximum volumetric and maximum mass relief rates for relief pressures from PR = 1 to PR = 7. Similar patterns were observed for other pure hydrocarbons used in the study. Numerical example. The following example illustrates

relief load and orifice-sizing calculations for a vessel containing n-hexane and absorbing 5 million Btu/hr of heat with a relieving pressure of 660 psia (PR = 1.5). Relief load calculation. A spreadsheet is used to calculate the relief rates at various stages of a relief incident. Utilizing a process simulator, a property table was created to calculate densities, along with specific enthalpies and entropies of the fluid at various temperatures. Using Eqs. 1 and 2, the volumetric and mass relief rates are calculated at different temperatures. The relief rates will peak if

TABLE 1. Volumetric and mass relief rates at different temperatures Temperature, °F

Reduced temperature

Density, lb/ft³

Enthalpy, Btu/lb

Entropy, Btu/lbmol–°F

504.2

1.054

14.93

–679.84

52.46

3,037

45,903

506.4

1.057

14.55

–677.12

52.70

3,143

46,331

508.7

1.059

14.19

–674.41

52.94

3,242

46,596

510.9

1.062

13.84

–671.73

53.18

3,331

46,693

513.2

1.064

13.50

–669.07

53.42

3,410

46,621

515.4

1.067

13.18

–666.44

53.65

3,478

46,390

517.7

1.069

12.87

–663.86

53.88

3,534

46,014

519.9

1.072

12.57

–661.31

54.10

3,578

45,511

522.2

1.074

12.29

–658.81

54.32

3,612

44,901

524.4

1.076

12.03

–656.34

54.54

3,635

44,205

526.7

1.079

11.78

–653.92

54.75

3,650

43,443

528.9

1.081

11.54

–651.55

54.96

3,657

42,633

531.2

1.084

11.32

–649.21

55.16

3,657

41,791

533.4

1.086

11.11

–646.90

55.36

3,651

40,929

535.7

1.089

10.91

–644.64

55.56

3,640

40,060

100

80 60 40 Volume Mass Oriﬁce area

20 0 1.01 FIG. 6

Maximum value, %

120

Maximum value, %

120

1.03

1.05

1.07 1.09 1.11 Reduced temperature

Hexadecane relief at 412 psia.

I JUNE 2012 HydrocarbonProcessing.com

1.13

Vol. relief rate, ft³/hr Mass relief rate, lb/hr

80 60 40 Volume Mass Oriﬁce area

20 1.15

0 1.05 1.075 1.1 1.125 1.15 1.175 1.2 1.225 1.25 1.275 1.3 Reduced temperature FIG. 7

Benzene relief at 1,428 psia.

PROCESS/PLANT OPTIMIZATION

Reduced pressure

the temperature range is wide enough to cover the temperatures at which the peaks occur. Table 1 is a sample calculation for n-hexane at PR = 1.5. As shown in Table 1, the maximum mass relief rate occurs when the temperature in the vessel reaches 510.9°F (TR = 1.062) and the maximum volumetric relief rate is 528.9°F (TR = 1.081). Relief valve orifice calculation. In the process simulator, a constant entropy table has been developed for each entropy between the maximum mass and the maximum volumetric relief rates in Table 1. The property tables include the specific volume of the fluid at different pressures, from relief pressure to PRV back pressure. Using a spreadsheet, the mass flux is calculated by numerically integrating “v ΔP ” along the range of pressures, from relief pressure to the PRV back pressure. The maximum mass flux represents the choked conditions in the nozzle. Tables 2–4 show sample calculations for three different entropies. Now the final table can be generated to calculate the maximum required orifice area throughout the relief event. Each row of the table will include throat pressure, specific entropy, mass relief rate, maximum mass flux, and the required orifice area, which is calculated from the mass relief rate and the mass flux using Eq. 4. The orifice area calculation is presented in Table

SPECIALREPORT

5. For a relief valve with a 0.95 discharge coefficient, the actual required orifice area would be 0.564/0.95 = 0.594 in2. Takeaway. As process simulator capability increases, the ability of engineers to utilize this software allows for a significantly more precise calculation process. The possibility to generate additional data points for this calculation by decreasing the step change in enthalpy will help increase the precision of the calculation. However, it is shown that, at extremely small step changes, the temperatures at which the maximum mass rate and maximum volume rate are generated do not approach each other. Sizing a relief device in this fashion will ensure that the orifice is adequately sized without the application of an overly conservative factor. HP

TABLE 3. Mass flux calculation for s = 54.10 Btu/lbmol–°F Pressure, psia

Specific volume, ft³/lb

∫–2vdP, ft²/s²

Mass flux, lb/sec.–ft2

660.0

0.07954

–

610.4

0.08749

38,414

2,240.2

560.7

0.09839

81,162

2,895.6

511.1

0.11339

129,865

3,178.3

461.4

0.13367

186,683

3,232.3

411.8

0.16047

254,328

3,142.8

362.2

0.19550

336,193

2,965.9

312.5

0.24187

436,777

2,732.5

262.9

0.30539

562,633

2,456.2

213.3

0.39756

724,295

2,140.7

163.6

0.54390

940,810

1,783.3

114.0

0.81382

1,253,057

1,375.5

64.3

1.48679

1,782,147

897.9

14.7

6.46163

3,610,108

294.0

5 4 3 Max. mass Max. volume Max. oriﬁce

1 1.00 1.05 1.10 1.15 1.20 1.25 1.30 1.35 1.40 1.45 1.50 Reduced temperature FIG. 8

N-pentane supercritical relief.

TABLE 4. Mass flux calculation for s = 54.96 Btu/lbmol–°F

TABLE 2. Mass flux calculation for s = 53.18 Btu/lbmol–°F ∫–2vdP, ft²/s²

Pressure, psia

–

660.0

0.08665

–

34,720

2,367.1

610.4

0.09576

41,951

2,138.8

3,075.2

560.7

0.10785

88,777

2,762.8

0.12383

142,057

3,043.8

Specific volume, ft³/lb

660.0

0.07225

610.4

0.07872

560.7

0.08788

73,034

Specific volume, ft³/lb

∫–2vdP, ft²/s²

Mass flux, lb/sec.–ft2

Pressure, psia

Mass flux, lb/sec.–ft2

511.1

0.10124

116,526

3,371.9

511.1

461.4

0.12049

167,519

3,396.8

461.4

0.14473

203,819

3,119.3

411.8

0.14697

229,028

3,256.3

411.8

0.17184

276,623

3,060.8

362.2

0.18199

304,681

3,033.0

362.2

0.20708

363,766

2,912.5

0.25379

469,756

2,700.6

312.5

0.22824

399,025

2,767.6

312.5

262.9

0.29126

518,499

2,472.2

262.9

0.31796

601,247

2,438.7

213.3

0.38228

673,399

2,146.6

213.3

0.41135

768,974

2,131.8

163.6

0.52631

882,356

1,784.8

163.6

0.55995

992,352

1,779.0

0.83444

1,313,031

1,373.2

114.0

0.79141

1,185,404

1,375.7

114.0

64.3

1.45149

1,701,223

898.6

64.3

1.51947

1,854,378

896.2

14.7

6.32557

3,489,778

295.3

14.7

6.58830

3,718,987

292.7

HYDROCARBON PROCESSING JUNE 2012

I 81

SPECIALREPORT

PROCESS/PLANT OPTIMIZATION

TABLE 5. Mass flux and PRV orifice area calculation Throat pressure, psia

Entropy, Btu/lbmole–°F

Vol. relief rate, lb/hr

Mass relief rate, lb/hr

Mass flux, lb/s–in.²

Orifice area, in.²

488.8

52.46

3,037

45,903

3,606

0.509

488.8

52.70

3,143

46,331

3,531

0.525

488.8

52.94

3,242

46,596

3,464

0.538

475.6

53.18

3,331

46,693

3,405

0.549

475.6

53.42

3,410

46,621

3,354

0.556

475.6

53.65

3,478

46,390

3,308

0.561

475.6

53.88

3,534

46,014

3,267

0.563

475.6

54.10

3,578

45,511

3,230

0.564

462.5

54.32

3,612

44,901

3,196

0.562

462.5

54.54

3,635

44,205

3,167

0.558

462.5

54.75

3,650

43,443

3,140

0.553

462.5

54.96

3,657

42,633

3,115

0.547

462.5

55.16

3,657

41,791

3,092

0.541

462.5

55.36

3,651

40,929

3,070

0.533

462.5

55.56

3,640

40,060

3,050

0.525

LITERATURE CITED

Piruz Latifi Nezami is a process engineering section manager with Jacobs

Francis, J. O. and W. E. Shackelton, “A Calculation of Relieving Requirements in the Critical Region,” API Proceedings—Refining Department, 50th MidYear Meeting, 1985.

Engineering in Houston, Texas. He holds a BS degree in chemical engineering from Sharif University of Technology in Tehran, Iran, and has more than 30 years of experience in the design and engineering of chemical, petrochemical and refining projects.

Ouderkirk, R., “Rigorously Size Relief Valves for Supercritical Fluids,” Chemical Engineering Progress, August 2002.

Freeman, S., and D. Huyen, “Calculation of Relief Rate Due to Fluid Expansion and External Heat,” API Summer Meeting, 2010.

Jerry Price is a refining and petrochemicals consultant for Jacobs Consultancy Inc. in Houston, Texas. Jacobs Consultancy provides expert consulting services to the global oil, refining and chemical industries. Mr. Price previously worked as a process engineer for Jacobs Engineering Group. He holds a BS degree in chemical engineering from Washington University in St. Louis, Missouri.

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VALVES

UPDATE ON VALVES USED IN HYDROGEN SERVICE Recommended practices scrutinize performance issues such as design, packing and metallurgy to mitigate failures T. SEQUEIRA, Tyco Flow Control, Houston, Texas

Processing of heavier crude oil, stricter environmental regulations and detrimental effects from impurities on very expensive refinery assets are increasing the use of and demand for hydrogen. The main hydrogenconsuming refinery processes are hydrotreating to remove sulfur and hydrocracking to convert heavy hydrocarbons and create higher-value fuels. For valve makers, this has increased demand for specialty materials, treatment procedures and zero-leakage performance. Adding further impetus to this demand are rigorous new US and German regulations regarding fugitive emissions and resulting industry and corporate standards. From the metallurgy side, manufacturers must consider the adverse effects that hydrogen at elevated temperatures and pressures can have on carbon and low-alloy steels. They include hydrogen embrittlement, high-temperature hydrogen attack (HTHA) and hydrogen blistering. Hydrogen is colorless, odorless and highly explosive, low-viscosity, low-molecular-weight gas. It is an asphyxiant. These characteristics make zero leakage a necessity. Leakage must be addressed not only at the seat but also at all other valve components. Metal gaskets, requiring more accurate and precise machining, can be useful where temperature limits the use of soft materials. Packing design becomes critical to avoid stem leakage. Additional inspection practices, such as radiography, may be necessary. Adding to the detrimental effects that hydrogen can have on the valve, operating conditions such as temperature, pressure and concentration of hydrogen should be considered when selecting the right materials. Additional steps, such as post-weld heat treatment (PWHT), are required. This article will present recommended practices used by manufacturers to assure safe and optimal valve performance in hydrogen service.

Refining and hydrogen. Crude oil refineries are the worldâ&#x20AC;&#x2122;s largest hydrogen consumers. Refining operations account for almost 90% of the global hydrogen consumption in 2008.1 The gas is central to many refinery unit operations. Hydrogen use is expected to increase 3.4%/yr from 2008 to 2013 and reach 475 billion m3. Of this anticipated 73 billion m3 of new global demand, refineries will consume almost 84%. Several factors are driving this demand: greater production of heavier crude oil with higher sulfur and nitrogen content, lower demand for heavy fuel oil requiring more upgrading requirements and more rigorous regulations for cleaner transportation fuels. Hydrogen is used to upgrade crude oil into light transportation fuels and to also remove sulfur and nitrogen compounds. Operational and safety challenges. Refineries are substantial hydrogen users. The outlook for hydrogen demand growth requires understanding the scope of issues regarding this gas use. In short, hydrogen poses unique material and operational challenges.

Hydrogen is a significant safety risk; it is an explosive and an asphyxiant. It is colorless and odorless, and, thus, it canâ&#x20AC;&#x2122;t be detected by human senses. Because hydrogen is lighter than air, accumulations can be difficult to detect. Its small atomic size compounds the risk by making traditional materials used in gaskets and packing permeable and therefore unsuitable for use. Hydrogen corrosion. Operationally, the hydrogen is corrosive, and it can degrade material performance in many ways. Hydrogen corrosion weakens metals internally when the relatively small atom penetrates metals to adversely affect strength and ductility. Metals can absorb hydrogen when exposed during production, processing and service. For refinery valves, this corrosion is shown in several ways, including hydrogen attack, embrittlement and blistering.2 High-temperature hydrogen attack. HTHA occurs when high concentrations of hydrogen are used under extreme temperatures and pressures. The result is a difficult-to-detect reaction within the steel; the reaction causes the steel to lose strength and ductility. Material failure occurs significantly below the yield stress, with little to no prior sign of weakness. Embrittlement. Hydrogen embrittlement, unlike HTHA, occurs at hydrogen levels as low as a few parts per million. It reduces steel ductility, making the metal brittle and resulting in static-load failures based on stress and time. Due to the difficulty in detecting cracks in welds and hardened steels, embrittlement is a particularly challenging problem. In addition, hydrogen does not affect all metallic materials equally. Most vulnerable are high-strength steels, titanium alloys and aluminum alloys. Hydrogen blistering. Hydrogen blistering occurs mostly in lowstrength alloys and in metals that have been exposed to hydrogencharging conditions. It occurs when hydrogen is absorbed into the metal and diffuses inward. This can precipitate molecular hydrogen at laminations or inclusion and matrix interfaces that can build up enough pressure to cause internal cracks. When these cracks are just below the surface, the hydrogen gas pressure causes the exterior layer of the metal to lift up and form a blister.

Risk to valves. The risk analysis for valves used in hydrogen service is based on three primary factors: pressure, temperature and concentration of hydrogen. In each instance, end users and manufacturers consider the most extreme conditions under which the valve could be subjected. Much of this risk analysis associates the presence of hydrogen in the stream to the possibility of metallic material corrosion such as hydrogen attack, embrittlement and blistering. Metal specifications are usually provided by end users based on their full knowledge of the operating environment. These specifications are typically done in accordance with American Petroleum Institute (API) 941 Recommended Practices, although end users also specify metallurgy developed from internal best practices.3 HYDROCARBON PROCESSING

VALVES 2012

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3.45

1,500

6.90

Hydrogen partial pressure, MPa absolute 10.34 13.79

17.24

20.7

1,400

73.8 800

1,300

700

1,200

3 23

6.0 Cr-0.5 Mo steel

7.3

1,000

23 1 20

1 7 5 7

900

1K 1 1.25 Cr-0.5 Mo steel

800 700

1.0 Cr-0.5 Mo steel

19 21G 12B 25H 20A 21E 26

500

3.0 Cr-1 Mo steel

500

2.25 Cr-1 Mo steel

400

6 8U 1.25 Cr-0.5 Mo steel or 1.0 Cr-0.5 Mo steel 5 1P 1 9 4 Carbon steel

17 1,000

400

300 500

24 (28,000)

600

2.25 Cr-1 Mo steel

Note: See annex A and ﬁgure 1a for 0.5 Mo steels

23F 23 16C 1D 23 23 11 23 19 20 33S 1 1 23 23 23 18T 1 16

600

13+0.25%V 3 13 13 13 13+0.1%V 14+0.25%V

1,500 2,000 Hydrogen partial pressure, psia

Source: Anacortes NHT Investigation Report – July 21, 2011

2,500

Temperature, °F

6.0 Cr-0.5 Mo steel 7

1,100 Temperature, °F

48.3

3(15-10°F) 3

300 4

10 1 22 200 9 10 4 13 8 (240°F) 3,000 9,000 11,000 Scale change

FIG. 1. Operating limits for steel in hydrogen service to avoid decarburization and fissuring.

Metallurgy for hydrogen service. API 941 RP guides

FIG. 2. Hydrogen-service valves typically feature large-radius designs to avoid stress concentrations. In addition to metallurgical considerations, risk reduction for valves in hydrogen service should also consider several other factors. The relative merits of valve design features such as fabricated, forged or cast processes, and rounded vs. angular features must be understood for the best performance. Recent advances provide new hydrogen service leak prevention capabilities with gaskets and packing. Heat-treating and inspection methodologies further reduce risk in hydrogen environments. V-86

VALVES 2012 HydrocarbonProcessing.com

metallurgical selection for hydrogen service in refineries. It summarizes the results of experimental tests and actual data acquired from operating plants to establish practical operating limits for carbon and low-alloy steels in hydrogen service at elevated temperatures. The steel discussed in the RP resists HTHA but not necessarily other corrosives present within a process stream or other metallurgical damage mechanisms. Central to the RP is a set of plots called “operating limits for steel in hydrogen service to avoid decarburization and fissuring,” as shown in Fig. 1. These so-called Nelson curves illustrate the resistance of steel to hydrogen attack at high temperatures and pressure. This plotted data is based on experience gathered since the 1940s. It was originally plotted by G. A. Nelson, using two parameters—operating temperature and partial pressure of hydrogen. It has been updated multiples times with further experience and new steels. In selecting a valve, the end user provides the manufacturer with the correct material specification because the risk is strongly related to the specific process and its characteristics, such as hydrogen concentration, other corrosive stream components and exposure time. Operating pressure and temperature, while generally known to valve manufacturers, are subordinate to these total process considerations. All of these parameters are important to selecting the most suitable material based on the Nelson curves.

Design. The potential for hydrogen attack, embrittlement and blistering can be greatly reduced by various design considerations. A key objective is the reduction or elimination of sharp edges and abrupt angles. Such edges concentrate stress that can accentuate hydrogen embrittlement and cracking. The tapering or thinning of metal at a

VALVES

FIG. 3. Operating limits for steel in hydrogen service to avoid decarburization and fissuring. Source: API. sharp edge also creates stress areas that are more easily invaded and degraded by hydrogen. As a result, large-radius designs that produce a uniform stress typify hydrogen service valves, as shown in Fig. 2. These curves are based on stress calculations for the crotch areas of the valve, using finite-element analysis to avoid peak stress. The forming process is also very important to valve performance. Both casting and forged steel have advantages and disadvantages that should be considered. Welding should be minimized or eliminated; it is one of the most critical points where embrittlement is likely to occur. Casting has no welds and, therefore, offers an advantage. In addition, casting frequently eliminates sharp edges and resulting stress concentrations. Conversely, casting is more prone to defects—such as voids and porosity—and impurities than forged steel. Therefore, if casting is used, the valve usually will undergo nondestructive testing to identify possible defects. Foundries are increasingly applying casting simulations to reduce potential flaws and faults. Zero leakage. Valve leakage occurs through two key paths. Leakage at the seat allows hydrogen to pass when the valve is closed. In this leakage, the gas is contained within the process. The more critical leakage is through the stem, which can result in gas escaping to the atmosphere. Leakage at the seat. To prevent leakage at the seat, metal-to-metal technology is preferred. The technology used in hydrogen service applies a flexible, resilient metal on the disk that seals against a stellite hard-faced seat. The metal-to-metal design provides a durable, hightemperature seal, thus ensuring a leak-proof seal. As mentioned, from an environmental point of view, the most critical leaks occur when the media escapes to the atmosphere, and it is then subject to legal scrutiny. Before addressing that type of leakage, we will briefly mention some regulatory issues.

Regulatory issues. Two applicable laws—the US Clean Air Act (CAA) and the German TA-Luft, address fugitive emissions and specify the acceptable emission limits, particularly volatile organic compounds (VOCs). In addition to these laws, standards and specifications include ISO 15848 1 and 2, Shell MESC 77 – 300/312, and API 622. Most recently, regulations under the CAA affecting US fugitive emissions have been significantly revised. These changes are implemented through an enhanced leak detection and reporting (LDAR) program administered by the US Environmental Protection Agency (EPA). Key provisions of the enhanced LDAR program apply to certification of leaking valves and valve-packing technology. This certification reduces previous emission limits from 10,000 ppm to no more than 100 ppm. API 622 is recognized by the EPA as an industry testing standard applicable to packing materials. The standard specifies the requirements for competitive testing of block-valve stem packing for process applications where fugitive emissions are a consideration. It is, at present, being revised to comply with the enhanced LDAR with changes. Leakage at the stem. Preventing stem leakage entails a number of basic design considerations, including: • Live-loaded packing for temperature variations • Packing to be prevented from rotation • Providing a very efficient shaft seal • Very smooth shaft surface • Ensuring the packing segments are in touch with the stuffing box and the shaft simultaneously • Applying independent PTFE and graphite packing. Two valve components are key to these considerations: the packing and gaskets. Softer graphite, which is typically used for packing and gaskets, is highly effective for leak prevention in many applications. But HYDROCARBON PROCESSING

VALVES 2012

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VALVES

graphite presents a unique problem in hydrogen service. Because the graphite is permeable to the small hydrogen atom, the soft material cannot prevent leakage. Reducing leakage by impregnating graphite with PTFE, a synthetic fluoropolymer, is unacceptable. PTFE can evaporate in a fire with disastrous results.

Gasket technology. Hard-metal gaskets between the body and bonnet are necessary in hydrogen processes. Softer metals are too porous for the application. The harder, nonporous materials have significantly higher operating temperatures exceeding 250°C. However, metal gaskets require more accurate machining. If the body or the gasket is not perfectly round and precisely within tolerances, it will not seal effectively. For this reason, valve bodies must be precisely machined.

Packing technology. As with gaskets, graphite packing material also presents permeability problems. An alternative in low-temperature applications (below 200°C) are packing designs that use O-rings in various rubber compounds or Chevron-type packing to provide leak prevention with multiple seals. However, these materials are not suitable for high-temperature (HT), high-pressure (HP) applications. Under these extreme environments, engineered graphite packing technology provides an effective alternative. The technology uses special graphite packing interposed with metal sheets to minimize gas losses. This design has been factory tested with different valves to check for leakage at pressures corresponding to ANSI classes 600, 1500 and 2500. The tests were carried out under the requirements of Shell’s MESC 77-300/312. Test results showed that recognized losses were lower than those imposed by the specification

for Class “A” tightness in a range between seven to ten times. The packing design, as shown in Fig. 3, consists of: • Top and bottom rings of polyacrylonitrile (PAN) fiber to provide mechanical resistance to pressure • Outer rings of laminated, graphite/steel to provide a barrier to hydrogen molecules • Central graphite rings especially designed for low emissions.

Inspection. Testing and Inspections are critical steps in certifying valves for hydrogen services. Radiographic x-rays and dye-penetration testing are used to check for internal defects, including cracks, hot tears, holes and gas inclusions. The internal volume of the valve is checked to address hydrogen blistering. Manufacturers are increasingly testing fully assembled valves with HP helium to search for leakage. This testing is done on the finished product. Because the helium atom is very close in size to the hydrogen, this testing best simulates operating conditions. Low-pressure testing indicates losses due to leaks and porosity, while the HP testing ensures there is no deformation of sufficient magnitude to cause losses.

Post-weld-heat treatment. For valves in hydrogen service, manufacturers typically prefer PWHT. Industry experience and research indicate that PWHT of 0.5 molybdenum (Mo) and chromium-Mo steels improves resistance to HTHA. The PWHT stabilizes the alloy carbides, which reduces the amount of carbon available to combine with hydrogen. The treatment also reduces residual stresses, making the material more ductile. Manufacturers typically use PWHT for all low-alloy steels while plain carbon steels are only treated at the end-users’ request.

Final thoughts. As refiners use more hydrogen in various process-

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VALVES 2012 HydrocarbonProcessing.com

ing, more scrutiny will be applied on valve specifications. Hydrogen service places special demands on valves. The potential for corrosion, HTHA, embrittlement and blistering presents operational, safety and environmental considerations. In addition, government regulations limiting fugitive emissions set strict standards regarding valve performance. Due to these issues, multiple factors must be considered when specifying valves for hydrogen service and include: • Metallurgy selected through API and/or company specifications • Forming process, i.e., casting vs. welding • Design features to avoid susceptibility to embrittlement, etc. • Gasket/packing design and material selection • A robust inspection process. HP ACKNOWLEDGMENT An upgraded and revised presentation from the AFPM Annual Meeting, San Diego, California, March 11-13, 2012. LITERATURE CITED 1

Freedonia, 2010, World Hydrogen Industry Study with Forecasts for 2013 and 2018: http://www.freedoniagroup.com/brochure/26xx/2605smwe.pdf. 2 Avery, M., B. Chui, Y. Kariya and K. Larson, “Hydrogen-induced corrosion,” Materials Science 112 Group Research Paper, March 12, 2001. http://www. mavery.com/academic/Hydrogen_Corrosion_Report.pdf. 3 API Recommended Practice 941, Seventh Ed., “Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and Petrochemical Plants,” August 2008.

Tito Sequeira is the global marketing manager for refining at Tyco Flow Control. He is responsible for the strategy and marketing mix required to serve the global refining market. He has experience in product management and industry marketing manager for power, refining and petrochemical. He has provided strategic leadership to pursue business opportunities into refining for different valve and control leading manufacturers. Mr. Sequeira holds a BS degree in industrial engineering from the Monterrey Institute of Technology in Mexico and an MBA from Yale University. He has five years of experience in the valve industry.

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KNOWLEDGEABLE SERVICE Chesterton, in partnership with our distributors, provides world-class customer service. Our factory-trained specialists and technicians work closely with customers to select the programs, products and services to meet the challenges faced by industry. Specialists and technicians are supported by Chesterton’s Application Engineering, Customer Service and Engineered Solutions Teams. Our mission is to be the hands-on expert partner to increase our customers’ reliability and productivity and to enhance their business performance and competitive advantage.

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Scan this QR code* to learn more about the new low-power valves. * Requires QR code reader.

The best of both worlds. Introducing new low-power valves from ASCO. Our solenoid valves are now available with the worldbeating reliability you expect, but at the lowest power rating everâ&#x20AC;&#x201D;only 0.55 watt! So you can install more devices on a process plant bus network. Or use them in remote locations with solar/battery sources. And unlike integrated valves, you can choose from a wide range of easily available models, with larger orifices to handle higher flows without clogging. Many ASCO low-power solenoid valves come with the ASCO Today same-day shipping program for the fastest delivery on the planet. Select 64 at www.HydrocarbonProcessing.com/RS

The ASCO trademark is registered in the U.S. and other countries. The Emerson logo is a trademark and service mark of Emerson Electric Co. ÂŠ 2011 ASCO Valve, Inc.

800-972-ASCO (2726) | www.ascovalve.com/LowPower | e-mail: info-valve@asco.com

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HOW NEW LOW-POWER SOLENOID VALVE TECHNOLOGY CHANGES THE GAME Process plants worldwide often place considerable reliance on lowpower solenoid valves. They are used as pilot valves to open and close larger ball or butterfly valves, or on control valves (installed between positioner and actuator) for fail-safe air release if there’s a loss of power. A new generation of even lower-power valves is now changing the rules of the power consumption game for project specifiers in the refining, upstream oil and gas, chemical, pharmaceutical and life sciences, food and beverage, and power industries. However, not all low-powered valves are created equal.

HOW LOW CAN THEY GO? The first truly low-power solenoid valves were intrinsically safe designs debuting in the mid-1980s. They reduced power draw to about 0.5 watt. However, they were difficult to manufacture and featured low flow and pressure ratings. By about 1995, their performance was improved by the introduction of a higher-flow, higher-pressure rating cartridge-type valve that delivered acceptable performance at around a 1.5-watt rating. Lately, efforts toward even greater efficiency and energy conservation have produced designs again approaching the magic half-watt mark, with the newest generation of truly low-power solenoid valves rated at 0.5 to 0.75 watt.

I/O, and plant real estate) than for the valve itself. Solenoid valves configured around the emerging half-watt standard can reduce these costs. Their lower current draw eliminates the need for additional power isolation relays. They permit the use of smaller, less expensive wiring gauges and allow the use of downsized, less costly power supplies.

THE TROUBLE WITH INTEGRATION Many OEM designers and end users have gravitated toward socalled “integrated” solutions. These feature a low-power solenoid valve built into a position indicator as a single unit. Unfortunately, they suffer some glaring disadvantages. First, their “black box” nature makes them difficult to stock, troubleshoot, and maintain. In fact, maintenance staff may simply discard the entire package and buy a new unit at the first sign of trouble. Additionally, manufacturers don’t always offer a full range of these valves as integrated solutions. That means buyers can’t standardize on and stock a single valve part number with characteristics sufficient to accommodate all of a plant’s applications.

THE ADVANTAGES OF TAKING THE BUS Plants considering retrofits or new construction can take advantage of the automation benefits of bus networks to find even greater utility with new low-power valves. Experience shows that ASCO valves arranged on an optimized DeviceNet or ASI bus can cut material and labor costs alone by close to 50%! Greater efficiency and “fit” can also be achieved. For DeviceNet, ASI, and other bus network applications in which input and output devices are powered directly from the network, new low-power valves may require only a third the current of their predecessors. So replacing older 1.5-watt-plus valves on a DeviceNet bus with ASCO’s highly reliable models at around 0.5 watt can allow users to fit more valves.

CLOGGING AND OTHER STICKY QUESTIONS OEMs and users alike report that integrated solutions—and in fact some non-integrated, separately available valves—may suffer from reliability issues such as clogging. These issues represent a serious threat. In many industries, the larger process valves that these small pilot valves control may remain in the same position for days, weeks, or even months. Yet when required, the valves must operate with unfailing reliability or result in serious consequences for process integrity and safety. When redesigning a valve to use less power, there also can be tradeoffs that cause a “performance hit.” These may involve decreases in orifice size and maximum allowable pressure. However, in top-ranked ASCO valves that are designed with generous parameters from the start, performance decreases are negligible. And lower power consumption means less heat for longer life of coils and power supplies.

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REMOTE POSSIBILITIES The new low-power solenoid valve models also present fresh opportunities for process control systems in remote locations such as oil pipelines and remote gas extraction stations. Designers of remote installations can choose from different savings paths. The lower power drain of the new valves can allow the system to be specified with a smaller battery bank. Alternatively, designers may hold batteries to the same size, but rely on decreased power consumption to optimize the system for longer operation without sunlight.

CONCLUSION Choosing low-power solenoid valves for process industry applications presents several challenges. Fortunately, the newest generation of valves offers candidates that combine low power with reliable performance to suit more applications than ever before. For more information contact ASCO at 1-800-972-2726 or infovalve@asco.com. HYDROCARBON PROCESSING

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HOW ONIS BLINDS WORK For all Onis Line Blinds, the pipe separation is performed the exact same as spreading pipes preparing to swing a figure-8. With an Onis Blind, the effort by the operator is minimal, to move a great deal of weight (any pipe) a very small distance to move the slide. The pipe must be depressurized, as the Onis Blind is not a valve. A lever (or a gearbox, depending on size/pressure/ temperature) is turned, and the forged Onis bodies are separated and the pipe is spread. The slide is moved on rollers from the full-bore to blinded position. The lever (or gearbox) is closed to recompress the bodies.

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Increase production time Reduce plant maintenance costs Operators can blind lines anytime Improve safety by reducing exposure time Reduce emissions during blinding Gaskets can be changed outside of process Zero tools or cranes needed to blind Can be automated (operated from control room)

PRODUCT RANGE: • • • • • •

Sizes: ½” to 50” 150# to 2500# Flanges Pressure: Vacuum to 6100 psig Temperature: –152°F to 1,400°F Onis FCCU Blinds, Onis Quick Filter, and Twin Onis Blinds Onis Blinds are custom built to customers’ requirements: ASME Section VIII Div-1, B 16.5, B16.48, B31.3, NACE, API-607

Onis Line Blind 10” 150# heater isolation, Operating Company, Washington, USA

ONIS SPECIFICS Onis Blinds physically spread the pipe. There are only 4 gaskets on the slide and zero internal (backseat) gaskets or moving parts that are hard to change in the field. The advantage of this feature is that all gaskets can be inspected, and changed if needed, without opening the line. For example, a few days before operators need to blind a line, anyone can easily inspect the gaskets, and if they need replacing, the gaskets can be removed and replaced while the production line is still in operation. For Dangerous mediums there is no need to use additional PPE while replacing gaskets. When the line is blinded, the full-bore gaskets are accessible and available to easily change and provide a new seat when the line is returned to service. All Onis moving parts are outside of the process, and there is no reduction of flow from the pipe and no place for product build-up. Additionally, all Onis Blinds have slide covers, grease fittings (to ensure bushing longevity), and lock-out/ tag-out latches. The bodies of Onis blinds are made from solid forgings and are not welded flanges. Onis blinds can be built for hydrotesting additional when specified by the customer. Onis offers manufacturers one year warranty (additional upon request). Installation support and on-site training for operators and maintenance personnel are available. Thank you for considering Onis Line Blinds.

WHERE ONIS BLINDS ARE USED Onis Blinds are currently used in refineries, chemical plants, pipelines, and compression stations. The Onis Blind can be used in any service (i.e. H2S, Nitrogen, Decoke/Feed lines, diesel, natural gas, benzine, chlorine, HCN, and more). Onis Blinds can be used to isolate reactors, heaters, pumps, compressors, and furnaces. Onis Blinds are used in offshore applications and their minimal operation time offer-many advantages.

WHO USES ONIS BLINDS Onis Blinds are currently used by ExxonMobil, Shell, BP, ConocoPhillips, Petrobras, Pemex, General Electric, DuPont, LyondellBasell, Certianteed, Dow, Total, Chevron, Honeywell, PetroChina, and BASF (and many more). SPONSORED CONTENT

Line Blinds CONTACT INFORMATION Onis Inc., One Riverway, Suite 1700, Houston, Texas, 77056 Phone: 713-840-6377, Fax: 832-201-7767 Email: sales@onislineblind.com Website: www.onislineblind.com Corporate Headquarters and Manufacturing: Onis France 1 Avenue Fernand Julien, ZI de Berthoire, 13410 Lambesc France Phone: 33 (0) 4 42 92 93 20, Fax: 33 (0) 4 42 92 73 52 Email: onis@onis.fr HYDROCARBON PROCESSING

VALVES 2012

V-93

Think Environmental Protection. Think Cashco Vapor Control. The full line of Vapor Control System from Valve Concepts has established the industry standard for engineered quality and in-field adaptability. The engineered modular design enables us to reduce capital outlay costs from 33% to 66% depending on the model.

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Hydrocarbon Processing’s International Reﬁning and Petrochemical Conference is a market-leading technical conference, providing an elite forum in which industry leaders will share knowledge and ideas relating to the latest technological advancements and trends in the reﬁning and petrochemical industries.

Attendees of IRPC will have the opportunity to: • Engage international hydrocarbon processing industry HPI leaders representing a range of operating and technology companies • Experience a dual-track conference program put together by IRPC’s esteemed advisory board led by IRPC Advisory Board Chair, Giacomo Rispoli of eni Refining & Marketing • Benefit from various networking opportunities with HPI leaders between technical sessions • Take part in an exclusive tour of the EST Project at eni’s Sannazzaro de’ Burgondi Refinery

Make Your Plans to Attend To reserve your spot at the conference, please visit www.HPIRPC.com or contact Gwen Hood, Events Manager, Gulf Publishing Company, at +1 (713) 520-4402 or Gwen.Hood@Gulfpub.com

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Visit our website at HydrocarbonProcessing.com HYDROCARBON PROCESSING JUNE 2012

I 97

HPI MARKETPLACE SALES OFFICES—EUROPE

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REPRINTS Rhona Brown, Foster Printing Service Phone: +1 (866) 879-9144 ext. 194 E-mail: RhondaB@FosterPrinting.com

Marketing, Inside Out Marketing in the Oilﬁeld 2012 will provide you with the tools necessary to maximize your marketing efforts in the oil and gas industry. Expert speakers in an array of topic-focused sessions will offer you guidance and insight that will enable you to effectively plan your marketing strategy for 2012 and beyond.

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FREE Product and Service Information—JUNE 2012 HOW TO USE THE INDEX: The FIRST NUMBER after the company name is the page on which an advertisement appears. The SECOND NUMBER, appearing in parentheses, after the company name, is the READER SERVICE NUMBER. There are several ways readers can obtain information: 1. The quickest way to request information from an advertiser or about an editorial item is to go to www.HydrocarbonProcessing.com/RS. If you follow the instructions on the screen your request will be forwarded for immediate action. 2. Go online to the advertiser's Website listed below. 3. Circle the Reader Service Number below and fax this page to +1 (416) 620-9790. Include your name, company, complete address, phone number, fax number and e-mail address, and check the box on the right for your division of industry and job title. Name ________________________________________________________

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

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

ADVERTISERS in this issue of HYDROCARBON PROCESSING Company Website

Page

RS#

Aggreko . . . . . . . . . . . . . . . . . . . . . . 71 (168) www.info.hotims.com/41429-168 www.info.hotims.com/41429-154

64 (53)

Bently Pressurized Bearing Co . . . . . . 52 (165) www.info.hotims.com/41429-165

BIC Alliance. . . . . . . . . . . . . . . . . . . . 30 (158) www.info.hotims.com/41429-158

(79)

www.info.hotims.com/41429-79

Cameron . . . . . . . . . . . . . . . . . . . . . . 35

(55)

www.info.hotims.com/41429-55

Cashco, Inc . . . . . . . . . . . . . . . . . . .V-94

62 (58)

www.info.hotims.com/41429-58

Chemstations Inc. . . . . . . . . . . . . . . . 32 (160) www.info.hotims.com/41429-160

Chesterton . . . . . . . . . . . . . . . . . . .V-89 (171) www.info.hotims.com/41429-171

Chromalox . . . . . . . . . . . . . . . . . . . . 54

(96)

www.info.hotims.com/41429-96

Colfax Americas . . . . . . . . . . . . . . . . 12

(86)

www.info.hotims.com/41429-86

(65)

NACE International . . . . . . . . . . . . . . 64

(54)

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

www.info.hotims.com/41429-54

(93)

FourQuest Energy . . . . . . . . . . . . . . . 44 (162)

(70)

www.info.hotims.com/41429-70

Greene, Tweed . . . . . . . . . . . . . . . . . . 2

(82)

www.info.hotims.com/41429-82

www.info.hotims.com/41429-156

Samson GmbH . . . . . . . . . . . . . . . . . 45 (163) www.info.hotims.com/41429-163

T.D. Williamson . . . . . . . . . . . . . . . . . . 8

www.info.hotims.com/41429-151

HPI Marketplace . . . . . . . . . . . . 96–97

Team Industrial Services. . . . . . . . . . . 25

Hoerbiger . . . . . . . . . . . . . . . . . . 28–29 (157) www.info.hotims.com/41429-157

I JUNE 2012 HydrocarbonProcessing.com

(75)

www.info.hotims.com/41429-75

Trachte USA . . . . . . . . . . . . . . . . . . . 82 (170)

HTRI . . . . . . . . . . . . . . . . . . . . . . . . . 23 (155)

www.info.hotims.com/41429-170

www.info.hotims.com/41429-155

Turbomachinery Laboratory . . . . . . . . 99

HYTORC . . . . . . . . . . . . . . . . . . . . . . 43 (161)

Unifrax . . . . . . . . . . . . . . . . . . . . . . . 58

www.info.hotims.com/41429-161

(68)

www.info.hotims.com/41429-68

URS Corp . . . . . . . . . . . . . . . . . . . . . 67 (167) www.info.hotims.com/41429-167

(85)

www.info.hotims.com/41429-85

Winsted Corporation . . . . . . . . . . . . . 53 (166) www.info.hotims.com/41429-166

(84)

www.info.hotims.com/41429-84

Wood Group Mustang . . . . . . . . . . . . 50

(90)

www.info.hotims.com/41429-90

www.info.hotims.com/41429-159

Worley Parsons . . . . . . . . . . . . . . . . . 19 (153) www.info.hotims.com/41429-153

(91)

MSA . . . . . . . . . . . . . . . . . . . . . . . . . 18 (152)

Yokogawa . . . . . . . . . . . . . . . . . . . . . 26

(67)

www.info.hotims.com/41429-67

Zyme-Flow Decon Technology . . . . . . 72 www.info.hotims.com/41429-92

For information about subscribing to HYDROCARBON PROCESSING, please visit www.HydrocarbonProcessing.com 100

(95)

www.info.hotims.com/41429-95

Tiger Tower Services . . . . . . . . . . . . . 46 (88)

www.info.hotims.com/41429-88

www.info.hotims.com/41429-152

(80)

Total Automation Solutions, Curtiss Wright Flow Control Company . . . . . . . . . . . 4 (151)

Gulf Research . . . . . . . . . . . . . . . .V-88

Linde Process Plants . . . . . . . . . . . . . 33

(66)

www.info.hotims.com/41429-80

Events—MITO. . . . . . . . . . . . . . . . . 98

www.info.hotims.com/41429-91

(63)

Quest Integrity Group LLC . . . . . . . . . 24 (156)

www.info.hotims.com/41429-66

Events—IRPC . . . . . . . . . . . . . . . . . 95

Milliken Workwear . . . . . . . . . . . . . . 14

www.info.hotims.com/41429-169

ONS . . . . . . . . . . . . . . . . . . . . . . . . 103

Spraying Systems Co . . . . . . . . . . . . . . 6

Gulf Publishing Company

Howden . . . . . . . . . . . . . . . . . . . . . 18A

(98)

PCC Energy Group. . . . . . . . . . . . . . 66A

Gastech . . . . . . . . . . . . . . . . . . . . . 101 GE Measurement & Control . . . . . . . 39

ONIS . . . . . . . . . . . . . . . . . . . . . . .V-92 www.info.hotims.com/41429-98

Microtherm . . . . . . . . . . . . . . . . . . . . 31 (159)

Dresser-Rand. . . . . . . . . . . . . . . . . . . 82 (169)

www.info.hotims.com/41429-63

(72)

Merichem Company . . . . . . . . . . . . 136 (61)

www.info.hotims.com/41429-61

Emerson Process Management (Delta V) . . . . . . . . . . . . . . . . . . . . . 20

ENI SpA . . . . . . . . . . . . . . . . . . . . . . 79

www.info.hotims.com/41429-164

www.info.hotims.com/41429-65

DeltaValve, Curtiss Wright Flow Control Company . . . . . . . . .V-84

RS#

LAR Process Analysers . . . . . . . . . . . . 49 (164)

Construction Boxscore . . . . . . . . . . . . 34 Costacurta SpA Vico . . . . . . . . . . . . 18A

Page

Events—WGLC . . . . . . . . . . . . . . . 18B

www.info.hotims.com/41429-62

CB&I . . . . . . . . . . . . . . . . . . . . . . . . . 16

Company Website

www.info.hotims.com/41429-162

www.info.hotims.com/41429-53

Burckhardt Compression Ag . . . . . . . 11

RS#

www.info.hotims.com/41429-93

www.info.hotims.com/41429-64

Axens . . . . . . . . . . . . . . . . . . . . . . . 104

Page

www.info.hotims.com/41429-72

Ametek Process Instruments . . . . . . . 22 (154) ASCO . . . . . . . . . . . . . . . . . . . . . . .V-90

Company Website

(92)

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

Avoid failures in water projects: Part 1 Your company is planning an expansion—building a new process unit or constructing an entire new plant. Regardless of the scope, the facility staff will specify project requirements, complete the process design, and, ultimately, operate and maintain the equipment. As the project takes shape, project engineers will talk with process engineers about the facility’s water systems. But project engineers and process engineers have different responsibilities, and sometimes they don’t speak the same language. Bridging the gap. Here are some ways to bridge the gap between these two groups: Define the design basis. In water treatment, the design basis describes the range of sustained operating conditions; these are not startup, shutdown or transient conditions. The design basis should include: • “Worst case” raw water quality; it should reflect seasonal, drought and flood conditions • Range of flowrates, pressures and water temperatures throughout the pretreatment system • Predicted effluent quality from each pretreatment unit that reflect the effects of aging of consumables, e.g., the projected permeate quality from three-year-old reverse osmosis (RO) membranes (per the manufacturer’s specification). The best information sources to construct the design basis are plant personnel who have experience operating the utility water systems. Current and former utility process engineers and service representatives from the water-treatment vendor can also provide good information. The water authority for the local watershed, or the industrial or potable water supply, is an excellent source of historical raw water quality. For example, the Delaware River Basin Authority, a joint state agency, maintains a historical record of selected water quality parameters from numerous monitoring sites on its website. Obtaining water quality information for well water is more difficult. Your water-treatment supplier may have information from wells at nearby plants that can serve as a first approximation for your design basis. Understand the total cost of ownership. Project engineers are responsible for accurately estimating the capital costs for equipment. But typically they do not evaluate or assign a relative ranking for the operating cost or complexity. Process engineers can assist with the qualitative analysis of the cost and site-specific complexity. A good example is choosing between a batch-process technology (ion exchange) and a continuous-process technology (RO) to meet varying demands for treated water. Ion-exchange units operate in a “batch mode” and require frequent idle time for regeneration. Conversely, RO units must run continuously for reliable operation. Choosing RO units for a highly variable 102

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flow demand requires either a treated-water storage tank with a sufficiently large working capacity or a complex operating scheme to sequence units for in-service and idle conditions. Idling RO units is not a best practices, it irreversibly compromises the performance and service life of the membranes. Properly analyze trade-offs. Selection of alternative technologies always involves a judgment of intangible attributes. For example, cold-lime softening creates a larger waste stream than polymer clarification, but the reduction in total hardness in cold-lime-softened water has benefits: smaller downstream ion-exchange equipment and/or a reduction of wastewater (concentrate) from the downstream RO unit. Project engineers should identify and analyze cases for several alternative technologies to understand these trade-offs. Don’t forget about integration issues. Project engineers in existing plants sometimes focus too narrowly on the plot plan—how to fit the new equipment into an existing facility, ignoring other issues such as integration of controls, dual-train operating considerations, and man-machine interface issues. For example, installing a cold-lime softener in parallel with a polymer clarifier and mixing their effluent streams will require pretreatment of the lime-softened water with acid or carbon dioxide prior to mixing to prevent scaling of the blended-water transfer line from post-precipitation.1 Environmental issues. Most environmental issues create constraints for production and wastewater quality; however, occasionally, there are exceptions. Some plants on the lower Mississippi River are allowed to discharge blowdown from cold-lime softeners directly into their outfall to the river, eliminating the cost and constraint of managing this waste stream and changing the balance of trade-offs with alternative technologies. Next month. The discussion continues. Project and process

engineerings vet operability issues and new technology before finalizing a water treatment system designs. HP 1

NOTE Post-precipitation is the result of excess lime reacting with the calcium hardness and precipitating calcium carbonate in situ.

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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