HP_2011_12 by androsov.info

DECEMBER 2011

2012 HPI FORECAST

SPECIALREPORT

TECHNOLOGY

Spending to increase for global refining, petrochemical and LNG industries

PLANT DESIGN AND ENGINEERING

Improve repair of corroded towers

Fresh and innovative approaches ensure successful projects

Update on water service providers

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DECEMBER 2011 • VOL. 90 NO. 12 www.HydrocarbonProcessing.com

SPECIAL REPORT: PLANT DESIGN AND ENGINEERING

35 41 43 51 59 63

Optimize capacity for large ethylene oxide reactors Many factors must be considered in fine-tuning unit design B. Crudge, B. Billig and R. Schneider

Selecting the right steam methane reformer: Can vs. box design Simulating various configurations and cost estimates aids in the selection of a steam methane reformer for hydrogen production W. Schoerner, G. Shahani and N. Musich

Investment roadmap: Planning for carbon capture and storage Reducing emissions can be approached the same way as any other new capital project S. Ferguson

Cover Photo courtesy of Bechtel.

HPIMPACT 15

US investment in GHG mitigation technologies

US welding equipment demand to exceed $7 billion

Saudi petrochemical executives host meeting with senior Chinese official

Knowledge transfer: A primer for major capital projects Improve transfer strategy across the project supply chain to achieve smooth end-user takeover A. Magarini, A. Altamura and R. Robertson

Manage risks with dividing-wall column installations A simple auxiliary configuration and an extensive modeling study can mitigate the implementation risks of DWCs J. Shin, S. Lee, J. Lee and M. Lee

Preserving knowledge: Keys to effective lifecycle management Plant information resides in many locations throughout the facility; capturing it is a challenge J. Lippin

HPI 2012 FORECAST

MAINTENANCE AND CORROSION

Consider these guides for stress relieving of vertical towers This case history investigates all required post-weld heat treatment for an existing column H. Ayari, D. Truong and K. T. Truong

PLANT SAFETY AND ENVIRONMENT

This summary reviews spending for the global HPI. Will 2012 be a better year for the refining, petrochemical and natural gas industries? What lies ahead for the energy industry?

Proper relief-valve sizing requires equation mastery These simple and rigorous critical-flow equations will help stem the tide of potential catastrophic failures J. S. Kim, H. J. Dunsheath and N. R. Singh

ROTATING EQUIPMENT

Enhancing pump design How modern tools accentuate pump performance S. Krueger, M. Cropper and J. Parker

WATER TREATMENT DEVELOPMENTS

HPI Market Data 2012 Executive Summary:

Onsite water services help refinery go from idle to online

COLUMNS 9

HPIN RELIABILITY Spare parts availability and the need for non-OEM options

HPINTEGRATION STRATEGIES Asset-intensive organizations require good asset information management

HPIN AUTOMATION SAFETY Safety equipment qualification

Assistance enables quick return to profitable production levels C. McCloskey

DEPARTMENTS 7 HPIN BRIEF • 25 HPIN INNOVATIONS • 29 HPIN CONSTRUCTION 33 HPI CONSTRUCTION BOXSCORE UPDATE 86 HPI MARKETPLACE • 89 ADVERTISER INDEX

HP ONLINE EXCLUSIVES HPIN ASSOCIATIONS The inside scoop from NPRA’s technology forum

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Because Hydrocarbon Processing is edited specifically to be of greatest value to people working in this specialized business, subscriptions are restricted to those engaged in the hydrocarbon processing industry, or service and supply company personnel connected thereto. Hydrocarbon Processing is indexed by Applied Science & Technology Index, by Chemical Abstracts and by Engineering Index Inc. Microfilm copies available through University Microfilms, International, Ann Arbor, Mich. The full text of Hydrocarbon Processing is also available in electronic versions of the Business Periodicals Index.

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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 European Editor Tim Lloyd Wright Contributing Editor Loraine A. Huchler Contributing Editor William M. Goble Contributing Editor Y. Zak Friedman Contributing Editor ARC Advisory Group

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 © 2011 by Gulf Publishing Co. All rights reserved. Permission is granted by the copyright owner to libraries and others registered with the Copyright Clearance Center (CCC) to photocopy any articles herein for the base fee of $3 per copy per page. Payment should be sent directly to the CCC, 21 Congress St., Salem, Mass. 01970. Copying for other than personal or internal reference use without express permission is prohibited. Requests for special permission or bulk orders should be addressed to the Editor. ISSN 0018-8190/01.

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HPIN BRIEF BILLY THINNES, TECHNICAL EDITOR

BT@HydrocarbonProcessing.com

Technip has signed a strategic partnership agreement for innovation and technology development with the French Alternative Energies and Atomic Energy Commission (CEA). Located in Paris and Grenoble, France, the technological research division at CEA gives Technip access to over 4,500 researchers focused on the development of new technologies in the fields of energy, transport, health, information and communication. Technip aims to harness and develop this knowledge to increase the competitiveness of its core businesses and to expand and differentiate its business footprint through new technologies. The agreement is valid for an initial period of three years.

Germany’s decision to phase out nuclear power in light of the Fukushima nuclear disaster in Japan has underlined the European country’s need for more gas supplies. It has also boosted interest in the planned Nabucco gas pipeline, which would transport gas 4,000 km between Turkey and Austria. However, a final decision on the Nabucco project will not be made until the end of next year, meaning that construction would not start before 2013 and the project would not be completed until late 2017. Nabucco Gas Pipeline International GmbH will hold an open season in the first half of 2012 to determine the requirements of European gas importers. Over the long term, Nabucco expects up to 20 billion cubic meters of gas from Azerbaijan to feed the pipeline.

Risk-management services firm DNV recently issued the world’s first certificate of fitness for a carbon-dioxide (CO2) storage development plan to Shell’s Quest carbon capture and storage (CCS) project in Canada. The proposed Quest project will capture and permanently store underground more than one million tpy of CO2 from its Scotford upgrader near Fort Saskatchewan, Alberta. Based on the conclusions of an expert panel, DNV certified that Shell’s storage development plan is worthy of certification based upon a number of different metrics, such as sufficient storage capacity; long-term containment; proper risk-management plans; and a measurement, monitoring and verification program capable of continuously demonstrating containment.

Foster Wheeler’s Global Power Group subsidiary has entered into a 20-year agreement with Essar Projects India Ltd. (EPIL) to provide a technology license for utility-sized circulating fluidized-bed (CFB) steam generators to be sold in India. “EPIL believes that CFB technology is the future for the Indian market given the constrained fuel supply situation and the ever-increasing environmental concerns,” said Alwyn Bowden, CEO of Essar Projects.

Enterprise Products’ $1.5 billion, 270-mile Acadian Haynesville Extension pipeline officially began commercial service in early November. With the completion of the project, producers in Louisiana’s prolific Haynesville/Bossier Shale play will have access to 1.8 billion bcf/d of incremental takeaway capacity. By increasing the system’s currently installed 74,000 horsepower of compression, capacity could be increased to 2.1 bcf/d, the company said. The project is supported by long-term, firm contracts with shippers totaling 1.6 bcf/d.

In side-by-side performance, durability and emissions testing of small engines, gasoline blended with isobutanol performed better than blends using ethanol, according to new research from renewable chemicals and advanced biofuels firm Gevo. Gevo said it provided the isobutanol to the Outdoor Power Equipment Institute (OPEI) and Briggs & Stratton (B&S), which tested both fuel blends in B&S small engines. The results demonstrated that, unlike ethanol, blends incorporating isobutanol do not cause any irregular or unstable engine or performance issues. The outcome suggests that isobutanol blends at 12.5% could ease the pressure on moving to higher ethanol blends to meet biofuel mandates with no impact on small engines. Isobutanol is a drop-in fuel that requires no flex-fuel engines, special blender pumps or pipelines. HP

■ BP fined $50 million BP has agreed to pay $50 million to the state of Texas to resolve air pollution allegations related to the March 2005 explosion at its Texas City refinery, according to a statement from Texas Attorney General Greg Abbott. “The proposed agreement resolves the state’s enforcement actions against BP for unlawful pollutant emissions at its Texas City refinery,” Mr. Abbott said. “The proposed agreement reflects the state’s commitment to protecting air quality and holding polluters accountable for illegal emissions.” According to the office’s 2009 enforcement action, BP was responsible for 72 separate pollutant emissions that have been occurring every few months since March 2005. An explosion and related fires erupted at BP’s Texas City refinery in March 2005, claiming 15 lives and injuring more than 170 workers. The state’s 2009 legal action against BP stemmed from a referral from the Texas Commission on Environmental Quality, which regulates and permits emissions at Texas refineries. After the Attorney General’s office filed its original legal action against BP, the TCEQ submitted a second, related referral against BP. According to TCEQ investigators, multiple Texas Clean Air Act violations occurred at the Texas City refinery between April 6 and May 16 of 2010. As a result, the Attorney General’s office filed a second enforcement action and charged BP with illegally emitting approximately 500,000 pounds of harmful air pollutants in Texas City. Under the proposed agreement, BP is required to pay $50 million to the state of Texas. That amount includes $500,000 in costs that the Attorney General’s office incurred while pursuing the state’s enforcement actions. The remainder of the $50 million reflects civil penalties that will be deposited in the state treasury. Aside from this settlement, BP has already paid more than $100 million in fines to US safety and environmental regulators, and up to $2.1 billion to settle civil accident claims related to the explosion. HP HYDROCARBON PROCESSING DECEMBER 2011

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

Spare parts availability and the need for non-OEM options Reliability engineers and their associated job functions often try hard to make their responsible supply-chain staff or purchasing departments understand that it is impossible for the maintenance department to plan, or accurately predict, spare parts demand. The reason is that a major proportion of equipment and systems fail randomly. A good example would be rolling element bearings in all industries worldwide. According to bearing manufacturers’ statistics, 91% fail before they reach the end of their conservatively estimated design lives, and only 9% reach the end of design life. The millions that prematurely fail every year can all be slotted in one or more of the seven basic failure categories: 1) operator error, 2) design oversights, 3) maintenance mistake, 4) fabrication/processing defect, 5) assembly/installation error, 6)material defects and 7) operation under unintended conditions. Experience clearly shows a preponderance of failures that could be avoided, but will continue to persist because of human error. That is also the reason for the randomness in which they occur. There is generally neither the investment in education, personnel, tools, time, or systematic grooming of a culture of knowledge and loyalty. The latter two would be needed to reduce failure frequencies and to improve the predictability of failures. Large-scale investments have been made in predictive maintenance devices and tools that are then sitting idle or cannot be used because plant staff members have not been trained, mentored or taught to interpret reams of data. A good example would be the many computerized maintenance management systems (CMMS) which to this day, are being fed useless information such as “bearing replaced,” “bearing failed” and “bearing repaired,” instead of “bearing failed because loose flinger ring abraded and brass chips contaminated the lube oil. Corrections made by upgrading to a clamped-on flinger disc.” Of course, the prerequisite is for the facility to practice failure analysis and take remedial action, instead of merely replacing parts. People in authority make frightfully wrong decisions. As an example, they legislate to standardize on just one type of lubricant, or to buy critically important machinery and components from the lowest bidder, or to procure replacement parts without linking them to a well thought-out specification, or to allow parts to be stocked without first thoroughly inspecting them for dimensional and material-related accuracy or specification compliance.

parts predictions determined from mathematical models are generally too far off to merit intelligent discourse. Instead, reasonable specifics are a function of equipment type, geographic location, skill levels of workforce members, etc. For decades, it has been understood that relevant answers require auditing or reviewing a particular local situation. Some years ago, one of our books or articles gave the following statistics for oil and petrochemical plants: a) 25% of all failures are preventable but not prevented b) 15% of all failures are predictable but not predicted c) 20% of all failures are predicted but not acted upon to undertake repair d) 25% of all failures are predicted and machines stopped to do repairs e) 15% of all failures are neither preventable nor predictable. Taking into consideration that these statistics were generated about 15 years ago, and also realizing that certain advancements have been made since the early 1990s, we were recently asked if an update would be available. It was pointed out that new

Random failures demand ready availability of good options. Because of the randomness of failures in hydrocarbon

processing industry (HPI) plants that are not adhering to true best-of-class concepts, it is necessary to have certain parts in stock. We know that some theoreticians extrapolate widely from data that apply to predictable wear-out failures. However, what transpires in HPI facilities is a function of numerous variables, most of which have lots to do with human error. And so, spare

FIG. 1

Informative bulletins inform us of non-OEM capabilities for rapid repairs. HYDROCARBON PROCESSING DECEMBER 2011

HPIN RELIABILITY and more powerful predictive technology, perhaps more precise diagnostics, and more (or sometimes less) reliable equipment and parts might have caused a shift in these percentages. If so, what are the new numbers? After reflecting on the issue, we believe some of today’s probable statistics are still close to the ones published 15 years ago. However, some definitions or updated numbers may be helpful. a) 25% of all failures are preventable but not prevented because of an arbitrary decision that is simply not rooted in knowledge and experience. Example: “Use the cheap oil” may overlook the fact that the cheap oil lacked demulsifiers or antifoaming agents, etc. b) 15% of all failures are predictable but not predicted. Example: The random appearance of “black oil” is attributable to O-ring degradation of a certain style of bearing protector seal. The bearings will soon fail, but nobody has read the books and articles that describe the occurrence. The occurrence should be linked to a certain risky design feature on a widely used product.1 c) 20% of all failures are predicted but not stopped to undertake repair. Chances are someone in authority overruled an expert who asked for a shutdown when vibration increased beyond a safe level. d) 25% of all failures are predicted and equipment is shut down for repair. Good; everybody is happy. Unfortunately, the organization’s energy is funneled into restorative maintenance efforts instead of proactive upgrade efforts that would prevent failures in the first place. We believe prevention is better than spending money for restoration.

e) Only 1% of all failures are neither preventable nor predictable. As of 2010, we changed our minds and no longer believe the old 15% figure was correct. Human beings make the decision to build cities in earthquake zones—either with suitable building codes, or by disregarding such codes. Strong levies can be built or not built, maintained or not maintained. But, yes, some machines might fail because a neighboring pressure vessel exploded or because a fire in another unit spreads. These may indeed fit the “neither preventable nor predictable” 1% category. The remaining 14% belong in the other categories. As to spare parts, our recommendation is to be informed on not only the supply capabilities of original equipment manufacturers (OEMs) but to also becoming familiar with the competence and response times offered by non-OEM vendors. The best of these both repair and systematically upgrade machines during a maintenance event. Being on their mailing list for relevant bulletins (Fig. 1) and understanding their reverse-engineering capabilities will prove even more helpful in cases where spare parts cannot be quickly obtained from the OEM. HP 1

LITERATURE CITED Bloch, H. P., “Getting all the facts is more important than ever,” Hydrocarbon Processing, May 2009, p. 9.

The author is Hydrocarbon Processing’s Reliability/Equipment Editor. A practicing consulting engineer with close to 50 years of applicable experience, he advises process plants worldwide on failure analysis, reliability improvement and maintenance cost avoidance topics. He has authored or co-authored 18 textbooks on machinery reliability improvement and over 490 papers or articles dealing with related subjects.

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HPINTEGRATION STRATEGIES SID SNITKIN, CONTRIBUTING EDITOR SRSnitkin@ARCweb.com

Asset-intensive organizations require good asset information management ARC Advisory Group has written extensively on the important topic of asset information management (AIM). While numerous cultural and organizational issues come into play, technology clearly provides the foundation for every AIM program. It provides the means for organizations to efficiently collect, organize and manage the volumes of drawings, lists, specs, manuals and databases associated with a typical capital asset investment. It also enables organizations to sustain the integrity of this information throughout the asset life cycle with consistent enforcement of proper quality management processes. Finally, it empowers every asset management stakeholder with convenient access to the information he or she needs to work safely, accurately and efficiently. Selecting the right AIM technology is challenging. Assets vary significantly across industries, and organizations have different asset management strategies. This leads to unique AIM requirements in areas like information content, business processes and the stakeholders that must be supported. IT solution providers also have a wide range of perspectives on AIM, creating a diverse landscape of AIM products. To establish a winning AIM technology environment, owner/operators need to clearly understand their needs and the capabilities of different solutions. AIM technology impacts organizational performance, provides metrics for evaluating current AIM capabilities, and offers advice on mapping gaps to functional requirements for new AIM investments.

• Unique technical information forms and formats not supported by conventional information management platforms • Extremely long lifetime and stringent, regulated recordkeeping requirements • Extensive, complex cross referencing between documents and data that must be considered in information quality management processes and user interfaces • The need to support widespread duplication of information across a variety of locally managed applications • Complex handovers of volumes of new and modified information during greenfield and brownfield projects • Many external stakeholders whose use and modification of asset information has to be closely monitored and coordinated with internal quality and security processes. Addressing these kinds of special issues is fundamental to ensuring that the organization always has good asset information. Since conventional information management solutions do not do this, organizations have no choice but to acquire or develop technology that does. At a minimum, organizations should augment their existing information management strategies with certain AIM-specific capabilities. In many cases, it will be wiser to roll out a new, enterprise-wide AIM solution and simultaneously enable the organization to take advantage of industry best practices and new technology developments.

Asset-intensive groups need AIM-specific technology.

Establishing requirements for your AIM technology program. While every asset-intensive organization can benefit

Good asset information enables asset-intensive organizations to optimize the returns from their substantial investments in equipment and facilities. Poor asset information can lead to staggering financial losses and significantly increased risks of environment, health and safety (EH&S) incidents and operational disruptions. The requirements for good asset information are simple and straightforward. It has to be complete, accurate and consistent to avoid confusion and costly mistakes. In addition, it has to be timely, accessible and understandable so people can leverage it for higher efficiency and better decision-making. But achieving these goals is difficult for most organizations, primarily because they lack the right AIM technology. People in the asset management trenches understand the importance of good asset information because they see how poor information impedes their efforts. But management often ignores their calls for AIM improvements, believing mistakenly that existing IT programs and investments already cover AIM. Management doesn’t understand how AIM is different from other information management challenges. While the technology needed for AIM is similar to that used in other information management programs, asset information has certain characteristics that merit special attention by IT organizations. These vary by industry, asset type and organization, but some typical examples include:

from AIM technology, the solutions that each should deploy varies according to factors like industry, asset management strategies and current IT environment. So it is vital that organizations establish a proper set of general requirements upfront to guide their AIM technology decisions. To serve this goal, the organization’s general AIM technology requirements have to address several critical issues. First, the organization needs to communicate the improvements that it expects from its implementation of AIM technologies and how it will benefit. Second, it needs to clearly define the asset information environment that AIM will have to support, in terms of the information to be managed and how this will be used to support asset management processes. Third, it must identify the stakeholders that the AIM environment will support and their needs for special features and tools. Finally, the requirements should explain how AIM will be integrated with the existing IT environment and how existing capabilities are to be leveraged to support AIM. HP The author, vice president at ARC, has over 30 years of experience in automation, information systems, and manufacturing. Dr. Snitkin hold BS and MS degrees in physics from Carnegie Mellon University, and an MBA and PhD in operations research and artificial intelligence from the University of Pittsburgh.

HYDROCARBON PROCESSING DECEMBER 2011

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HPIMPACT BILLY THINNES, TECHNICAL EDITOR

BT@HydrocarbonProcessing.com

According to a study conducted by T2 and Associates on behalf of the American Petroleum Institute, North American investments in greenhouse gas (GHG) mitigating technologies are estimated to have totaled $225 billion between 2000 and 2010 (Fig. 1). Over the 2000–2010 period, the US-based oil and natural gas industry invested an estimated $108 billion in GHG mitigating technologies including shale gas, and $71 billion without shale gas investments, other US-based private industries invested an estimated $74 billion, and the US federal government invested an estimated $43 billion. Major investments by the oil and natural gas industry included shale gas (especially over the 2009–2010 period), efficiency improvements, including combined heat and power, and advanced technology for vehicles. Investments in wind, biofuels and solar were also made. Other private industries’ major investments included advanced technology vehicles, efficiency improvements in electricity generation, biofuels, wind and solar. The US federal government has spread investment across all technology categories with major investments in energy-efficient lighting, wind, solar, biofuels and basic research. It also made significant investments in renewables and efficiency during 2009 and 2010 as part of the American Recovery and Reinvestment Act of 2009 (ARRA).

metric tons equates to 11.2 million cars taken off the roads. For comparison, there are 246 million cars and trucks in the US, according to the US Department of Transportation. Six leading technology investments. The six lead-

ing emission mitigation technologies for private and public sector investment (Fig. 2), as measured by expenditure share, are: advanced technology vehicles, 22% ($49.5 billion); shale gas, 17% ($37.7 billion); other efficiency, 14% ($30.7 billion); ethanol, 8% ($18.4 billion); wind, 8% ($17.4 billion); and combined heat and power, 7% ($16.3 billion.) These top six technologies commanded 76% of the estimated total investments, or $170 billion over the 2000–2010 period in the North American market. All other technologies (including LNG, 6%, fugitive gas reduction, 5% and nuclear, 4%) combined comprised 24% of the estimated total investments. 110 100 90 80 70 60 50 40 30 20 10 0

$ Billion

US investment in GHG mitigation technologies

Oil and natural gas industry

Emission reductions. The EIA has recently reported that

energy-related carbon dioxide emissions in the US in 2010 increased by 213 million metric tons, or 3.9%, compared to 2009. 2010 was preceded by declines in three out of the four previous years. US anthropogenic GHG emissions in 2009 were 5.8% below the 2008 total. The decrease in US CO2 emissions in 2009 resulted primarily from three factors: an economy in recession, a particularly hard-hit energy-intensive industry sector and a large drop in the price of natural gas that caused fuel switching away from coal to natural gas in the electric power sector. While the US economy declined by 2.6% in 2009, a 5.8% decrease in total GHG emissions meant that US GHG intensity improved by 3.3% from 2008 to 2009. In 2010, GDP grew by 3%, but emissions increased by 3.9%, largely as a result of a rebound in coal use for power generation. Since 1990, carbon dioxide emissions in the US have grown much more slowly than GDP; in 2007 emissions reached a peak of about 20% greater than 1990, but even after the 2010 increase, carbon dioxide emissions are only about 12% more than in 1990. GDP has increased by 63% over that same time period. US- based oil and gas industry sources have reported direct emission reductions totaling 48.3 million metric tons CO 2 equivalent for 2008 compared to 2007. The reduction of 48.3 million metric tons is equivalent to taking 9.7 million cars and light trucks off the road. Comparable figures for 2009 are a 52.8 million metric tons reduction and 10.6 million cars taken off the roads. For 2010, the reported reduction of 55.9 million

Other private industry

Technology categories Enabling Non-hydrocarbon End use

Federal government Fuel substitution without shale Shale gas

Source: Data complied from 565+ annual company reports for 2000–2010, and the US Department of Energy, Energy Information Administration

FIG. 1

North America GHG mitigation investments divided by industry and government money from 2000 to 2010. The total invested in 2010 was $225 billion.

Total investment = $225.2 billion Top six = $170 billion

All other investment 24%

CHP 7% Wind 8%

ATV 22%

Shale gas 7% Ethanol 8%

Lighting, heating, AC efﬁciency, etc. 14%

Source: Data compiled from 565+ annual company reports for 2000–2010, and the US Department of Energy, Energy Information Administration

FIG. 2

Leading GHG mitigation investments in North America from 2000 to 2010. HYDROCARBON PROCESSING DECEMBER 2011

I 15

HPIMPACT US welding equipment demand to exceed $7 billion Demand in the US for welding equipment and consumables is forecast to increase 6.4% annually to $7.1 billion in 2015 (Table 1). Gains will be driven by continued recovery from the economic recession experienced between late 2007 and 2009 in major manufacturing and construction markets. Growth will also be fueled by the increasing number of applications in which various types of welding can be used. These and other trends are presented in a new study from The Freedonia Group. The welding equipment segment is dominated by arc and resistance welding systems, which accounted for a combined 70% of equipment demand in 2010. These will remain the dominant welding techniques, in part due to their successful integration TABLE 1. US welding equipment and consumables demand by market in millions of dollars % annual growth 2005– 2010– 2010 2015

Item

2005

2010

2015

Welding equipment and consumables

5,110

5,160

7,050

0.2

6.4

Manufacturing

3,268

3,250

4,390

–0.1

6.2

540

445

750

–3.8

Energy and power generation 195

215

290

6.2

Repair and maintenance

410

425

590

0.7

6.8

Consumer and other

697

825

1,030

3.4

4.5

Construction

A visiting Chinese delegation met with SABIC executives in Saudi Arabia.

The meeting was part of an effort to show China’s growing business profile in Saudi Arabia. 16

I DECEMBER 2011 HydrocarbonProcessing.com

with modern automation techniques that improve weld deposit rates and alleviate the shortage of skilled welders. Welding consumables will benefit from both economic recovery and the ubiquity of arc welding processes increasing 6.3% annually. Welding electrodes and filler metal accounted for 73% of all consumables in 2010, with oxyfuel and shielding gases accounting for the rest. Solid wire electrodes are the largest product category for electrodes and filler metal in dollar terms. However, emergent consumable products such as flux- and metal-cored electrodes are the most rapidly growing product segment. Among the gases, oxygen and acetylene are dominant in metal joining and cutting. Argon is by far the most commonly used shielding gas, followed by carbon dioxide. Manufacturing comprises the largest market for welding products, accounting for 63% of all consumption in 2010. Within the manufacturing sector, fabricated metal products and transportation equipment are the largest consumers, and recovery in these industries will help drive gains in welding product demand in manufacturing applications to $4.4 billion in 2015. Consumption of welding products by the construction industry will grow the fastest of any end-use industry. Based on recovery from a severe slowdown in 2008 and 2009, revitalized construction activity will drive demand to $750 million in 2015, or nearly 11% of the welding product market total.

Saudi petrochemical executives host meeting with senior Chinese official Officials with petrochemical major Saudi Basic Industries Corp. (SABIC) hosted senior Chinese official He Lifeng (vice party secretary of the Tianjin city government) in early November at its headquarters in Riyadh, offering what it said was a strong sign of support for its growing China business profile. Mohamed Al-Mady, SABIC CEO, received Mr. He as well as his delegation, which included Xu Hongxing, president of the SINOPEC SABIC Tianjin Petrochemical Co. venture.The Chinese dignitaries watched a corporate film and a presentation, and attended a lunch reception hosted in their honor. Expressing his views on the visit, Mr. Al-Mady said that it reflects SABIC’s strong commitment to the Chinese market. “SABIC has embarked on a series of growth initiatives in China, including a new partnership with SINOPEC to build a polycarbonate plant in Tianjin and a new research center in Shanghai,” Mr. Al-Mady said. The visit comes on the heels of two recent delegations from China to SABIC. The first was headed by Zhang Gaoli, a member of the central committee political bureau with the Communist Party of China (CPC) and secretary of CPC Tianjin Municipal. The second delegation was led by Li Yongwu, chairman of China Petroleum and the Chemical Industry Federation. Mr. He was the party secretary of Fuzhou city and Xiamen before being promoted to his current post. He was also the Xiamen city director of treasury, and later vice mayor. SABIC has 17 offices in China, three manufacturing plants in Shanghai, Guangzhou and Tianjin, and one technology and innovation center in Shanghai. It employs over 900 staff members. “We are happy to receive such dignitaries from China’s expanding chemical industry,” Mr. Al-Mady said. “This reflects our rapidly growing presence in China and our ambition to be the preferred petrochemical supplier in this country.” HP

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UNIQUE HIGH QUALITY SOLUTIONS

Process Insight:

Selecting the Best Solvent for Gas Treating

Selecting the best amine/solvent for gas treating is not a trivial task. There are a number of amines available to remove contaminants such as CO2, H2S and organic sulfur compounds from sour gas streams. The most commonly used amines are monoethanolamine (MEA), diethanolamine (DEA), and methyldiethanolamine (MDEA). Other amines include diglycolamine® (DGA), diisopropanolamine (DIPA), and triethanolamine (TEA). Mixtures of amines can also be used to customize or optimize the acid gas recovery. Temperature, pressure, sour gas composition, and purity requirements for the treated gas must all be considered when choosing the most appropriate amine for a given application.

Primary Amines

Mixed Solvents

dŚĞ ƉƌŝŵĂƌǇ ĂŵŝŶĞ D ƌĞŵŽǀĞƐ ďŽƚŚ KϮ ĂŶĚ ,Ϯ^ ĨƌŽŵ ƐŽƵƌ ŐĂƐ ĂŶĚ ŝƐ ĞīĞĐƟǀĞ Ăƚ ůŽǁ ƉƌĞƐƐƵƌĞ͘ ĞƉĞŶĚŝŶŐ ŽŶ ƚŚĞ ĐŽŶĚŝƟŽŶƐ͕ D ĐĂŶ ƌĞŵŽǀĞ ,Ϯ^ ƚŽ ůĞƐƐ ƚŚĂŶ ϰ ƉƉŵǀ ǁŚŝůĞ ƌĞŵŽǀŝŶŐ KϮ ƚŽ ůĞƐƐ ƚŚĂŶ ϭϬϬ ƉƉŵǀ͘ D ƐǇƐƚĞŵƐ ŐĞŶĞƌĂůůǇ ƌĞƋƵŝƌĞ Ă ƌĞĐůĂŝŵĞƌ ƚŽ ƌĞŵŽǀĞ ĚĞŐƌĂĚĞĚ ƉƌŽĚƵĐƚƐ ĨƌŽŵ ĐŝƌĐƵůĂƟŽŶ͘ dǇƉŝĐĂů ƐŽůƵƟŽŶ ƐƚƌĞŶŐƚŚ ƌĂŶŐĞƐ ĨƌŽŵ ϭϬ ƚŽ ϮϬ ǁĞŝŐŚƚ й ǁŝƚŚ Ă ŵĂǆŝŵƵŵ ƌŝĐŚ ůŽĂĚŝŶŐ ŽĨ Ϭ͘ϯϱ ŵŽůĞ ĂĐŝĚ ŐĂƐͬŵŽůĞ D ͘ ' Π ŝƐ ĂŶŽƚŚĞƌ ƉƌŝŵĂƌǇ ĂŵŝŶĞ ƚŚĂƚ ƌĞŵŽǀĞƐ KϮ͕ ,Ϯ^͕ K^͕ ĂŶĚ ŵĞƌĐĂƉƚĂŶƐ͘ dǇƉŝĐĂů ƐŽůƵƟŽŶ ƐƚƌĞŶŐƚŚƐ ĂƌĞ ϱϬͲϲϬ ǁĞŝŐŚƚ й͕ ǁŚŝĐŚ ƌĞƐƵůƚ ŝŶ ůŽǁĞƌ ĐŝƌĐƵůĂƟŽŶ ƌĂƚĞƐ ĂŶĚ ůĞƐƐ ĞŶĞƌŐǇ ƌĞƋƵŝƌĞĚ ĨŽƌ ƐƚƌŝƉƉŝŶŐ ĂƐ ĐŽŵƉĂƌĞĚ ǁŝƚŚ D ͘ ' ĂůƐŽ ƌĞƋƵŝƌĞƐ ƌĞĐůĂŝŵŝŶŐ ƚŽ ƌĞŵŽǀĞ ƚŚĞ ĚĞŐƌĂĚĂƟŽŶ ƉƌŽĚƵĐƚƐ͘

Secondary Amines

/Ŷ ĐĞƌƚĂŝŶ ƐŝƚƵĂƟŽŶƐ͕ ƚŚĞ ƐŽůǀĞŶƚ ĐĂŶ ďĞ ͞ĐƵƐƚŽŵŝǌĞĚ͟ ƚŽ ŽƉƟŵŝǌĞ ƚŚĞ ƐǁĞĞƚĞŶŝŶŐ ƉƌŽĐĞƐƐ͘ &Žƌ ĞǆĂŵƉůĞ͕ ĂĚĚŝŶŐ Ă ƉƌŝŵĂƌǇ Žƌ ƐĞĐŽŶĚĂƌǇ ĂŵŝŶĞ ƚŽ D ĐĂŶ ŝŶĐƌĞĂƐĞ ƚŚĞ ƌĂƚĞ ŽĨ KϮ ĂďƐŽƌƉƟŽŶ ǁŝƚŚŽƵƚ ĐŽŵƉƌŽŵŝƐŝŶŐ ƚŚĞ ĂĚǀĂŶƚĂŐĞƐ ŽĨ D ͘ DŽƌĞ ĐŽŵŵŽŶ ŝŶ ƚŽĚĂǇ͛Ɛ ŵĂƌŬĞƚ ŝƐ ƚŚĞ ĂĚĚŝƟŽŶ ŽĨ ƉŝƉĞƌĂǌŝŶĞ ƚŽ D ƐŽůƵƟŽŶƐ ĨŽƌ KϮ ƌĞŵŽǀĂů Žƌ ƉŽƐƐŝďůǇ ĂŶ ĂĐŝĚ ƚŽ ĂŝĚ ŝŶ ƌĞŐĞŶĞƌĂƚŽƌ ƉĞƌĨŽƌŵĂŶĐĞ ĨŽƌ ƚŚĞ ůĞĂŶ ƐŽůǀĞŶƚ͘ DĂŶǇ ƉůĂŶƚƐ ƵƟůŝǌĞ Ă ŵŝǆƚƵƌĞ ŽĨ ĂŵŝŶĞ ǁŝƚŚ ƉŚǇƐŝĐĂů ƐŽůǀĞŶƚƐ͘ ^h>&/EK> ŝƐ Ă ůŝĐĞŶƐĞĚ ƉƌŽĚƵĐƚ ĨƌŽŵ ^ŚĞůů Kŝů WƌŽĚƵĐƚƐ ƚŚĂƚ ĐŽŵďŝŶĞƐ ĂŶ ĂŵŝŶĞ ǁŝƚŚ Ă ƉŚǇƐŝĐĂů ƐŽůǀĞŶƚ͘ ĚǀĂŶƚĂŐĞƐ ŽĨ ƚŚŝƐ ƐŽůǀĞŶƚ ĂƌĞ ŝŶĐƌĞĂƐĞĚ ŵĞƌĐĂƉƚĂŶ ƉŝĐŬƵƉ͕ ůŽǁĞƌ ƌĞŐĞŶĞƌĂƟŽŶ ĞŶĞƌŐǇ͕ ĂŶĚ ƐĞůĞĐƟǀŝƚǇ ƚŽ ,Ϯ^͘

Choosing the Best Alternative

dŚĞ ƐĞĐŽŶĚĂƌǇ ĂŵŝŶĞ ƌĞŵŽǀĞƐ ďŽƚŚ KϮ ĂŶĚ ,Ϯ^ ďƵƚ ŐĞŶĞƌĂůůǇ ƌĞƋƵŝƌĞƐ ŚŝŐŚĞƌ ƉƌĞƐƐƵƌĞ ƚŚĂŶ D ƚŽ ŵĞĞƚ ŽǀĞƌŚĞĂĚ ƐƉĞĐŝĮĐĂƟŽŶƐ͘ ĞĐĂƵƐĞ ŝƐ Ă ǁĞĂŬĞƌ ĂŵŝŶĞ ƚŚĂŶ D ͕ ŝƚ ƌĞƋƵŝƌĞƐ ůĞƐƐ ĞŶĞƌŐǇ ĨŽƌ ƐƚƌŝƉƉŝŶŐ͘ dǇƉŝĐĂů ƐŽůƵƟŽŶ ƐƚƌĞŶŐƚŚ ƌĂŶŐĞƐ ĨƌŽŵ Ϯϱ ƚŽ ϯϱ ǁĞŝŐŚƚ й ǁŝƚŚ Ă ŵĂǆŝŵƵŵ ƌŝĐŚ ůŽĂĚŝŶŐ ŽĨ Ϭ͘ϯϱ ŵŽůĞͬŵŽůĞ͘ /W ŝƐ Ă ƐĞĐŽŶĚĂƌǇ ĂŵŝŶĞ ƚŚĂƚ ĞǆŚŝďŝƚƐ ƐŽŵĞ ƐĞůĞĐƟǀŝƚǇ ĨŽƌ ,Ϯ^ ĂůƚŚŽƵŐŚ ŝƚ ŝƐ ŶŽƚ ĂƐ ƉƌŽŶŽƵŶĐĞĚ ĂƐ ĨŽƌ ƚĞƌƟĂƌǇ ĂŵŝŶĞƐ͘ /W ĂůƐŽ ƌĞŵŽǀĞƐ K^͘ ^ŽůƵƟŽŶƐ ĂƌĞ ůŽǁ ŝŶ ĐŽƌƌŽƐŝŽŶ ĂŶĚ ƌĞƋƵŝƌĞ ƌĞůĂƟǀĞůǇ ůŽǁ ĞŶĞƌŐǇ ĨŽƌ ƌĞŐĞŶĞƌĂƟŽŶ͘ dŚĞ ŵŽƐƚ ĐŽŵŵŽŶ ĂƉƉůŝĐĂƟŽŶƐ ĨŽƌ /W ĂƌĞ ŝŶ ƚŚĞ /WΠ ĂŶĚ ^h>&/EK>Π ƉƌŽĐĞƐƐĞƐ͘

Tertiary Amines ƚĞƌƟĂƌǇ ĂŵŝŶĞ ƐƵĐŚ ĂƐ D ŝƐ ŽŌĞŶ ƵƐĞĚ ƚŽ ƐĞůĞĐƟǀĞůǇ ƌĞŵŽǀĞ ,Ϯ^͕ ĞƐƉĞĐŝĂůůǇ ĨŽƌ ĐĂƐĞƐ ǁŝƚŚ Ă ŚŝŐŚ KϮ ƚŽ ,Ϯ^ ƌĂƟŽ ŝŶ ƚŚĞ ƐŽƵƌ ŐĂƐ͘ KŶĞ ďĞŶĞĮƚ ŽĨ ƐĞůĞĐƟǀĞ ĂďƐŽƌƉƟŽŶ ŽĨ ,Ϯ^ ŝƐ Ă ůĂƵƐ ĨĞĞĚ ƌŝĐŚ ŝŶ ,Ϯ^͘ D ĐĂŶ ƌĞŵŽǀĞ ,Ϯ^ ƚŽ ϰ ƉƉŵ ǁŚŝůĞ ŵĂŝŶƚĂŝŶŝŶŐ Ϯй Žƌ ůĞƐƐ KϮ ŝŶ ƚŚĞ ƚƌĞĂƚĞĚ ŐĂƐ͕ ƚŚƵƐ ƵƐŝŶŐ ƌĞůĂƟǀĞůǇ ůĞƐƐ ĞŶĞƌŐǇ ĨŽƌ ƌĞŐĞŶĞƌĂƟŽŶ ƚŚĂŶ ƚŚĂƚ ĨŽƌ ͘ ,ŝŐŚĞƌ ǁĞŝŐŚƚ ƉĞƌĐĞŶƚ ĂŵŝŶĞ ĂŶĚ ůĞƐƐ KϮ ĂďƐŽƌďĞĚ ƌĞƐƵůƚƐ ŝŶ ůŽǁĞƌ ĐŝƌĐƵůĂƟŽŶ ƌĂƚĞƐ ĂƐ ǁĞůů͘ dǇƉŝĐĂů ƐŽůƵƟŽŶ ƐƚƌĞŶŐƚŚƐ ĂƌĞ ϰϬͲϱϬ ǁĞŝŐŚƚ й ǁŝƚŚ Ă ŵĂǆŝŵƵŵ ƌŝĐŚ ůŽĂĚŝŶŐ ŽĨ Ϭ͘ϱϱ ŵŽůĞͬŵŽůĞ͘ ĞĐĂƵƐĞ D ŝƐ ŶŽƚ ƉƌŽŶĞ ƚŽ ĚĞŐƌĂĚĂƟŽŶ͕ ĐŽƌƌŽƐŝŽŶ ŝƐ ůŽǁ ĂŶĚ Ă ƌĞĐůĂŝŵĞƌ ŝƐ ƵŶŶĞĐĞƐƐĂƌǇ͘ KƉĞƌĂƟŶŐ ƉƌĞƐƐƵƌĞ ĐĂŶ ƌĂŶŐĞ ĨƌŽŵ ĂƚŵŽƐƉŚĞƌŝĐ͕ ƚǇƉŝĐĂů ŽĨ ƚĂŝů ŐĂƐ ƚƌĞĂƟŶŐ ƵŶŝƚƐ͕ ƚŽ ŽǀĞƌ ϭ͕ϬϬϬ ƉƐŝĂ͘

'ŝǀĞŶ ƚŚĞ ǁŝĚĞ ǀĂƌŝĞƚǇ ŽĨ ŐĂƐ ƚƌĞĂƟŶŐ ŽƉƟŽŶƐ͕ Ă ƉƌŽĐĞƐƐ ƐŝŵƵůĂƚŽƌ ƚŚĂƚ ĐĂŶ ĂĐĐƵƌĂƚĞůǇ ƉƌĞĚŝĐƚ ƐǁĞĞƚĞŶŝŶŐ ƌĞƐƵůƚƐ ŝƐ Ă ŶĞĐĞƐƐŝƚǇ ǁŚĞŶ ĂƩĞŵƉƟŶŐ ƚŽ ĚĞƚĞƌŵŝŶĞ ƚŚĞ ďĞƐƚ ŽƉƟŽŶ͘ WƌŽDĂǆΠ ŚĂƐ ďĞĞŶ ƉƌŽǀĞŶ ƚŽ ĂĐĐƵƌĂƚĞůǇ ƉƌĞĚŝĐƚ ƌĞƐƵůƚƐ ĨŽƌ ŶƵŵĞƌŽƵƐ ƉƌŽĐĞƐƐ ƐĐŚĞŵĞƐ͘ ĚĚŝƟŽŶĂůůǇ͕ WƌŽDĂǆ ĐĂŶ ƵƟůŝǌĞ Ă ƐĐĞŶĂƌŝŽ ƚŽŽů ƚŽ ƉĞƌĨŽƌŵ ĨĞĂƐŝďŝůŝƚǇ ƐƚƵĚŝĞƐ͘ dŚĞ ƐĐĞŶĂƌŝŽ ƚŽŽů ŵĂǇ ďĞ ƵƐĞĚ ƚŽ ƐǇƐƚĞŵĂƟĐĂůůǇ ǀĂƌǇ ƐĞůĞĐƚĞĚ ƉĂƌĂŵĞƚĞƌƐ ŝŶ ĂŶ ĞīŽƌƚ ƚŽ ĚĞƚĞƌŵŝŶĞ ƚŚĞ ŽƉƟŵƵŵ ŽƉĞƌĂƟŶŐ ĐŽŶĚŝƟŽŶƐ ĂŶĚ ƚŚĞ ĂƉƉƌŽƉƌŝĂƚĞ ƐŽůǀĞŶƚ͘ dŚĞƐĞ ƐƚƵĚŝĞƐ ĐĂŶ ĚĞƚĞƌŵŝŶĞ ƌŝĐŚ ůŽĂĚŝŶŐ͕ ƌĞďŽŝůĞƌ ĚƵƚǇ͕ ĂĐŝĚ ŐĂƐ ĐŽŶƚĞŶƚ ŽĨ ƚŚĞ ƐǁĞĞƚ ŐĂƐ͕ ĂŵŝŶĞ ůŽƐƐĞƐ͕ ƌĞƋƵŝƌĞĚ ĐŝƌĐƵůĂƟŽŶ ƌĂƚĞ͕ ƚǇƉĞ ŽĨ ĂŵŝŶĞ Žƌ ƉŚǇƐŝĐĂů ƐŽůǀĞŶƚ͕ ǁĞŝŐŚƚ ƉĞƌĐĞŶƚ ŽĨ ĂŵŝŶĞ͕ ĂŶĚ ŽƚŚĞƌ ƉĂƌĂŵĞƚĞƌƐ͘ WƌŽDĂǆ ĐĂŶ ŵŽĚĞů ǀŝƌƚƵĂůůǇ ĂŶǇ ŇŽǁ ƉƌŽĐĞƐƐ Žƌ ĐŽŶĮŐƵƌĂƟŽŶ ŝŶĐůƵĚŝŶŐ ŵƵůƟƉůĞ ĐŽůƵŵŶƐ͕ ůŝƋƵŝĚ ŚǇĚƌŽĐĂƌďŽŶ ƚƌĞĂƟŶŐ͕ ĂŶĚ ƐƉůŝƚ ŇŽǁ ƉƌŽĐĞƐƐĞƐ͘ /Ŷ ĂĚĚŝƟŽŶ͕ WƌŽDĂǆ ĐĂŶ ĂĐĐƵƌĂƚĞůǇ ŵŽĚĞů ĐĂƵƐƟĐ ƚƌĞĂƟŶŐ ĂƉƉůŝĐĂƟŽŶƐ ĂƐ ǁĞůů ĂƐ ƉŚǇƐŝĐĂů ƐŽůǀĞŶƚ ƐǁĞĞƚĞŶŝŶŐ ǁŝƚŚ ƐŽůǀĞŶƚƐ ƐƵĐŚ ĂƐ ŽĂƐƚĂů 'ZΠ͕ ŵĞƚŚĂŶŽů͕ ĂŶĚ EDW͘ &Žƌ ŵŽƌĞ ŝŶĨŽƌŵĂƟŽŶ ĂďŽƵƚ WƌŽDĂǆ ĂŶĚ ŝƚƐ ĂďŝůŝƚǇ ƚŽ ĚĞƚĞƌŵŝŶĞ ƚŚĞ ĂƉƉƌŽƉƌŝĂƚĞ ƐŽůǀĞŶƚ ĨŽƌ Ă ŐŝǀĞŶ ƐĞƚ ŽĨ ĐŽŶĚŝƟŽŶƐ͕ ĐŽŶƚĂĐƚ ƌǇĂŶ ZĞƐĞĂƌĐŚ Θ ŶŐŝŶĞĞƌŝŶŐ͘

WƌŽDĂǆΠ ƉƌŽĐĞƐƐ ƐŝŵƵůĂƟŽŶ ƐŽŌǁĂƌĞ ďǇ ƌǇĂŶ ZĞƐĞĂƌĐŚ Θ ŶŐŝŶĞĞƌŝŶŐ͕ /ŶĐ͘ ŶŐŝŶĞĞƌŝŶŐ ^ŽůƵƟŽŶƐ ĨŽƌ ƚŚĞ Kŝů͕ 'ĂƐ͕ ZĞĮŶŝŶŐ Θ ŚĞŵŝĐĂů /ŶĚƵƐƚƌŝĞƐ͘ ƐĂůĞƐΛďƌĞ͘ĐŽŵ ǁǁǁ͘ďƌĞ͘ĐŽŵ ϵϳϵ ϳϳϲͲϱϮϮϬ h^ ϴϬϬ ϳϳϲͲϱϮϮϬ Select 71 at www.HydrocarbonProcessing.com/RS

HPI 2012 FORECAST HP EDITORIAL www.GulfPub.com/2011HPI

HPI Market Data 2012 Executive Summary THE NEXT STEP

What is the global energy outlook? Energy drives eco-

The economic recovery continues for the global hydrocarbon processing industry (HPI). Energy drives economic growth. Unfortunately for developed nations, stronger economic recovery remains a slow, arduous process with a prolonged comeback. The present downturn is very similar to the Great Depression of the 1930s. Individuals who can remember those years understand that economic problems do not correct themselves in a year or two. It will take time, lots of time, and every nation will have a very different pathway to recovery. Major events, such as the 2008/2009 downturn, also shift other trends forward. In pre-2008, China was not expected to become the No. 1 energy-consuming economy until 2015. China’s long economic expansion run, combined with the US downturn and energy demand collapse, shifted the order of energy consuming nations in 2010; China is now the major energy consuming nation. Other changes are expected. In 2011, the financial collapse continues to play out on the global stock markets and national economies. Weakness by several European Union nations continues to undermine confidence in this manufacturing/trading block. National debt by Italy, Spain and Greece weigh heavily on investment confidence for Europe. Likewise, the political and social unrest in North Africa and the Middle East further support fear over crude oil supply security and increase the volatility of energy prices.

nomic growth and sustains fiscal health. Factors shaping the energy industry in 2012 include: • The pace of global economic recovery will greatly influence the types of energy used over the next few years. Actions by governments on climate change and energy security are major forces that will impact the HPI. • Energy demand will be driven by developing nations and account for 93% of the new energy demand. China, the largest energy-consuming nation, will be a major force in shaping the global energy marketplace. • Fossil fuels (coal, oil and natural gas) will comprise the majority of primary energy resources; rising penalties on carbon emissions will encourage switching to low-carbon feedstocks in addition to efforts to reduce energy consumption. • Unconventional oil will play an increasing role in the global oil supply. About 10% of the world’ oil supply is met by unconventional oils, and that number will increase. Canadian oil sands and Venezuelan extra-heavy crude are dominate sources. However, coal-to-liquids, gas-to-liquids and shale oils will play roles as future energy resources. • Crude oil will remain a dominant part of the primary fuel mix. Nuclear energy is facing immense scrutiny and challenges for future new installations, and it is only 8% of the total energy mix. Renewable energy including, hydro, wind, solar, geothermal

Global oil demand changes, 2008–2011 thousand bpd FSO Europe North America 2008 2009 2010 -1,300 -900 516

2011 -207

2012 0

2008 2009 0 -730

Latin America 2008 2009 300 0

2010 300

2010 -100

2011 2012 -150 -370

2008 2009 0 -200

2010 2011 2012 290 120 100

Middle East 2008 2009 400 290

2010 280

2011 2012 200 270

2011 2012 220 245

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

Africa 2008 2009 0 50

2010 2011 2012 50 40 125

Tim Lloyd Wright is HP’s European Editor and has been active as a reporter Source: Hydrocarbon Processing

FIG. 1

Global oil demand changes by regions, 2008–2012.

and conference chair in the European downstream industry since 1997, before which he was a feature writer and reporter for the UK broadsheet press and BBC radio. Mr. Wright lives in Sweden and is founder of a local climate and sustainability initiative.

HYDROCARBON PROCESSING DECEMBER 2011

I 19

HPI 2012 FORECAST and modern biomass will increase their share of the energy mix. But these energy forms struggle to be viable replacements for hydrocarbon resources. More research is needed to reduce manufacturing costs. Government subsidies prevent renewables from competing on their own within the marketplace for many reasons.

HPI companies are strengthening their balance sheets and seek opportunities to maximize market shares through strategic capital investments. Such endeavors also include purchasing and revamping existing facilities over construction of a grassroots facility. CONSTRUCTION

Current state. The global HPI struggles to find a steady-state

situation for demand. The 2008/2009 recession was a significant economic tsunami that hastened demand changes for energy and petrochemical-based products. In 2011, there is significant talk, if not fear, that a double dip recession may be very possible given the current economic news and political events. Yet, the global economy manages to squeeze through the year with improved demand numbers for crude oil (Fig. 1). TOTAL SPENDING

In 2012, the HPIâ&#x20AC;&#x2122;s capital, maintenance and operating budgets are expected to exceed $222 billion (Tables 1â&#x20AC;&#x201C;3). Capital spending is projected to reach $56.3 billion; maintenance spending should reach $66 billion; and operating spending is estimated to exceed $99.9 billion, as summarized in Table 2. The HPI continues to be more cost conscious. The 2012 total spending includes $107 billion on global petrochemical/chemical facilities, $87 billion on refining operations, approximately $23.4 billion on gas processing/LNG facilities and $4 billion on synfuels projects as listed in Table 1. Changing product trends, political and economic instability and currency issues have delayed projects, if not cancelled HPI construction projects. Project spending is more conservative. Table 1. 2012 Worldwide HPI total spending by sector Sector, millions $ Petrochemical/ chemical Refining Gas processing Synfuels Totals

US 29,416 21,568 5,726 56,710

OUS 78,271 65,410 17,712 4,000 165,393

Worldwide 107,687 86,978 23,438 4,000 222,103

Table 2. 2012 Worldwide HPI total spending by budget Type, millions $ Capital Maintenance Operating Total

US 9,550 15,830 30,382 55,762

1,279 30% 712 16% 108 2%

43 1% Engineering FEED Maintenance

FIG. 2

OUS 46,760 50,050 69,531 166,341

Worldwide 56,310 65,880 99,913 222,103

1,983 46%

204 5% Planning Study Under construction

Breakdown of all 2011 HPI projects by activity level.

I DECEMBER 2011 HYDROCARBON PROCESSING

Since 2000, the global HPI has been expanding at a moderate rate. Economic cycles and the aftermath of the September 11, 2001 events yielded small gains. However, beginning in 2006, the HPI saw a wave of new project announcements for the global refining, petrochemical and natural gas processing industries. Emerging demand and strong economic growth by developing nations became the driving force for new energy consumption and initiated new HPI processing capacity activities. Some industry consultants have feared that there were too many announced projects and some would not come to fruition, remaining an announcement or stalled in the engineering stage. The 2008/2009 recession proved to be a significant adjustment in consuming markets. The depth of the global economic downturn destroyed some consumer markets. Such changes caused the rebalancing of supply/demand for HPI products. The adjusted demand and available supply caused some HPI projects to be delayed if not cancelled for a variety of reasons, including diminished demand, lack of financing and so forth. As shown in Tables 4 and 5, refining and petrochemical projects are the core of new construction. Refined transportation fuels and petrochemical products are clearly consumer goods. Natural gas processing and liquefied natural gas (LNG) are indirect consumables in that this hydrocarbon is a feedstock for petrochemical products/fertilizer industries or is used extensively for electric power generation. Many forces and conditions will impact project activity in 2012. Product demand and secure feedstock supplies are vital in Table 3. 2012 Worldwide HPI total spending for equipment and materials Item, millions $ Piping Valves Vessels and internals Pumps Compressors Mixers/agitators Drivers Heat exchangers Structurals Instrumentation Electricals Furnaces/boilers and tubes Storage tanks Insulation and refractories Paints and coatings Buildings Materials handling Tools Other equipment Chemicals/catalysts Containers and packaging Other materials Totals

US 808 615 720 670 568 155 673 1,068 148 1,995 810 613 198 303 206 49 106 106 406 13,852 1,170 1,320 26,559

OUS 3,360 2,370 2,770 2,630 2,120 560 2,560 4,300 670 7,740 3,210 2,500 995 1,280 733 225 340 340 1,580 29,000 4,480 4,270 78,033

Worldwide 4,168 2,985 3,490 3,300 2,688 715 3,233 5,368 818 9,735 4,020 3,113 1,193 1,583 939 274 446 446 1,986 42,852 5,650 5,590 104,592

HPI 2012 FORECAST any project development. Financing is equally important; once the facility is built, it must pay for itself—capital, operating, and maintenance expenses. Table 5 shows the global nature of this industry. An HPI project can take as long as 10 years from the conceptual design until commissioning and on-specification products are produced (Fig. 2). Even after construction is completed, capital expenses still continue; plant equipment wear out or fail under normal operating conditions. Unexpected events (such as fires, explosions, hurricanes, floods, etc.) or other major catastrophes can compromise, if not destroy key equipment, thus requiring full replacement of major or entire operating units. REFINING

There are approximately 650 refineries with a combined processing capacity of 85 MMbpd in operation worldwide. They vary in complexity, as well as in size. About 83 MMbpsd of capacity is the traditional crude oil feedstocks, and 2 MMbpsd of capacity is based on unconventional feeds. Margins are sustained by unique combinations of complexity and capacity. Profitability is determined by the feedstock processed, as well as by the finished products produced. Changes in future crude oil characteristics, price and availability will impact operations and profitability of present and future refining capacity additions. The type and cost of crude oils are major factors in the final cost for refined products. The price of crude oils is manipulated by a number of factors such as embargoes, wars, recessions and so forth as shown in Fig. 3; all are beyond the control of refiners. Refining capacity is a long-term investment. Many factors will change during that time. Flexibility to process different feedstocks and finish products are necessary. Investment is continuous to replace/repair worn equipment along with the installation of new processing units to add more processing flexibility and to meet safety and environmental mandates. Looking ahead, the available feedstocks for upgrading are becoming more heavy and sour. Proven reserves are heavier and sour. Light sweet crudes will command higher prices. The flexibility to process the heavier crudes does require more capital investment in infrastructure—an upfront capital cost. As shown in Fig. 4 and Tables 4 and 5, all regions have some refining capacity expansions planned. What is important is the investment being made to handle the different crudes available. New project designs will be able to process heavy and medium crude oil feeds; less new capacity will be designed for light sweet and light sour feeds.

substantial new capacity over the next few years. Latin America is also experiencing a refining capacity boom with discoveries of crude oil reserves offshore from Brazil. Biofuels. World production capacity is approaching 36 billion

gallons, but worldwide demand is nowhere close to that level, and overcapacity has plagued the industry worldwide. Operating rates are typically in the 10%–15% range. The only exception is the EU, where mandates make this region an active importer of biodiesel from Argentina, the US and Southeast Asia. However, sustainability issues keep the Indonesian exports from growing into the EU. This question of sustainability and using the rainforest for palm-oil production poses a similar problem for the large Neste renewable diesel production that came online in early 2011 in Singapore, about 600 million gallons, which will depend on Indonesian and Malaysian palm oil for feedstock. Biodiesel production is at the forefront of the food vs. fuel fight; most developing nations depend on edible oils for food production. Even the EU, India and the US import much of the vegetable oils consumed in those countries. India has banned the use of imported Table 4. Worldwide HPI construction projects Petrochem/chem Refining Gas processing Synfuels All others Total

Jun-08 1,676 1,564 1,127 87 650 5,104

Jun-09 1,837 1,692 1,196 98 650 5,473

Jun-10 1,889 1,751 1,266 108 718 5,732

Jul-11 1,246 1,427 939 78 639 4,329

Table 5. Worldwide HPI construction projects by region: June 2008 to July 2011 Jun-08 671 188 458 1,153 192 942 1,425 5,029

US Canada Latin America Europe Africa Middle East Asia-Pacific Total

Jun-09 714 212 530 1,261 215 990 1,551 5,473

Jun-10 716 209 607 1,283 231 1,057 1,629 5,732

Jul-11 421 155 469 956 179 872 1,277 4,329

100

New capacity. New grassroots capacity is in the planning and 80 Crude oil, 2008 $/bbl

engineering phases for facilities located in China. However, ever changing product specification and consumer demands are also initiating construction/expansion projects for existing refineries, globally. Much of this project activity is being driven by economic and environmental factors. The only positive out of the 2008/2009 recession was a slowdown in new refining capacity coming online over the last year. In fact, the brutal conditions forced some refining projects to be abandoned and others delayed until demand improved. New demand for refined products will be concentrated in developing nations shown in Tables 4 and 5. Accordingly, new capacity expansion will be primary located in Asia-Pacific (Fig. 4). Approximately 5 MMbpd of new refining capacity will be added over the next three years; the majority of new processing capacity will be largely located in China. The Middle East, likewise, is planning

60 Suez crisis

OPEC 10% quota increase Asian ﬁnancial crisis Iran/Iraq war Iranian revolution Gulf Yom Kippur war war oil embargo

PDVSA strike Iraq war Asian growth weaker dollar Series of OPEC cuts 4.2 million barrels

20 US price controls

Recession 2/11

47 51 55 59 63 67 71 75 79 83 87 91 95 99 03 07 49 53 57 61 65 69 73 77 81 85 89 93 97 01 05 09

1947-August, 2009 US 1st purchase price (wellhead) Average world $28.68 Average US $26.64 Median US and world $19.60 World price

FIG. 3

Crude oil prices influenced by human events in 2008 US dollars. HYDROCARBON PROCESSING DECEMBER 2011

I 21

HPI 2012 FORECAST edible oils from Malaysia and Indonesia to process biodiesel. Jathropha oil is being grown in Africa and India, but it remains to be seen if it can be grown in sufficient quantities and cost-effectively to compete with vegetable oil. Algae are perhaps the best hope for a future for biodiesel, but its commercial production is still a decade away. NATURAL GAS/LNG Consumption. Worldwide natural gas consumption jumped

7.4% to 3,169 billion cubic meters (Bcm) in 2010, the fastest increase since 1984. Demand growth was above average in all world regions, with the exception of the Middle East. The world’s largest natural gas user, the US, saw a 5.6 vol% increase in natural gas consumption in 2010 to a new record high of 683.4 Bcm. China and Russia saw marked increases in volumetric consumption, as well. Other Asian countries posted collective consumption growth of 10.7%, led by India with a 21.5% increase. Fig. 5 shows production and consumption of natural gas by region from 1985– 2010, according to BP’s 2011 Statistical Review of World Energy. Uncertainty surrounding energy-security and climate-change policies is making natural gas an attractive alternative to highpolluting coal and oil located in politically unstable areas. The

Capacity additions, Mbpd

4,000 Latin America FSU Africa Middle East

3,000 2,000

Other Asia China Europe North America

Production. BP’s Statistical Review of World Energy reported

1,000 0

-1,000 2010

2011

2012

2013

2014

2015

Source: Muse

FIG. 4

International Energy Agency (IEA) sees natural gas overtaking coal as the second-most-prominent fuel in the energy mix before 2030, with coal use dropping in favor of natural gas most visibly in the US and China. Furthermore, unconventional gas could account for as much as 40% of global production growth in natural gas through 2035, with output from shale formations poised for major growth. The US Energy Information Administration (EIA) forecasts an annual rise in US natural gas consumption in 2011 of 1.8% to 67.4 billion cubic feet per day (Bcfd), and an increase of just 0.7% in 2012 to 67.8 Bcfd. Growth in demand from the electric power and industrial sectors will offset expected decreases in commercial and residential use. Elsewhere in the Atlantic Basin, European gas demand is anticipated to slow in the future due to sluggish population growth, already-high market penetration in many EU countries, and energy-efficiency improvements. In the Middle East, gas demand is expected to double through 2035 on increased power needs and industrial use, spurring some countries to establish policies prioritizing domestic gas use over exportation. Major consumer China’s natural gas demand is anticipated to account for one-third of the Asia-Pacific region’s total gas demand over the next 20 years, while greater demand for LNG in Japan, South Korea, and other Southeast Asian countries will drive up regional LNG consumption. The Asian-Pacific LNG market will see a marked tightening through 2020 as a result of the nuclear outages caused by the March 2011 earthquake and tsunami in Japan.

Global refinery capacity additions by regions, 2010–2015.

that global natural gas output increased 7.3% in 2010 to 3,193.3 Bcm. Significant production gains were seen in Qatar (30.7%), Russia (11.6%) and the US (4.7%). According to the EIA, the fastest growth in gas output through 2035 will take place in non-OECD regions such as the Middle East (particularly Iran and Qatar), Africa, Russia, and the rest of non-OECD Europe and Eurasia. In light of rising electricity demand and climate concerns, power production will remain the star among growth segments for natural gas.

Production

3,500

Consumption

Rest of World Asia Paciﬁc Europe and Eurasia North America

3,000 2,500

Bcm

2,000 1,500 1,000 500 0 1985

1990

1995

2000

2005

Source: BP, Statistical Review of World Energy

FIG. 5

Production and consumption of natural gas by region, 2010.

I DECEMBER 2011 HYDROCARBON PROCESSING

2010 1985

1990

1995

2000

2005

2010

HPI 2012 FORECAST Under the IEA’s “golden age of gas” scenario, the US, China and Canada will lead the world in the production of unconventional gas. By 2035, unconventional reserves could make up 24% of global natural gas output, up from 12% in 2008. Fig. 6 shows the IEA’s estimates for production of conventional and unconventional gas from major producing countries in 2035. The EIA expects US natural gas production in 2011 to average 65.5 Bcfd, a 5.9% rise over 2010 output. The US market is seen tightening in 2012 as domestic gas output growth slows in response to overproduction, subdued prices since the 2008 peak, and uncertainty surrounding regulations for hydraulic fracturing technology. However, an overall expansion in US gas production and exports will continue over the next few decades, further reducing the need for imports. Canada sees investment in domestic gas production declining through 2013 due to a gas oversupply in North America and a projected shift in the region’s drilling focus away from natural gas and toward oil and other liquid hydrocarbons. Meanwhile, South America is expected to become a significant net importer of LNG over the next decade as a result of a slowdown in gas production in major producer Argentina. Across the Atlantic Ocean, OECD Europe’s production of natural gas from tight sands, shale and coalbed methane is not expected to offset generally declining output in the region over the following decades. Conversely, the IEA expects gas output from non-OECD Asia to expand by 8.9 trillion cubic feet from 2007–2035, with China and India making up the largest growth segments of 35% and 24%, respectively. In the Pacific, Australia is rapidly becoming a global LNG hub, with four LNG construction projects underway as of August 2011. International trade. LNG’s share in global natural gas trade is growing rapidly. Russia and the Caspian Sea region are expected to export more gas to the East and West, while increased supplies of LNG from Australia will promote energy security and supply flexibility. Also, LNG demand from the Middle East and the Atlantic Basin is expected to strengthen through 2020, reducing the Asia-Pacific region’s grip on global LNG trade flows to around 53% from 60% in 2010.

North America’s gradual switch from net gas importer to net exporter is another major change. Several import terminals in the US Gulf of Mexico are being prepared for conversion into export facilities. The future of LNG exports from the US depends heavily on three key factors: growth in domestic shale gas production, the continued suppression of natural gas prices in the US relative to other LNG markets, and robust demand growth in LNG-consuming countries and regions. If shale gas production falls short of projections, shale-based LNG export plans may fall by the wayside. Additionally, lingering initiatives to reduce carbon footprint will inform LNG trade across regions and continents. Worldwide, LNG consumption growth is anticipated to slow to 2.2%/yr from 2020–2030 as “green” fuels and energy-efficiency initiatives take center stage. Demand growth will center on Asia from 2010–2020, with Europe, the Americas and the Middle East close behind. Also, the shale gas boom in the US will inspire importing countries to look to unconventional gas as an exploitable source of energy. PETROCHEMICALS

Outlooks for the global petrochemical industry are largely tied to the accessibility a given location has to natural gas. For regions such as North America, an abundance of shale has helped to keep natural gas prices low, allowing the ethane-based petrochemical industry to thrive. Russia United States China Iran Qatar Canada Algeria Australia Saudi Arabia Turkmenistan

Conventional Unconventional

200

400

Bcm

600

800

1,000

Source: IEA, World Energy Outlook 2011, Special Report

FIG. 6

Projected gas output from major producing countries, 2035.

Ethylene capacity additions, million metric tons

35 Other MDE Kuwait United Arab Emirates Qatar Iran Saudi Arabia

30 25 20 15 10 5 0 2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

Source: CMAI

FIG. 7

Ethylene capacity additions in the Middle East, 2004–2014.

HYDROCARBON PROCESSING DECEMBER 2011

I 23

Demand million metric ton

HPI 2012 FORECAST 5.2%

4.2%

5.3%

9.4%

7.3%

7.0%

3.2%

1.8%

1.7%

4.6%

0.1%

2.0%

400 600 500 World 300 Asia & 400 1990s ’00-’07 India 200 300 ’10-’15 200 100 -7.1% -1.4% 100 2008 2008 0 0 ’90 ’95 ’00 ’05 ’10 ’15 ’90 ’95 ’00 ’05 ’10 ’15

60 60 50 North 50 West America 40 40 Europe 30 30 20 20 -13.9% -16.2% 10 10 0 0 ’90 ’95 ’00 ’05 ’10 ’15 ’90 ’95 ’00 ’05 ’10 ’15 Source: CMAI

94 92 90 88 86 84 82 80 78 76

Ethylene supply/demand, million metric tons

180 160 140 120 100 80 60 40 20 0

Operating rate, %

Demand trends for petrochemical products, worldwide, Asia Pacific, North America and Western Europe, 1990– 2015.

FIG. 8

’04 ’05 ’06 ’07 ’08 ’09 ’10 ’11 ’12 ’13 ’14 Operating rate assumes shutdown at 4.5 MMtpy capacity No capacity is rationalized in the near term Capacity Demand Source: CMAI

FIG. 9

a new olefins cracker by 2017, while several other companies have launched exploratory programs as they consider capacity additions. Meanwhile, other firms are debottlenecking current units. However, the Middle East still has an advantage over North America based on its proximity to Asia. While North American producers have cheap feedstock access, post-recession demand is not growing quickly enough to consume the potential supply. As a result, producers must have export access to locations such as China and other Asia-Pacific countries, where demand continues to surge. That gives an economic edge to Middle East locations, which have an easier time shipping to nearby Asia (Fig. 7). Industry trends. Come 2012, the global petrochemical industry should be at a crossroads. Some recovery has taken place since the 2008–2009 recession, but the extent of growth depends on region. Many developed countries are seeing stagnant conditions, and future forecasts are murky. That said, some trends appear to be emerging. By region, Asia-Pacific will remain the global growth leader, based on burgeoning economic strength from China and India (Fig. 8). Behind them, however, North America may challenge the Middle East in new projects. Within industry, naphtha olefins crackers remain disadvantaged. However, producers will seek to maximize production from available resources such as natural gas condensate and coal-to-liquids. Overall, petrochemical companies throughout the world are restructuring, consolidating and implementing domestic and global strategies to improve profitability and contend with forecast economic changes, particularly in Europe where growth is lagging. Survival in the coming years will involve tough decisions by petrochemical operators. Older, high-cost facilities are forecast to be idled or permanently shut down. New projects may be delayed or even cancelled as demand for petrochemicals returns to pre2008 levels (Fig. 9).

Global ethylene supply and demand, 2004–2014.

Business, political factors drive R&D. Other changes

On the other hand, political concerns in North Africa and the Middle East have caused crude prices to skyrocket, with Brent values holding above $110/bbl and WTI near $100/bbl for much of 2011. As a result, naphtha-based regions are struggling to make the economics work. Shale technology has evolved rapidly and continues to improve, led by horizontal wells, lower rig cycle times, multiple fracs and multi-well pads. The technology is also scalable and transferable to numerous scale plays. Combine that with the reality that a substantial amount of new reserves are rich in natural gas liquids (NGLs), and there suddenly appears to be a feedstock haven for petrochemicals. In addition, the crack spread for natural gas continues to widen relative to crude. That will give midstream producers all the incentive they need to continue drilling in shale plays, which are abundant in North America and potentially even in Europe. Regional breakdown. Those developments are leading a petrochemical revival in areas that only a year ago were considered old news. While capacity continues to come onstream in Asia, led by growing China demand, the cheap feedstock advantage that once seemed exclusive to the Middle East is now available in places such as the US and Canada, where there is also more political stability. In the US, Dow Chemical has already announced plans to build 24

I DECEMBER 2011 HYDROCARBON PROCESSING

include competitive business pressures such as inventory reduction and improved customer service requiring that petrochemical facilities have greater availability, higher reliability and better cost efficiencies. Other areas that producers are looking to improve are increasing production capabilities at existing facilities, reducing the time between product slate changes and, through better control and analysis, minimizing product specification problems. Environmental considerations on the manufacturing and utility operations of the industry are impacting spending. Federal and state mandates in the US, and the Kyoto Treaty elsewhere in the world, are requiring petrochemical and refining facilities to drastically reduce nitrous oxide emissions. Discussions on greenhouse gas (GHG) emissions and carbon management are attaining backing by governments, special interest groups and the public. Climate-change policies are under development at various levels and will require changes in operations for many chemical producers. Petrochemical research and development (R&D) projects for new technology include catalyst and reactor systems, separation projects, bioprocess technologies, tools and construction materials, computational methods and tools, and analytical measurement techniques. Ultimate R&D goals are aimed at reducing energy consumption, enhancing economic competitiveness and lessening environmental impacts on the global petrochemical/ chemical industry. HP

HPINNOVATIONS SELECTED BY HYDROCARBON PROCESSING EDITORS Editorial@HydrocarbonProcessing.com

Optimize low TOC range monitoring How can a monitoring system, with a very short response time and a reliable and fast validation/calibration method, enable reuse of pure and hot water by monitoring steam processes and boiler feed water for contaminations by organics, reduce operation cost and energy loss? ODS Sampling & Analytical Systems in the Netherlands is experienced in installing online total organic carbon (TOC) process-monitoring systems and advises operators how to optimize their processes to obtain fast and accurate TOC measurements. In low TOC ranges, measuring and validating/calibrating can be problematic. Today, boilers operate at very high pressure (100 bar–120 bar and higher). According to numerous guidelines, only water contamination at concentrations lower than 0.1 mg/l C to 0.2 mg/l C are allowed. Boilers operating at lower pressure (60 bar–80 bar) allow water contamination at a slightly higher level of about 0.5 mg/l C. The TOC analyzer must be capable of monitoring this potential lowlevel TOC contamination reliably. To reduce operating costs and prevent any installation damages caused by too high TOC concentrations, the total monitoring TOC analyzer system’s response time should be as short as possible. There is a risk that contaminated return condensate is pumped back into the boiler drum before being detected. For monitoring possible TOC contaminations in steam processes and boiler feed-water applications, fast response times, as well as simple and fast validation of the results, are required. Thus, the total analyzing system—from the point of sample taking up to the analyzer—has to be optimized.

316 should be used. Every meter of sample line is one meter too much. TOC analyzers use the thermal oxidation method at 1,200°C combined with multiloop injection by LAR Process Analysers AG. These analyzers have low ranges with accurate and stable TOC or total carbon (TC) analyses. The lowest detectable limit is about 2 μg/l C. No pump is used in the sample stream. Peristaltic pumps use flexible tubes that cause absorption effects. TOC or TC? A boiler needs pure water. This water is produced via the makeup-water installation. All impurities are removed as far as possible. Acid attacks the metal boiler wall, process pipes and heat exchangers, resulting in pit corrosion. A TOC analyzer analyzes only organic carbons. A TC analyzer responds to organic hydrocarbons, as well as inorganic carbon (carbonates). Optimal sample conditioning.

Samples are extracted from a sample point in a big process pipe. A sample point at the lowest point, especially in horizontal pipes, will act as a buffer collecting fine particles like metal oxides, etc. Small particles need to be filtered out. There are several methods to reduce the sample temperature. Although the analyzers can handle a temperature of about 90°C, it is safer to reduce the temperature to a lower value such as between 30°C and 40°C. ODS uses an air-cooled heat exchanger with a very-low internal volume. In fact, it transports the sample continuously, at a flow of about 1 liter/min., as close as possible to the analyzer.

Reducing response time. By opti-

Fast validation and calibration.

mizing the dimension, size and type of materials of all wetted parts, such effects mentioned above, can be minimized. Sufficient sample velocity in sample lines of at least 0.3 m/s, preferably 1 m/s, is important. Small sample-line diameters decrease the total wetted surface. In general, ODS recommends an OD of 6-mm or ¼-in. lines with an ID of about 4 mm. However, this small-diameter sample line can handle very high pressure without any risk. Seamless sample pipes in stainless-steel quality

LAR has improved and simplified calibration and validation for TOC analyzers based on the high-temperature method at 1,200°C. With any other methods it is necessary to provide watery standards for calibration and validation—requiring high expenditure and long fall-out times. Its patented method uses a specified test gas. With the QuickTOCcondensate, the sample volume is defined by an injection loop and injected into the reactor via the carrier gas. The high temperature of 1,200°C enables

use of a defined concentration of CO2 or methane. Such a certified validation gas is stable and usable for a long period of time. LAR’s QuickTOC analyzers are especially customized to meet pure-water application. Select 1 at www.HydrocarbonProcessing.com/RS

Catalytic direct oxidation for sulfur recovery GTC Technology has a worldwide technology licensing agreement with TDA Research for sulfur recovery from hydrogen sulfide (H2S) through catalytic direct oxidation. The agreement expands GTC’s platform of acid-gas removal technology, including GT-CO2, a process technology for CO2 removal; GT-SSR, a Claus process for sulfur recovery with over 60 licenses; and Crystasulf, a liquid-phase Claus process technology for sulfur recovery. GTC expects the catalytic direct oxygen technology to apply to a range of 0.2 tpd to 300 tpd. “Direct oxidation catalyst technology provides a significant advance in sulfur recovery,” said Dr. Matt Thundyil, sulfur business leader for GTC Technology US,

FIG. 1

Sample conditioning panel.

As HP editors, we hear about new products, patents, software, processes, services, etc., that are true industry innovations—a cut above the typical product offerings. This section enables us to highlight these significant developments. For more information from these companies, please go to our website at www.HydrocarbonProcessing.com/rs and select the reader service number.

HYDROCARBON PROCESSING DECEMBER 2011

I 25

HPINNOVATIONS LLC. “We will be able to deliver greater value to our clients, and continue our exceptional track record in commercializing innovative technologies for the energy industry.” Select 2 at www.HydrocarbonProcessing.com/RS

hte engaged in research for Total The high-throughput experimentation (hte) company is collaborating with Total Gas and Power in a research project for optimizing a large-scale gas-to-chemical (GTC) process. The collaboration’s main goal was to compare the performance of newly developed catalyst formulations with a GTC catalyst already being used by Total on a large scale. The optimum process parameters for deployment on an industrial

scale were successfully determined within the scope of the cooperation. High throughput technologies and hte’s expertise, both in heterogeneous catalysis and process optimization, reportedly made a considerable contribution to securing the research project’s success. Based on a statistical Design of Experiments (DoE), hte performed numerous experimental investigations within a short period of time. The comprehensive and precise data provided from this was then used to create a macrokinetic reaction model for a GTC catalyst used by Total on an industrial scale. With its development and optimization of GTC processes, Total is striving to establish natural gas, biomass and coal as economically viable alternatives to crude oil and thereby tap new petrochemical added value chains. Total and hte are building on their successful cooperation in a follow-up project. Select 3 at www.HydrocarbonProcessing.com/RS

FIG. 2

CeraComp components.

Material virtually eliminates sealless pump failure

Select 5 at www.HydrocarbonProcessing.com/RS

CeraComp material, an innovative ceramic-matrix composite, reportedly delivers dramatic benefits over traditional silicon-carbide materials with superior fracture and wear resistance. It expands sealless pump reliability by virtually eliminating the risk of catastrophic failure. Green, Tweed’s CeraComp solutions are said to deliver exceptional toughness and fracture resistance for improved MTBF and reduced maintenance costs. The material is capable of withstanding temperatures over 1,100°F (600°C). This exceeds the upper limit of polymeric and elastomeric composites, and maintains outstanding chemical resistance. In addition, CeraComp’s excellent toughness enables better structural integrity and impact resistance, eliminating the risk of catastrophic failure. The material’s design flexibility makes it suitable for a wide range of petrochemical and power applications. Green, Tweed’s Advanced Technology and Engineering teams have developed two solutions for canned-motor and magnetic-driven pumps. These bearings and bushings are suitable for both rotary and static usage.

Scanning unit offers inside view of components

Select 4 at www.HydrocarbonProcessing.com/RS

Precise and reliable oil-analysis method FIG. 3

ARL PERFORM’X XRF spectrometer.

I DECEMBER 2011 HydrocarbonProcessing.com

spectrometer to create a flexible and highperformance solution that is reportedly capable of reaching detection limits of below 0.5 ppm. Using wavelength dispersive XRF (WDXRF), the method is said to offer excellent repeatability and resolution, particularly for light elements such as sodium and calcium. In addition, it allows oils to be measured directly without dilution, reducing sample preparation time, and increasing speed and throughput of analyses. The ARL PERFORM’X system provides dual sample loading and is able to process more than 60 samples per hour, offering rapid and precise analysis of up to 84 elements including sulfur, nickel, vanadium and lead. The instrument’s innovative sample-recognition capability ensures safe and straightforward loading of liquids. Featuring the latest version of the state-of-the-art Thermo Scientific OXSAS software, the instrument can operate with Microsoft Windows 7 to ensure simple and trouble-free analyses.

A new method for elemental analysis of oil samples in the petrochemical industry uses the Thermo Scientific ARL PERFORM’X X-ray fluorescence (XRF)

The microscopy department at Freudenberg Forschungsdienste (Freudenberg Research Services) has started using a computed tomography (CT) scanning unit. Developed on the basis of X-ray technology, CT provides X-ray images from various angles, creating computer-assisted 3D images. These 3D images provide a perfect, faithful insight into the inside of the object being examined. The specified object can be turned and rotated onscreen as required and viewed from all conceivable angles. With the help of CT images, Freudenberg checks whether material samples, prototypes and initial sample components meet stipulated specifications. These images can also be used to identify component damage and analyze its causes. Experts can examine the entire component as a transparent image or can make its plastic covering disappear at the click of a mouse, revealing the integral electric printed circuit board and contacts. Distances, angles, radii, surface areas, or the volume of even the tiniest trapping of air can be exactly calculated. Freudenberg also uses CT scanning to check the even distribution of fibers in nonwovens and to find out whether air has been trapped in cast parts. With CT scanning, Freudenberg is making giant leaps forward in terms of the industrial development of elastomer components and fracture analysis. Select 6 at www.HydrocarbonProcessing.com/RS

Results

Linde has built a history of proven results with over 250 synthesis gas plants and 2,800 air separation plants installed worldwide. As a world class supplier of synthesis gas and air separation plants, Linde Engineering and its subsidiary, Selas Fluid, provide single source responsibility for engineering, procurement and construction of complete synthesis gas and air separation plants. Synthesis Gas Plants: • Hydrogen • Carbon monoxide • H2/CO synthesis gas • Ammonia • Methanol • Synthetic natural gas

Cryogenic Plants - standard or custom designed: • Nitrogen • Oxygen • Argon

Select 60 at www.HydrocarbonProcessing.com/RS

Selas Fluid Subsidiary of The Linde Group

Headquarters: Five Sentry Parkway East • Blue Bell, PA 19422 USA • Tel: 610-832-8797 • Fax: 610-834-0473 Texas Ofļce: 16225 Park Ten Place • Suite 250 • Houston, TX 77084 USA • Tel: 281-717-9090 • Fax: 281-717-9091

www.linde-engineering.com sales@selasĽuid.com

HPI MARKET DATA 2012 YOUR GUIDE TO PROFITABLE PLANNING IN 2012 AND BEYOND Produced by the staff of Hydrocarbon Processing, HPI Market Data 2012 is the industry’s most trusted forecast of capital, maintenance and operating expenditures for the petrochemical, refining and natural gas/LNG industries. Order your copy and gain actionable insight and analysis to drive your planning and global activities towards increased profitability and market share in 2012 and beyond.

Order Online at GulfPub.com/2012HPI or Call +1 (713) 520-4426 Strategic Planning • Market Analysis and Trends • New Growth Opportunities

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

North America Jacobs Engineering Group Inc. has contracts from seven clients in the Alberta oil sands to support steam-assisted gravity drainage (SAGD) and bitumen-upgrading expansion projects. The combined total construction value of the awarded projects is estimated at more than $1.4 billion. Project scopes include engineering procurement and construction (EPC), frontend engineering and design (FEED), fabrication and construction management on various mid- and large-cap projects. The construction values on each project range in value from $15 million to more than $650 million. Technip has been awarded a contract by ExxonMobil Chemical for a grassroots lubricant base-stock facility to be built at ExxonMobil’s integrated refinery and chemical plant complex in Baytown, Texas. The project will provide a new synthetic lubricant base-stock plant, consisting of the process unit, associated pipe rack and product tanks, as well as a pumping and firewater system. The contract covers project management, detailed engineering, procurement and construction. Technip’s operating center in Houston, Texas, will execute this contract, which is scheduled to be completed in 2013. Enterprise Products Partners L.P. has begun commercial operations of a fifth natural gas liquids (NGL) fractionator at its Mont Belvieu, Texas, complex. The new unit is operating in excess of its nameplate capacity of 75,000 bpd, and increases total nameplate capacity at the partnership’s Mont Belvieu facility to 380,000 bpd. Up o n c o m p l e t i o n o f t h e s i x t h fractionator, total nameplate capacity of Enterprise’s Mont Belvieu NGL fractionation facility will increase to more than 450,000 bpd. Service at the sixth fractionator is projected to begin in early 2013, at which time the unit will be fully contracted. The additional capacity provided by the fifth and sixth fractionators will allow Enterprise to process mixed NGLs at its Mont Belvieu complex that are being diverted to Louisiana, as well as incremental volumes from the partnership’s

new Yoakum natural gas processing facility in Lavaca County, Texas, which is scheduled to begin operations in mid-2012.

South America PEMEX has acquired 45 of the latest Model 5100 HD series gas analyzers from AMETEK Process Instruments to monitor moisture levels in natural gas at monitoring stations throughout Mexico. Based on tunable diode-laser absorption spectroscopy, the analyzers provide a noncontact, rapid-response approach to measuring moisture in natural gas. BASF is strengthening its position in the superabsorbent polymers (SAP) market with investments in local production sites in fast-growing emerging markets. In South America, BASF will build a SAP plant in Camaçari, Brazil, with a capacity of 60,000 metric tpy. Production is expected to start in late 2014. In China, BASF-YPC Co., Ltd., a 50-50 joint venture between BASF and Sinopec, plans to start construction of a 60,000-metric-ton SAP plant at its Verbund site in Nanjing in mid 2012. Commercial production is planned for the beginning of 2014.

Europe Statoil has exercised an option of a three-year extension of the minor modifications frame agreement contract with Aker Solutions at the Mongstad refinery, located on Norway’s west coast. Aker Solutions estimates the contract value to be approximately NOK360 million. The original frame agreement at the Mongstad refinery commenced in January 2006 and lasts until the end of 2011. The scope of work includes studies and execution of modifications to increase operational stability, capacity and longevity. A total of 100 people at Aker Solutions’ office in Bergen will work on the Mongstad contract. A time capsule has been laid down in Budyonnovsk, Stavropol Territory, Russia, to symbolize the launch of Phase One construction of a gas processing plant (GPP), part of a gas chemical facility to be built on the industrial site of OOO Stavrolen, an OAO LUKOIL subsidiary.

The facility, which is expected to be built in several phases, will have a primary feedstock of associated petroleum gas from the fields developed by LUKOIL in the Russian sector of the Caspian Sea. In 2015, it is planned to commission Phase One of the GPP with a 2 billion-m3/yr capacity, in addition to a 135-MW unit on the base of a combined-cycle gas turbine and to upgrade the existing ethylene production unit to convert it to process liquefied gases. In 2017, it is planned to commission Phase Two of the GPP with a 4 billion m3/ yr capacity, along with an ethylene production unit with a 225,000-tpy capacity and a polyethylene production unit with a 255,000-tpy capacity.

Middle East Burckhardt Compression has an order from Petroleum Development Oman LLC to deliver one process gas compressor for a new miscible gas injection (MGI) facility in the Sultanate of Oman. The responsible contractor for the project is Worley Parsons Oman Engineering LLC. The process gas compressor for the MGI facility will be installed at the Al-Noor Production Station in the Sultanate of Oman. Delivery of the compressor is scheduled to be in Q3 2012. A subsidiary of Foster Wheeler AG’s Global Engineering and Construction

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 DECEMBER 2011

I 29

HPIN CONSTRUCTION Group has received a contract from Apache Khalda Corp. for the provision of project management consultancy (PMC) services to oversee the front-end engineering design (FEED) for the Qasr Compression Project in Egypt. The project will provide additional compression to the existing facilities at the Qasr gas-condensate field, in the Western Desert, approximately 525 km west of Cairo. Foster Wheeler will provide expertise and personnel to assist Apache Khalda in

the management and administration of the project’s FEED phase, which is expected to be completed at the end of 2011. The State Company for Oil Projects, part of the Iraqi Ministry of Oil, has awarded Axens the basic design and license contracts for the construction of the new refinery in Nassiriya, Iraq. Axens will supply the following process units for the refinery:

• H-Oil technology for the hydroconversion of 52,000 bpsd of vacuum residue (VR) • Prime-D, gasoil desulfurization hydrotreater. The 105,000-bpsd unit will produce ultra-low-sulfur diesel with less than 10 ppm of sulfur • Prime-K, kerosine desulfurization hydrotreater with a processing capacity of 24,000 bpsd • Butane isomerization unit with a process capacity of about 11,900 bpsd. The refinery will have a capacity of 300,000 bpsd of domestic crude oil and will deliver high-quality products mainly for the domestic market. Neste Oil, The Bahrain Petroleum Co. (Bapco) and nogaholding have started commercial production at the new base-oil plant in Bahrain. The joint-venture plant produces premium-quality Very High Viscosity Index (VHVI) Group III base oils for use in blending top-tier lubricants and has a production capacity of 400,000 metric tpy. Neste Oil has a 45% stake in the jointventure plant and the company’s share of the investment cost was €130 million. Neste Oil is responsible for the sales and marketing of the plant’s output, which increases Neste Oil’s total Group III base-oils capacity from 250,000 metric tpy to 650,000 metric tpy. Bapco is responsible for operating the plant, which is located at Bapco’s refinery in Sitrah on the east coast of Bahrain. ABB has won the main automation contract for Sadara Chemical Co., a joint venture (under formation) between affiliates of Saudi Aramco and The Dow Chemical Co. Work is underway on establishing Sadara and the related integrated chemical complex in Jubail Industrial City, Saudi Arabia. When fully operational in 2015, the facility will reportedly be the largest plastics and chemicals production complex ever built in a single phase. The scope of supply includes process automation systems, safety systems, project management, project engineering, commissioning assistance, post-commissioning site support, as well as engineering, operator and maintenance technician training.

Asia-Pacific SCG-Dow Group, a joint venture between The Dow Chemical Co. and SCG, has ramped up the new propylene oxide (PO) facility in Thailand to stable production levels in preparation for the full Select 153 at www.HydrocarbonProcessing.com/RS 30

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Consistent design & quality assurance Anchor-Loc 3 module design features construction from a continuous fold of spun blanket, stainless steel alloy hardware and center mount attachment. The design allows for consistent furnace layout, ease of installation and dependable service life. All components meet or exceed established industry standards assuring the same high quality worldwide.

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HPIN CONSTRUCTION capacity run scheduled for the fourth quarter of 2011. The world-scale plant, located within the Asia Industrial Estates (AIE) site near Map Ta Phut, Thailand, will have a name-plate capacity of 390 kiloton/yr of PO via the innovative hydrogen peroxide to propylene oxide (HPPO) technology jointly developed by Dow and BASF. In December 2010, Dow announced plans to build a propylene glycol (PG) plant at the Map Ta Phut, Thailand, site,

with a production capacity of 150 kiloton/ yr. The PG plant is in the design process, and will use this environmentally advantaged PO from the new HPPO plant. It will reportedly be the largest PG plant in the Pacific area. The AIE site also features a specialty elastomers plant, which announced startup earlier this year, along with power utilities and infrastructure and a new liquids cracker, also jointly owned by SCG and Dow.

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Do you have flows up to 1,400 US GPM (320 m3/hr), RS Series heads up to 3,400 feet (1,000 m), pressures up to 1,500 psig (100 bar), temperatures from 20˚F to 300˚F (-30˚C to 149˚C), and speeds up to 3,500 RPM? Then you need Carver Pump RS Series muscle! Designed for moderate to high pressure pumping applications, the RS is available in five basic sizes with overall performance to 1,000HP. As a standard, with a product lubricated radial sleeve bearing and two matched angular contact ball bearings for thrust, it only takes a mechanical seal on the low pressure, suction side to seal the pump. Optional features include ball bearings on both ends with an outboard mechanical seal, various seal flushing arrangements and bearing frame cooling. These features make the RS ideally suited for Industrial and Process applications including Pressure Boost Systems, Boiler Feed, Reverse Osmosis, Desalination and Mine Dewatering. Whatever your application, let us build the muscle you need!

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CB&I has announced that Lummus Technology has been awarded a contract by China Coal Shaanxi Yulin Energy & Chemical Co. Ltd. for the license and engineering design of two light-olefins recovery units. The plants will be located in Yulin, Shaanxi Province, China. The first unit is expected to start up in 2013. The recovery units, which use breakthrough technology to recover olefins (ethylene and propylene) produced from methanol feed, are each expected to yield 300,000 metric tpy of polymer-grade ethylene and 300,000 metric tpy of polymergrade propylene. In addition, the Olefins Conversion Technology (OCT) from Lummus Technology was selected to upgrade the byproduct produced by the light-olefins recovery units into an additional 165,000 metric tpy of polymer-grade propylene. KBR has a license and process design package contract for a new olefins production unit using the Advanced Catalytic Olefins (ACO) technology. This award represents the first license using this innovative technology, which catalytically cracks naphtha and other straight-run feeds to produce olefins yields that are said to surpass those available from traditional steam-cracking technology. Shaanxi Yanchang Petroleum Yanan Energy and Chemical Co., Ltd., will construct and operate the plant, which will be constructed in Luoyang Village, Fucheng Town, Fu County, Shaanxi Province, China. The ACO converter will have a capacity of approximately 200 kiloton/yr of olefins (ethylene plus propylene). ACO technology is developed jointly by KBR and SK Innovation. INEOS Technologies has licensed its Innovene PP process to the Sinopec Maoming Co., through Sinopec’s international business window—Sinopec International Co., Ltd.—for manufacturing polypropylene homopolymers, random copolymers and impact copolymers. The 200 kiloton/yr plant will be located in Maoming City, Guangdong Province, China. It is the fourth PP license signed by INEOS Technologies in China this year. The Maoming PP plant, due to start up in 2013, will bring Sinopec’s total capacity based on INEOS Technologies’ Innovene PP process to 1.2 million tons of polypropylene. HP Expanded versions of these items can be found online at HydrocarbonProcessing.com.

Select 154 at www.HydrocarbonProcessing.com/RS 32

HPI CONSTRUCTION BOXSCORE UPDATE Company

City

Project

Ex Capacity Unit

Cost Status Yr Cmpl Licensor

Engineering

Constructor

SRPC SRPC Undefined

Ain Sokhna Ain Sokhna Moatize

Sulfur Recovery Unit Treater, SCOT Coal Liquefaction (CTL)

162 tpd 162 tpd 9.5 bpd

U U P

2013 2013 2016

Jacobs Nederland BV Jacobs Nederland BV Uhde

QGC Shenhua Ningxia Coal TonenGeneral Sekiyu K.K. Mitsubishi Chemical S-Oil Corp CPC Corp CPC Corp

Curtis Island Lingwu/Ningdong Kawasaki Osaka Ulsan/Onsan Refinery Kaohsiung Kaohsiung

LNG Sulfur Recovery Refinery Benzene Paraxylene Stripper, Sour Water (2) Sulfur Recovery Unit

3.8 40 335 100 900 69 150

MMtpy tpd bpd tpy Mtpy m3/hr tpd

U U C P C U U

2014 2013 2011 2012 2011 2013 2013

ConocoPhillips Ltd Jacobs Nederland BV

Bechtel Jacobs

SembCorp Marine|Bechtel

Axens Jacobs Nederland BV Jacobs Nederland BV

Samsung Eng

KazMunaiGas Expl & Prod Yara Sluiskil B V Lukoil Lukoil CAD Nishnekamsk Turkmengas

Pavlodar Sluiskil Budennovsk Budennovsk Tatarstan Turkmen

Refinery Urea Polyethylene Ethylene Complex Alkylation, Sulf Acid Sulfur Recovery Unit

EX TO

17.5 3500 225 600 6000 1030

Mtpy m-tpd tpy Mtpy bpd tpd

P C U U U U

2015 2011 2017 2020 2012 2014

Uhde

Stratco Jacobs Nederland BV

Kingston Kingston

Gas Plant Hydrotreater, Kerosene

TO TO

1300 1300

F F

2015 2015

UOP UOP

Mbpd tpd tpd tpd bpd 470 Mbpd 470 MMtpy bpd tpy 893 tpd tpd bpd MMtpy 20000 MMtpy

P U U U F F U F U U U U U U

2017 2013 2013 2013 2016 2016 2015 2016 2013 2013 2013 2012 2016 2013

Axens|Shaw S&W Shell Global Jacobs Nederland BV Jacobs Nederland BV

U U

2013 2014

AFRICA Egypt Egypt Mozambique

ASIA/PACIFIC Australia China Japan Japan South Korea Taiwan Taiwan

1400

EUROPE Kazakhstan Netherlands Russian Federation Russian Federation Russian Federation Turkmenistan

436

Stamicarbon

Vnipineft

LATIN AMERICA Jamaica Jamaica

Petrojam Ltd Petrojam Ltd

7 Mbpd 6 Mbpd

MIDDLE EAST Bahrain Iraq Iraq Iraq Iraq Iraq Oman Oman Saudi Arabia Saudi Arabia Saudi Arabia Saudi Arabia Saudi Arabia Saudi Arabia

BAPCO SRC SRC SRC RKC SRC Orpic Orpic Sipchem Saudi Aramco Saudi Aramco Aramco Services Co Sadara Chemical Co. Sipchem

Bahrain City Basra Basra Basra Karbala Maissan Sohar Sohar Al Jubail Jazan Jazan Jubail Jubail Jubail

Cracker, FCC Sulfur Recovery Unit Sulfur Recovery Unit (2) Treater, SCOT (2) Refinery Refinery Solvent Deasphalting Refinery Vinyl Acetate Sulfur Recovery Unit Treater, SCOT (2) Alkylation, Sulf Acid Complex Ethyl Acetate

Saudi Arabia Turkey

Sipchem/Hanwha Chemical Socar\Turcas Enerji JV

Jubail Izmir

Polyethylene, LD Refinery

EX TO

EX EX

40 184 184 230 140 150 2.5 60 200 541 541 12000 3 100

None 214 bpd

60 2.4

Shaw S&W

Technip Shaw FW|Honeywell UOP

Saipem

Jacobs Nederland BV Jacobs Nederland BV Stratco Exxon Cheml Co

ABB Burckhardt Compression E Tech Engineering and Construction Axens

BOXSCORE DATABASE

Axens

ONLINE

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

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I 33

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PLANT DESIGN AND ENGINEERING

SPECIALREPORT

Optimize capacity for large ethylene oxide reactors Many factors must be considered in fine-tuning unit design B. CRUDGE, B. BILLIG and R. SCHNEIDER, Scientific Design Co., Little Ferry, New Jersey

50 45 40 35 30 25 20 15 10 100

FIG. 1

2.2 ⌬EO 2.5 ⌬EO 3.0 ⌬EO 3.5 ⌬EO 4.0 ⌬EO

150

200 250 300 Volumetric work rate, kg/h EO/m3

Economic service life of EO catalyst.

350

to diameter. Therefore, increasing the tube diameter does not necessarily reduce the total weight of tubes for a fixed catalyst volume. The point of diminishing returns in reactor cost has been reached. Designing for normal operating conditions at steady state does allow increasing the tube diameter as catalyst selectivity increases. However, this must be weighed against the benefits of a robust design with smaller diameter tubes that has a greater ability to handle process disturbances without creating “hot spots” that can damage catalyst and lead to other problems such as deteriorating product quality. CONVERSION AND PRODUCTIVITY

In common industry terms, conversion is often described in terms of ΔEO (moles of EO produced per 100 moles of reactor inlet gas, often in the range of 2 to 4). Productivity is defined as work rate or kg/hr of EO produced per metric ton (weight work

FIG. 2

Photo of a typical large modern EO reactor.

Comparative production cost

Economic catalyst life, months

thylene oxide (EO) is an important chemical intermediate, with annual global consumption of approximately 30 million tpy. Most of the EO is hydrolyzed to produce ethylene glycol (EG), but other important products are also made from EO, including ethanolamines, glycol ethers and various ethoxylates. EO is produced commercially via a vapor-phase reaction of ethylene and oxygen over a silver-based catalyst. This reaction is exothermic, and the unselective reaction to complete combustion is even more so. Conversion must be kept low to ensure high selectivity to EO. Accordingly, heat must be removed from the reacting process gas efficiently within the reactor to allow good control at low conversion. The reactor is effectively a multitubular heat exchanger, with catalyst loaded inside the tubes and a coolant on the shell side. Current commercial reactors use boiling water as the coolant and generate steam directly within the reactor unlike earlier designs that used an intermediate organic fluid, either boiling or non-boiling. A key performance measure is EO selectivity, defined as moles of EO produced in the reactor per 100 moles of ethylene converted. Improvements in catalyst over time have led to higher EO selectivity and accordingly with less heat removed per ton of EO produced. The reduction in heat removal has allowed some relaxation in variables such as productivity and tube diameter, and it became easier to meet certain technical constraints. However, this has allowed the process engineer more scope in improving the process economics with great care. Modern commercial EO reactors have tubes that range in diameter from about 1.5 in. to 2 in. (38 mm to 50 mm) for the outside diameter (OD). Tube-wall thickness is controlled by external pressure from the boiling water side and is proportional

400

FIG. 3

10 12 14 Catalyst-bed height, m

Production costs vs. bed height for EO reactor.

HYDROCARBON PROCESSING DECEMBER 2011

I 35

SPECIALREPORT

PLANT DESIGN AND ENGINEERING

rate) or per cubic meter (volumetric work rate) of catalyst. Volumetric work rate is often in the range of about 150 to 300. Selectivity to EO decreases as ΔEO increases; raw material costs (ethylene and oxygen) increase with ΔEO. Conversely, recycle gas flow decreases along with its associated capital and energy costs, leading to an economic optimum ΔEO. As the catalyst ages, it loses activity and selectivity. The normal practice is to increase reactor temperature to maintain production as activity decreases. In most cases, the catalyst is replaced at or near the end of its economic service life before reaching the reactor temperature limit. The economic optimum life occurs when the sum of average operating and catalyst costs reaches a minimum, although other factors such as periodic maintenance or inspection schedules can frequently affect the timing. The main operating costs are due to ethylene and oxygen consumption, ethylene cost being typically about 70% of the total operating cost. Note that catalyst cost includes not only the cost of buying catalyst but also direct costs of changing catalyst, silver leasing and silver-handling losses. The economic catalyst life depends on the ratio of catalyst to ethylene cost. Fig. 1 shows the results of a typical study on economic catalyst life. Reactor size limits. As plant sizes have continued to increase,

EO reactor sizes have increased dramatically over the last 10 years. The maximum reactor diameter is usually determined less by fabrication limits than by practical considerations of handling, 14 2.2 Δ EO 2.4 Δ EO 2.6 Δ EO 2.9 Δ EO

The first step is determining the catalyst life. The economic catalyst life minimizes the sum of raw materials and catalyst costs and depends on the rate of selectivity loss over time. Actual catalyst characteristics depend on catalyst type; specifics are considered proprietary but general trends are reasonably universal. Selectivity and activity decline are both accelerated by increasing conversion and productivity (ΔEO and work rate). Although the catalyst life is occasionally limited by operating temperature, it is more common to replace catalyst at or near its economic service life. For a new project, a target catalyst life might also be defined as the result of a preferred shutdown schedule based on other considerations such as required inspection intervals or coordination with other plants within a complex. Targeting a specific catalyst life for such 13

8 130

140

150 160 170 Volumetric work rate, kg EO/h m3

180

Optimum catalyst bed height based volumetric work rate.

2.2

FIG. 5

12 11 10 9 8 7 6 2.2

190

FIG. 6

2.4

2.6 Δ EO

2.8

3.0

Optimum catalyst bed height vs. ∆EO.

14 Optimum cat bed height, m

Comparative cost of production

FIG. 4

GENERAL OPTIMIZATION

Optimum bed height, m

transporting and erecting at the plant site. Although site conditions vary, the diameter limit is approximately 28 ft (8.6 m) in a general case. Such a reactor contains about 24 m3 of catalyst for each meter of catalyst-bed height. For example, if the catalyst-bed height were 10 m, the empty reactor would weigh more than 1,000 metric tons and would contain well over 200 m3 of catalyst. At a volumetric work rate of 200, this reactor would produce about 50 tph of EO or 400,000 tpy (400 Mtpy) of EO based on 8,000 operating hours per year. In most cases, large sites are integrated EO/EG processing units that convert most or all of the EO to EG. Plant capacity is usually expressed in terms of monoethylene glycol (MEG), which is produced by the hydrolysis of EO. In a conventional noncatalytic hydrolysis reactor, the EO requirement is approximately 0.8 tons of EO per ton of MEG. So 400 Mtpy of EO produced in a large EO reactor is typically equivalent to 500 Mtpy of MEG. Reactor and plant capacity and costs will later be described in terms of MEG equivalent. Fig. 2 shows a typical large modern EO reactor.

2.4

2.6 Δ EO

Cost of production vs. ∆EO.

I DECEMBER 2011 HydrocarbonProcessing.com

2.8

3.0

13 12 11 10 9 8 400

FIG. 7

450

500

550 600 650 700 Capacity, thousand tpy MEG

750

800

Optimum catalyst-bed height vs. single reactor capacity.

PLANT DESIGN AND ENGINEERING reasons generally leads to a constrained optimum. The catalyst life for a given set of operating conditions sets the average cost of raw materials and catalyst per unit of product. Catalyst-bed height can also be varied, and this essentially involves trading capital vs. power costs. The capital cost of adding reactor volume depends on whether this is accomplished by increasing bed height (tube length) or by adding more tubes. From a capital viewpoint, it is more economical to increase bed height than tube count. However, the reactor pressure drop is proportional to the cube of the bed height for fixed-reactor volume and has a strong effect on recycle compressor power. Catalyst particle size and shape also affect pressure drop. The generally used shape has evolved from spherical to the present hollow cylinder and continues to be subject to further investigation. For simplicity, we will assume that the catalyst characteristics are already fixed and that they focus only on the process variables that can be optimized. Fig. 3 shows an example of the effect of catalyst-bed height on production costs for one set of conditions. The general trend when reactor size is not constrained, as illustrated in Fig. 4, is that the economic bed height tends to decrease with an increasing work rate (smaller reactor) and increase with an increasing ΔEO (lower gas flow). Each set of operating conditions (ΔEO and work rate) defines the cycle gas flow. Reactor pressure drop and, therefore, recycle compressor power are then defined by the catalyst-bed height. All other operating and capital costs associated with cycle gas flow can be calculated. Finally, the cost of production can be calculated over a range of conditions for a particular set of raw material and utilities costs. With four variables being adjusted (ΔEO, work rate, catalyst life and bed height), the resulting cost curve is relatively flat and a modest deviation in any of the variables has only a small effect on the cost of production. Fig. 5 shows production cost vs. ΔEO with the three other variables optimized, indicating a minimum cost at approximately 2.6 ΔEO. The corresponding volumetric work rate is 170, and the single-reactor capacity, for this example, is estimated at 450 Mtpy of MEG at the typical diameter limit. The optimum catalyst-bed height for this case approximates a straight line when plotted against ΔEO and the trend line, as shown in Fig. 6. CONSTRAINED OPTIMIZATION REACTOR SIZE LIMITS

Optimum volume work rate

Economies of scale mean that the unit cost of production decreases as plant capacity increases. As limiting reactor diameter is reached, there is an additional constraint and a choice between either adding a reactor or increasing the individual reactor capacity. Increasing the number of reactors adds capital cost and plot area, while increasing the individual reactor capacity forces an increase in work rate and/or bed height that increases operating costs. The economic optimum bed height is affected by power cost, as expensive power tends to reduce the economic bed height. 290 270 250 230 210 190 170 150 400

FIG. 8

500

600 700 Capacity, thousand tpy MEG

800

Optimum work rate vs. single rector capacity. Select 156 at www.HydrocarbonProcessing.com/RS

SPECIALREPORT

PLANT DESIGN AND ENGINEERING

In one example, using 12Â˘/kWh, raising the reactor capacity above 450 Mtpy is most economically achieved by increasing bed 3.00 Optimum Î&#x201D; EO

2.80 2.60 2.40 2.20 2.00 400

600 700 Capacity, thousand tpy MEG

800

Optimum â&#x2C6;&#x2020; EO vs. reactor capacity.

Comparative, $/ton MEG

FIG. 9

500

height to accommodate 550 Mtpyâ&#x20AC;&#x201C;600 Mtpy, at which point the optimum bed height has reached a maximum and more capacity increase is achieved by using work rate. Further, the economic Î&#x201D;EO tends to increase with capacity, as this limits the increase in cycle gas flow. These trends are illustrated in Figs. 7â&#x20AC;&#x201C;9. Increasing individual reactor capacity, therefore, saves capital but increases operating costs. This is worthwhile up to a breakeven point, beyond which it becomes more economical to add a reactor. In this example, the breakeven point occurs at an individual reactor capacity of 570 Mtpy of MEG, as illustrated in Fig. 10. The process engineer has several variables to adjust to minimize cost of production for a specific case. Î&#x201D;EO, work rate, catalyst-bed height and life are the main limiting size factors for EO reactors. As illustrated here, two EO reactors would be the economic choice for processing capacities over 570 Mtpy. HP NOTE Scientific Design currently offers a single EO reactor for MEG capacities up to 700 Mtpy, constrained by capabilities of the approved fabricators and the usual logistical concerns.

1 reactor 2 reactors

Bill Crudge is the development manager in Scientific Design Co., where he has been employed for 30+ years in various positions. He is mostly connected with the EO process and catalyst. Mr. Crudge holds a BS degree in chemical engineering from the University of Glasgow.

500

550

FIG. 10

600 650 700 Capacity, thousand tpy MEG

MEG cost vs. production.

750

800

Robert Schneider is senior vice president and director of engineering and licensing at Scientific Design Co. He has over 35 years of experience in engineering, catalysts and technology management in the chemical and petrochemical industry. He holds a BS degree in chemical engineering from the University of Louisvilleâ&#x20AC;&#x2122;s Speed Scientific School and an MBA from the University of South Florida.

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PLANT DESIGN AND ENGINEERING

SPECIALREPORT

ydrogen (H2) demand in the refining sector will continue to increase due to the trend of processing heavier and sourer crude oil. Additionally, more stringent regulations on refinery products, such as tighter sulfur and aromatics specifications, will drive H2 consumption. Another influencing factor is the replacement of older facilities to achieve greater efficiency and reliability. The H2 demand may be initially small (1–10 million standard cubic feet per day [MMscfd]) or mid-size (11–20 MMscfd). These requirements are likely to evolve as the project is developed. Therefore, it is necessary to have flexibility in developing the project, and it is important to consider different options in terms of incremental H2 supply. Reformer configurations. There are two basic configurations for a steam methane reformer (SMR) design: “can” and “box.” Each design has its pros and cons and range of applicability, as discussed below. A can reformer consists of a cylindrical, up-fired furnace that houses the catalytic reformer. Fig. 1 shows a picture of a typical H2 plant based on a can configuration. A cylindrical geometry for the reformer furnace provides excellent heat transfer characteristics. Furthermore, it is the most cost-effective design for relatively small H2 requirements, taking manufacturability and transportation into account. These plants are standardized in design and modular in construction, with relatively short field construction schedules. The capacity of a single can reformer can range from 0.2 MMscfd to over 8.0 MMscfd of H2. Capacity can be doubled with a dual can design. The following plant configurations are available to meet specific project requirements:

• In a high-export steam configuration, heat recovery from both flue gas and process gas streams is maximized to generate steam. There is no combustion air preheat. Typically, the amount of export steam is ~100 lb per 1,000 scf of H2 produced. This configuration is attractive when low-cost fuel gas is available.

FIG. 1

Hydrogen plant with a can reformer.

FIG. 2

Hydrogen plant with a box reformer.

TABLE 1. Typical can vs. box reformer Can

Box

Ratio

Output Hydrogen, MMscfd

7.5

44.8

6.0

Export steam, lb/hr

26,000

68,000

2.6

Feed and fuel, MMBtu/hr (lower heating value)

140

706

5.0

Electrical, kW

200

850

4.3

Input

HYDROCARBON PROCESSING DECEMBER 2011

I 41

SPECIALREPORT

PLANT DESIGN AND ENGINEERING

100

Selection criteria. A key consideration for selecting whether

Two cans

120

MMscfd of H2, with the option to combine several trains for increased capacity. Box reformer plants can also be designed for either low operating cost or low-capital, maximum-steam production. These configurations will result in different project-specific waste-heat recovery concepts. The integration of refinery offgas as feed or fuel can be considered to further improve efficiency. A picture of a typical box reformer is shown in Fig. 2. Typical operating performances of can and box reformers are presented in Table 1. In this example, the box reformer capacity is six times larger than that of the can reformer. However, it can be seen that a box reformer is more efficient due to the higher degree of heat integration.

One can

Steam/hydrogen, lb/thousand scf

• In low-energy units, combustion air and reformer feed temperatures are optimized to minimize energy consumption. Energy consumption can be as low as 400 British thermal units (Btu) per scf of H2 produced.1 • High-efficiency units can be designed as a combination of the two cases presented above. A firebox reformer consists of a compact firebox with vertical, top-supported catalyst tubes arranged in multiple parallel rows. The furnace can be customized, prefabricated and fielderected. The compact design is reliable, efficient and easy to maintain. These plants are suitable for 10 MMscfd to over 120

60 Box 40 20 0 0

FIG. 3

60 80 Hydrogen, MMscfd

100

120

140

Can and box reformer capacities overlap.

Attention P I P E S Y S users

the reformer configuration should be can or box is the H2 production capacity. However, there is a certain “gray area” that permits the use of either a can or box reformer (Fig. 3). In such situations, it is necessary to take a close look at the associated steam production and possible future expansion plans. A detailed economic assessment must be carried out, taking into account capital and operating costs and the required plant flexibility. Project schedule, transportation limitations and general site conditions are other important factors to be considered. The ability to simulate, side-by-side, the various configurations and options by combining different technologies or process steps is the key to finding the best overall solution. Conclusion. Selecting a hydrogen plant requires an in-depth assessment of capital and operating costs for both a can and box reformer. Ideally, it is important to engage a company that designs, owns and operates H2 plants based on in-house technology for a range of plant sizes. Such a company has the ability to evaluate the entire gamut of possibilities for H2 production. The ideal technology supplier is one that also owns and operates large industrial gas processing plants. At the Linde Group, experience from operating plants is fed back to the engineering group for continuous improvement of performance and reliability, ensuring the best plant design and overall solution for a given set of circumstances. HP NOTES 1

Based on low heating value

Wolfgang Schoerner is the business unit director for hydrogen and synthesis gas plants in North America with Linde Engineering. Prior to this role, he performed engineering and project management roles for Linde in Germany. He holds a diploma in process engineering from the Technical University of Munich.

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Linde Engineering. He has over 25 years of experience in industrial gases for the energy, refining and chemical industries. He holds a BS degree in chemical engineering from the University of Bombay, an MS degree in chemical engineering from the Illinois Institute of Technology, and an MBA degree from Lehigh University.

Nick Musich is the head of the proposals and process engineering department for Hydro-Chem in Holly Springs, Georgia. He has 15 years of industrial experience, and worked for Mobil Oil and Siemens before joining Hydro-Chem. He has a BS degree in chemical engineering from Georgia Tech and an MBA degree from Kennesaw State University.

PLANT DESIGN AND ENGINEERING

SPECIALREPORT

Investment roadmap: Planning for carbon capture and storage Reducing emissions can be approached the same way as any other new capital project S. FERGUSON, Foster Wheeler, Reading, UK

here is mounting worldwide concern over potential climate change due to anthropogenic carbon dioxide (CO2) emissions. Global power generation and processing industries are CO2 contributors. There are a number of drivers for the process industry to manage and reduce its CO2 emissions. Manufacturing sites have opportunities for additional income from the sale of CO2 credits or to mitigate the risk of penalties imposed by future legislation. Remember: Management of CO2 emissions is growing in importance. To be successful, applying a rigorous investment planning approach to projects that minimize or reduce the carbon footprint of a new or existing facility, or a portfolio of sites is a favorable strategy. Whatever the scale and however far reaching the emission reduction aims may be, applying an appropriate roadmap tool ensures that the best project is implemented to achieved set goals. This article introduces the concept of an investment planning roadmap and outlines the steps involved. Many available technologies to reduce CO2 emission will be discussed. Each step in the investment planning roadmap will be discussed, noting in particular how it can be applied to CO2 emission reduction and carbon-capture projects.

Agree objectives. It is fundamental to define what is desired to be achieved by the project. This can range from a simple plant debottleneck to achieving an overall CO2 emissions target for a global corporation. There may also be a number of stakeholders involved, so this stage is key in ensuring alignment between the parties involved.

then run to determine the best performing configuration on a net present value (NPV) basis. The LP model generated can then also be used to rapidly explore a number of “what if ” scenarios, thus enabling the project’s economic sensitivity to key product or feedstock price variations to be understood. Site selection. The suitability of the

Market analysis. This step is essential

to drive the feedstock, product slate and plant configuration to the optimum economic solution, maximizing the plant margin. Market analysis will determine product demand and price (including CO2 pricing and feedstock price and availability). Plant configuration studies. For

most applications, linear programming (LP) is used to develop a model of the project incorporating product yield, capital and operating cost data for each potential unit operation. The results of the market analysis are also input into the model that is

proposed location (or locations) can be assessed by considering four key factors: • Site—Land availability, ground conditions, structures and obstructions, severe weather protection and earthquake zonal rating • Port—Already existing, dredging requirements, jetty location, existing facilities and suitability of surrounding waterways • Infrastructure—Local and national road network, heavy haul routes, rail network and regional and national airports • Local area—Towns and industry nearby, construction resources, schools

Agree objectives Market analysis Plant conﬁguration study

More detailed reviews

INVESTMENT PLANNING 101

The goal of investment planning is to support companies in selecting the right projects to achieve their strategic goals. This involves determining if the projects are both economically and technically feasible, ensuring the optimum usage of capital and determining the most appropriate timeframe for the project. To reach the best project for meeting the client’s needs, it is necessary to follow a simple but rigorous roadmap process, as shown in Fig. 1.

Site selection

Cost estimates

Develop offsites/ utilities/marine facilities concept Constructability studies

FIG. 1

Economics and ﬁnancial analysis

Recommend conﬁguration development roadmap

The investment planning roadmap.

HYDROCARBON PROCESSING DECEMBER 2011

I 43

SPECIALREPORT

PLANT DESIGN AND ENGINEERING

and emergency services, prevalent health hazards, landfill materials and local labor. This assessment not only looks at the suitability of prospective sites but it also allows the cost of infrastructure development, ground remediation, etc., to be factored into the total cost estimate. Offsites and utilities. The scope of

the utilities and offsite requirements will be based on data from process unit technology providers. Major equipment lists for all utilities, tankage and other offsite requirements will be identified, including intermediate tankage based on the highlevel shutdown philosophy and marine facility requirements.

Constructability studies. It is cru-

cial to consider the constructability during the investment planning stage of a project to determine issues that could impact the design. Such issues include access routes for large or heavy equipment and cost benefits of modular rather than stick-built fabrication. At this stage, a high-level schedule for the full project through to startup can be developed allowing the contracting strategy to be planned. Cost estimates. The cost estimates, based on current market data for the plant location, are based on all of the proceeding stages in the investment planning process. High-level operating costs, including mainte-

■ The roadmap approach to investment planning can

be tailored to meet the needs of any project to ensure that the company’s goals are achieved and the right project solution is developed from the beginning, whether that be a grassroots refinery project, a low-carbon power station or a retrofit to meet new emission performance standards.

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nance, insurance, labor, feedstocks, catalysts and chemical requirements, are developed along with the total capital cost estimate. Economic and financial modeling.

The capital and operating cost estimates are fed into models to ensure that the plant economics are sufficiently robust and achieve the objectives specified by the company at the beginning of the investment planning process. The assumptions within the models should reflect the company’s long-term outlook and consider a number of scenarios. The project’s internal rate of return (IRR) should be considered, along with the NPV to determine the magnitude of the reward for the estimated investment costs. Investment planning process.

Investment planning can be an iterative process, and while changes are frequently made in later design stages, the earlier they occur within the project development then the cost for changes and iteration is substantially lower. A well-conceived investment plan, based on real data and tested against real scenarios gives a sound basis upon which to progress the project. The plan should focus on all the issues affecting the project cost and development—not just the configuration of the process units. GHG MANAGEMENT TECHNOLOGY OPTIONS

A well-developed design, utilizing the optimal feedstocks, energy integrated flow schemes and high-value product slate, is inherently likely to be efficient, minimizing energy demand and waste streams. However, there are almost always some unavoidable energy demands and carbon emissions. This section introduces some key options for greenhouse gas (GHG) emission abatement. This article will focus only on CO2 since it is the largest and most high-profile single GHG. For other industries, it may also be appropriate to consider management of carbon monoxide (CO), methane, nitrous oxide, CFC and HCFC emissions. Greenfield development projects have the advantage of being able to design their processes for reduced CO 2 emissions through process selection and choice of primary energy supply. However, both new and existing plants can consider these options: • Efficiency improvements • Fuel substitution • Feedstock substitution

PLANT DESIGN AND ENGINEERING • Configuration modifications • Carbon capture and storage (CCS). Efficiency improvements. The most

cost-effective approach to carbon abatement is efficiency improvement that can be potentially applied to both existing and planned assets. By maximizing efficiency, the inherent carbon emissions and energy requirements of the process will be minimized. A study of process efficiency will focus on those emissions, which are generated by the process itself, such as CO2 resulting from chemical reaction, as seen in the coal-to-liquids processes. A study of energy efficiency will then look at minimizing the requirement for heat and electrical energy input to the process so that emissions from the utility supply can also be minimized. Onsite power generation can be significantly more efficient than standalone power generation since it can be integrated within the process. A number of potential integration options include: • Power generation from steam raised in wasteheat boilers • Boiler feedwater preheating against process-generated low-grade heat • Cooling water cooling against a cold process stream • Use of onsite fuel sources. Energy integration across the site can reduce the need for energy input to the facility. For example, adding new process units may provide sources for waste heat that can eliminate the need for continuous use of a process heater elsewhere. It is important to consider that the plant must still be able to start up and maintain availability, so the capital expense may not be significantly reduced by energy integration. However, if the plant is able to run for a significant proportion of its operating hours with fewer process heaters in operation, then plant-wide energy demand will be reduced. If both power and heat are needed by the process, then co-generation of electricity and steam (or hot water) in a combined heat and power (CHP) plant should be considered.

conventional feedstocks that are closer to being carbon neutral. For example, if part of the plant includes the gasification of coal or petcoke to produce a syngas, partial or full substitution with an appropriate biomass may be feasible to reduce the total carbon footprint, or increase production without increasing CO2 emissions.

The addition of renewables to supplement the power generation portfolio can increase the diversity of generation and significantly reduce the carbon footprint for utility systems. However, the likely load factor, or the availability, of each type of renewable generation, which could be considered for each location, should be considered. Renewables include wind, solar and, potentially, tidal power, as well as the previously mentioned biomass.

Configuration modifications. Con-

figuration modifications can mean swapping one or several process units for more efficient alternatives or debottlenecking part of the plant to minimize carbon losses to atmosphere. While this is much easier during the design of a new plant, it

Feedstock substitution. In some

applications, it may be possible to wholly or partially substitute a high-carbon content, or a high embedded-carbon feedstock, for Air

ASU

Gasiﬁer/ reformer

Excess water

FIG. 2

Nitrogen Water/steam

Oxygen Feedstock

SPECIALREPORT

Shift reactor

Heat recovery HP MP

CO2 export

SRU and tail gas treating

Sulfur

AGR process

LP steam

HP hydrogen

Pre-combustion flow scheme.

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Fuel substitution. CHP plants can be

highly efficient. However, if the CHP plant can accept a number of different feedstocks, including low-carbon or “carbon-neutral” fuel, such as refuse-derived fuel or a range of locally produced biomass feeds, then the site’s carbon footprint can be further reduced. This also applies to power generation without simultaneous heat generation.

Drying and compression

Ceramic Fiber Mineral Wool

0.000

0.020

0.040

0.060

0.080

0.100

0.120

0.140

Thermal Conductivity (W/m-K) at 600 °C Mean

C1676 ASTM Standard for Microporous

0.160 Data Per ASTM Testing Standards

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SPECIALREPORT

PLANT DESIGN AND ENGINEERING

is not impossible for existing plants. For example, performing pinch analysis on a refinery’s crude preheat train may enable it to be reconfigured for improved total energy efficiency. CARBON CAPTURE AND STORAGE

Most of the mentioned options will be very specific to the location and plant. However, CCS could be applied to almost all processes in some form. CCS is the process of removing or reducing the CO2 content of streams normally released to atmosphere and transporting that captured CO2 to a location for permanent storage. CCS can be applied to a wide range of large single-point sources, such as process streams, heater and boiler exhausts, and vents from a range of high CO2 footprint industries including: power generation, refining, natural gas treating, chemicals, cement production and steel production. There are three main classifications of technologies applied: • Pre-combustion capture • Post-combustion capture • Oxy-fuel combustion capture. Once captured, the CO2 is compressed, dried and transported to a suitable storage location such as a saline aquifer, a depleted oil field (where enhanced oil recovery could be applied) or a depleted gas fields. Each CCS route here is a group of technologies based on similar process circumstances.

Pre-combustion CO 2 capture. A

solid or gaseous feedstock is fed to an oxygen or air-blown pressurized gasifier or reformer, where it is converted to syngas. The syngas is then passed through a shift reactor to increase the hydrogen (H2) and CO2 content of the syngas. This high-pressure (HP), high-temperature syngas is cooled before being washed with a solvent to absorb the CO2 leaving an essentially pure H 2 stream and a CO 2rich solvent stream. The solvent regeneration process then releases a CO 2 stream that can be dried and compressed for export. This process offers a high degree of integration potential as it generates a pure high-pressure H 2 stream, and the syngas cooling train can be used to raise a significant quantity of HP, medium-pressure (MP) and low-pressure (LP) steam, as shown in Fig. 2. Pre-combustion variations include: • A range of coals, petcoke, fuel oils, municipal solid waste and biomass can be used as gasifier feedstock. • Natural gas and light liquid feedstocks can be used with a reformer. • A range of CO 2 solvent removal systems are available along with methyldiethanolamine (MDEA) as well as alternative technologies such as membranes and pressure-swing absorption (PSA). Pre-combustion applications. The

Oxyfuel boiler

Particle removal

Sulfur removal

Cooler/ condenser

Ash

Fly ash

Gypsum

Water

Post-combustion applications.

CO2 Drying and export compression

Lean solvent Stripper

Absorber

Hex

Direct contact cooler

Excess water FIG. 3

Air

Blower Post-combustion flow scheme.

Flue gas recycle

Oxygen

FIG. 4

Nitrogen

ASU

Fuel

Post-combustion CO 2 capture.

Combustion flue gas is cooled by direct water contact before entering a blower designed to overcome the absorption system pressure drop. The flue gas enters the absorption column where it is washed with a physical solvent such as monoethanolamine (MEA). The flue gas is scrubbed of up to 90% of its CO 2 content and is returned to the combustor stack and released to atmosphere. The CO 2-rich solvent is then heated against lean solvent and regenerated in a stripping column. The solvent returns to the absorption column while the released CO2 is dried and compressed for export. The highlight of the post-combustion process is that it is suited not only for new installations but also for retrofitting existing plants, as shown in Fig. 3. Post-combustion variations include: • A range of processes exists utilizing different solvents: MEA, ammonia, sterically hindered MEA and even sea water. • For high-sulfur feeds, the process may be coupled with a flue-gas desulfurization unit allowing the direct contact cooler to be eliminated.

Vent

Flue gas

most obvious application of pre-combustion carbon capture would be a new-build power plant in which the H2-rich stream is combusted in a gas turbine, and the steam raised during syngas heat recovery is used, along with heat recovered from the gas turbine exhaust, in a steam turbine to form a combined cycle plant such as an integrated gasification combined cycle (IGCC) facility. This scheme could similarly be used on a refinery for co-generation of low embedded-carbon hydrogen and heat to be supplied to other refinery units or with a steam turbine to raise power. The acid-gas removal step is typically characterized by its HP syngas feedstock composed of mainly H 2, CO2 and CO. The same acid-gas removal process can also be applied to similar syngases in processes such as steam methane reformer (SMR) H2 production, natural gas treating and ammonia production—even decarbonization of refinery fuel gas could be considered. The pre-combustion scheme can also be used for repowering an existing gas turbine power island or any burner that is capable of switching to decarbonized syngas, with or without burner modification.

Drying and compression

Oxy-fuel flow scheme.

I DECEMBER 2011 HydrocarbonProcessing.com

CO2 export

Post-combustion carbon capture is typically associated with large retrofit power projects or new build, high-carbon footprint power

PLANT DESIGN AND ENGINEERING plants. Post-combustion CO2 capture is a simpler system than the pre-combustion described earlier and it can be bolted on to the back of almost any combustion system. Very large single-point sources, such as power plants, present a challenge in terms of maximum scale up in a single leap, but once demonstrated at scale, this technology has the potential to be used to capture approximately 90% of the CO2 emissions from any carbon-combustion-based power plant (including coal, oil, natural gas, municipal solid waste and biomass). As shown in Fig. 3, the scheme has already been demonstrated for many years in smaller applications, for CO2 production used in the food and chemicals industries. Some smaller scale plants may already be at an appropriate size to capture CO2 from point sources similar to the size of refinery fired heaters. Depending on the specific site, postcombustion carbon capture could be applied to a number of refinery flue gas sources (such as fired heaters, fluid catalytic crackers, hydrogen production units) with the cooler, blower and absorber located as close as possible to each source (or group of sources) with the rich solvent, then pumped to one or multiple solvent regeneration units and one or multiple compression units. This offers flexibility to fit in around the plot plan of existing process plants as much as possible.

tion unit and sealing the system against air ingress can allow any boiler or fired heater to be converted to oxy-firing. Careful consideration must be made with respect to design temperatures and pressure of the existing boiler or heater when applying oxy-fuel carbon capture as a retrofit. Oxy-fuel carbon capture aims to increase the partial pressure of the combustion flue gas by effectively eliminating the large volume flow of nitrogen found in systems fired using air as their oxidant. This is done to remove the process step in both the preand post-combustion carbon capture flow scheme in which CO2 must be separated from a stream largely composed of other gases. This results in smaller sized equipment and fewer processing steps. However, an air separation unit must also be included. INVESTMENT PLANNING FOR CARBON FOOTPRINT REDUCTION

A carbon footprint reduction project requires each of the steps identified in the investment planning roadmap just as in any other project. Applying the investment planning approach ensures that the objectives are well defined, the project is appropriate for the market, the configuration of the solution

SPECIALREPORT

is optimal; the costs are well defined, and the economic and financial case is robust. Agree objectives. In this stage, the exact targets at which the project is aimed and the scope to which they apply should be determined. For example, a company may wish to reduce the CO 2 emissions across its full portfolio of process plants to meet an internal company goal, or it may wish to focus on one location in which there is a specific driver, such as an emissions trading scheme. Likewise, the project may be intended to develop in stages, such as a refinery planning to reduce its carbon emissions by a set amount annually over a number of years. As for any investment project, there will be a number of stakeholders involved, and it is important to keep them all positively engaged, particularly if a new technology such as CCS is to be applied. Non-governmental organizations (NGOs) and local residents may be concerned about the new technology and require reassurance that risks to the environment and safety are mitigated responsibly; they may also wish to know what other options were considered during the project development.

Oxy-fuel combustion CO2 capture.

In this process, the fuel is combusted with oxygen from an air separation unit. The temperature in the boiler is moderated by recycling a portion of the flue gas back to the combustion chamber. The flue gas passes through particle removal by an electrostatic precipitator, sulfur removal by limestone scrubbing, and water removal by cooling and condensation. The remaining flue gas has a high CO2 concentration that can then be purified, dried and compressed for export. Steam from the boiler is used to generate power via a steam turbine, as shown in Fig. 4. Oxy-fuel variations include: â&#x20AC;˘ A range of fuels can be used in an oxyfuel flowscheme. â&#x20AC;˘ A similar scheme has also been proposed for the conversion of gas turbines to substitute oxygen for air. Oxy-fuel applications. The most discussed application of oxy-fuel carbon capture is for new-build, large-scale power production. However, adding an air separaSelect 161 at www.HydrocarbonProcessing.com/RS

SPECIALREPORT

PLANT DESIGN AND ENGINEERING

Market analysis. There is a wide range

of available schemes aimed at incentivizing high-energy efficiency and reduced CO2 emissions that augment the natural economic drivers for the process industry to minimize waste and maximize quality and output. Understanding what incentives are available in the region in which a project will operate could enable the project to be significantly more economic if it can take advantage of such schemes. Examples include regional emissions trading and grants for new or clean technology demonstrations. Likewise, the reverse can apply, particularly with the currently uncertain future in terms of GHG emissions regulation where taxes or levies may be brought into force in the near future. Being at a transition point in legislation can make it particularly difficult to predict and select a firm basis for the investment, thus making market analysis particularly invaluable for this project. There may be the opportunity to utilize captured CO2 for enhanced-oil recovery or enhanced-gas recovery, either by the project company, or sold over the fence to a neighboring operator, thereby generating a significant additional revenue stream. A refinery may be well placed for this application once

commercial movement of CO2 by ship has been more widely demonstrated. Understanding the market and legislative context into which the project will fit will help mitigate the risks of being locked into expensive carbon penalties or high electricity or fuel prices while identifying any additional revenue streams not traditionally encountered. Plant configuration studies. Once

the project objectives are defined and the applicable market and legislative framework are understood, then potential process routes and technologies can be identified. LP is extremely useful for determining the optimum configuration for energy efficiency and CO2 emissions minimization. The ability to run a number of “what if ” scenarios, once the LP model has been developed, allows a picture of the project’s sensitivity to volatile fuel, electricity or carbon prices to be understood. It also allows the cost benefit of building in relatively capital-intensive, carbon-reduction options to be quantitatively assessed as well as assessing how to configure the plant for optimal conversion of feedstocks into highest margin products. Just as the product yield and energy demand of each process unit is built into

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I DECEMBER 2011 HydrocarbonProcessing.com

the LP model, so can be the CO2 emitted, immediately enabling the minimum CO2 emissions case to be identified. If the minimum emissions case is not economic without carbon capture due to a high anticipated carbon emissions penalty, then carbon capture units can be added to the model in the same way as any other process unit to understand if this improves the project margin despite the additional capital and operating cost. Example. A hydrogen production unit (HPU) in a refinery produces a significant portion of the total site CO2 emissions and it can be the ideal candidate unit for a relatively quick win in terms of CO2 emissions reduction. A number of capture techniques can be applied: A. Pre-combustion capture on HPU syngas between the shift reactor and the PSA unit. B. Post-combustion capture on the HPU reformer itself (where the reformer is fired on PSA tail-gas). C. Post-combustion carbon capture on other refinery fired heaters, fired on natural gas. In this particular study, both of the hydrogen unit carbon capture options (A and B) delivered significant CO2 emissions reductions at a lower project cost (both capital and operating) than applying postcombustion capture to the other refinery fired heaters on the site. Site selection. While the market analysis will have dealt with locally applicable drivers and the price and availability of primary fuels and feedstocks, there are several additional points to be considered with respect to site location. Most critically, for a project to even consider CCS as an option for CO2 emissions management, a suitable storage location and transport route to that location must be identified in the earliest stages of the project. While some projects may be conveniently located close to a depleted oil or gas field, others may be comparatively “stranded” until such a time as regional infrastructure, such as a CO2 collection and transportation hub, becomes available (if this is foreseeable within the planned lifetime of the plant). Options such as CO2 shipping can also be considered, although alternative technology selection or alternative site location may be the more appropriate choice. The site selection stage should also consider if renewables would be advantageous, particularly for coastal sites, sites with strong prevailing wind, high solar potential, or access to geothermal energy for water preheating.

For both new and existing sites, availability of extra plot space should be considered. Many countries are requiring that power generators prove that their new plant is carbon capture ready (CCR), which usually translates to ensuring there is sufficient additional space onsite to locate the capture plant. Offsites and utilities. Since the

requirements for utilities and offsites are specific to the process configuration, these will be developed specifically for the configuration selected and included in the LP model. If carbon capture is to be included in either the initial design or added at a later date, the major utility requirements for CCS (i.e., power and cooling requirements for CO2 compression and heating requirements for solvent regeneration) will need to be included in the design capacity of the utility systems and/or integrated with the other process units where possible. Facilities for solvent storage and loading will also be required as suitable routing and metering for CO2 export facilities. Constructability studies. For a CCS

project, the physical size of the equipment—particularly for the large-scale post-combustion scheme—presents real challenges in terms of ensuring constructability. In the largest cases envisaged (largescale power generation schemes), the factor determining the number of CO2 absorption trains required is fixed by the capacity of the largest possible physical size of vessel that can be shipped to the site, proposed to be a 20-m-diameter column. Panel constructed square absorbers may avoid this limitation, in which case, other equipment items such as heat exchangers and direct contact cooler become the limiting train-size items. For the solvent regeneration part, the train size is likely to be determined by the maximum physical size of reboilers that can be installed around the stripper to meet its needs. The constructability studies will also determine the plot space required for equipment laydown, along with the heavy lift cranes and other logistics of moving these large items of equipment to their final site locations. Cost estimates, economic and financial modeling. Economic model-

ing, when designing for minimum carbon footprint, may be made more complex than other projects due to considering a greater number of scenarios and the need to do additional sensitivity analysis to certain key variables such as impact of various legislation,

BORSIG

PLANT DESIGN AND ENGINEERING taxation and subsidy regimes. Likewise, the impact of a particularly uncertain value revenue stream such as CO2 should be explored in depth to determine the scenarios in which different project options become economic. OPTIONS

This article has outlined the method and justification for following an investment planning roadmap to ensure that the optimum project is developed. With an investment planning roadmap, project objectives are well defined; the project is appropriate for the market; the configuration of the solution is optimal; the costs are well defined and the economic case is robust. This rigorous and staged process is particularly critical for projects in which there are a wide range of unknowns (such as future CO2 price or penalty and volatile fuel prices) coupled with an array of potential mitigation options. Breaking the investment planning process into manageable stages allows a clearer picture to be drawn and recorded with respect to which options have and have not been considered and how they compare against each other and against the overall objectives. HP ACKNOWLEDGMENT Updated version of the original presentation at the Green Forum, Oct. 4–5, 2010, London, 1st Green Refining & Petrochemicals Forum. LITERATURE CITED Carter, D., “Investment Planning—A roadmap to success,” The Chemical Engineer, July 2009. 2 Bullen, T. and M. Stockle, “Integrating Refinery CO2 Reduction into your Refinery,” Hydrocarbon Processing, November 2008. 3 Carter, D. and E. Petela, “Developing and Implementing the most appropriate energy management strategy,” ERTC, November 2008. 4 Bullen, T. and M. Stockle: “CO Infrastructure 2 Development: CCS Options,” PTQ, October 2008. 5 Stockle, M., “Optimising Refinery CO2 Emissions,” ERTC, November 2007. 6 Ferguson, S., “Energy Security and Greenhouse Gas Management,” Lovraj Kumar Memorial Trust Annual Workshop, New Delhi, November 2009. 1

Suzanne Ferguson is a chartered chemical engineer with an MEng (Hons) degree in chemical engineering from the University of Surrey. She joined Foster Wheeler in 2004 and has worked on refinery and hydrogen unit frontend engineering design (FEED) projects and performed basis of design, FEED and EPC-phase dynamic simulation for LNG projects. She has also worked on power island design at Foster Wheeler’s Italian operation in Milan. Ms. Ferguson is now Carbon Capture Technical head in Foster Wheeler’s Business Solutions Group, UK, where she has worked on a range of CCS studies, FEED and pre-FEED projects.

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SPECIALREPORT

Knowledge transfer: A primer for major capital projects Improve transfer strategy across the project supply chain to achieve smooth end-user takeover A. MAGARINI, A. ALTAMURA and R. ROBERTSON, Technip Italy, Rome, Italy

mong the risks inherent in engineering, procurement and construction (EPC) projects for grassroots facilities and large facility upgrades, transferring operational responsibility to the end users poses significant challenges. Seasoned EPC contractors manage this risk with a project-customized knowledge transfer strategy directed at all levels of the facility’s workforce. When the strategy is managed as a core feature of project execution, knowledge transfer can mean the difference between on-time, under-budget plant hand-over vs. a hand-over period marred by delays, cost overruns and initial operation incidents, all affecting plant integrity and profitability. The goal of knowledge transfer could not be more clear-cut: to create the pool of specialized knowledge, skills and troubleshooting abilities, which underpins superior individual and team performance and, in turn, the plant’s business mission and operating objectives (Fig. 1). Boosted in recent years by a host of environmental, safety and reliability issues, knowledge transfer has evolved from a piecemeal, low-priority line item to a core feature of the project life cycle, alongside the cornerstones of EPC. A new generation of project managers values the benefits of a strategy in which skill gaps of end users are mitigated through technology-supported knowledge transfer. These efforts methodically build individual and team competence as project activity morphs from EPC through to commissioning and hand-over. For plant owners, the operating and maintenance skill sets put in place through a cohesive knowledge transfer initiative are critical to operating success, and often yield substantial savings in post-takeover technical assistance, offspec product write-offs and unplanned maintenance stoppages affecting plant availability. Scoping the knowledge transfer. When project managers strategize the hand-over phase for a major capital project, they focus on three areas, which will determine the process plant’s operating viability: • Well-designed processes, equipment, control systems and health, safety and environmental (HSE) safeguards • A proficient workforce characterized by leadership, trained and qualified personnel, a strong team ethic and accountability • Reliable operating and maintenance (O&M) manuals and procedures. These three areas—plant, personnel and procedural knowhow—are the foundations of the knowledge transfer strategy; they will underpin the successful, safe hand-over of the completed

facilities. How effectively the project management team leverages these inputs to produce the required O&M excellence in the enduser workforce will affect the success of plant hand-over and the project’s conclusive profit margin. Early in project execution, the future end user and the EPC contractor sit down together and jointly shape the content and timing of the project’s knowledge transfer strategy. It should detail the coordinated sequence and schedule of expertise-transfer activities designed to generate the knowledge, skills and problem solving abilities needed by the plant workforce to confidently manage commissioned plant assets at takeover. In devising the strategy, contractor and owner can tap into a range of knowledgerich contractual services and systems that embrace four categories: • Knowledge and skill creation such as training and capacity development programs at and away from the plant jobsite. • Dynamic learning and learning-support tools like the operator training simulator (OTS), computer-based training (CBT) systems and the learning management system (LMS). • Knowledge capture, storage and distribution—Process plant O&M documentation such as operating and maintenance manuals and customized IT applications including plant information management system (PIMS) and asset management system (AMS) Process plant O&M mission: t Long-term t Medium-term Division/dept objectives

Individual and team performance

Key job tasks

Knowledge

FIG. 1

Skills

Attitudes

Job knowledge, skills and attitudes wired to the plant’s O&M mission are the basis for knowledge transfer strategy. HYDROCARBON PROCESSING DECEMBER 2011

I 51

SPECIALREPORT

PLANT DESIGN AND ENGINEERING

• Knowledge collaboration and sharing—The intense formal and informal exchange of information and ideas between contractor and end-user project teams during engineering, procurement, construction, and commissioning. When these contractual inputs are harnessed in a concerted plan to build individual and team capacity, visibly tagged as key milestones on the project schedule, and orchestrated for delivery as the project unfolds, the net result is a robust body of O&M knowledge and skills in the owner’s workforce—and a leading factor in smooth plant hand-over within contractual schedule and budget. To drive the knowledge transfer strategy and to generate momentum across the project life cycle, perceptive project managers designate a knowledge transfer specialist to lead the delivery of all knowledge transfer inputs, and liaise permanently with key stakeholders—the EPC team, technology licensors and critical equipment vendors, key subcontractors, and end-user management. With an ideal background in plant technology, training and human resources (HR) management, the knowledge transfer specialist coordinates the planning, development, delivery and evaluation of all knowledge transfer activities hand-in-hand with takeover-critical HR sourcing, recruitment, training and job placement.

by building a profile of the human organization required to successfully manage, operate, maintain and technically support the physical plant equipment and systems. The EPC contractor, as primary agent for the plant’s supplied processes, equipment and control systems, is well positioned to work with the end user to analyze the quantity/quality of managers, supervisors and skilled technicians who take over the site’s O&M needs. The results from this shared analysis, which includes the specialized inputs of process licensors, equipment and control system vendors, and site technical managers can be structured as an organizational blueprint (Fig. 2). This blueprint forms the basis for plant employee recruitment and training, and their competencebased placement in the plant environment during advanced construction and pre-commissioning activities. The organizational analysis answers important questions about plant workforce configuration, technical and core competencies, reporting hierarchy and lines of communication, which are categorized as: • Process operations. What is the optimal segmentation of plant processes and equipment into operating and control areas? How will equipment geography and design affect operator workload and numbers? What criteria are used to determine the staffing requirements for distributed control system (DCS) PRIORITY ONE: PLAN THE WORKFORCE console operators? Which sophisticated units and systems require No process plant hand-over can succeed without a competent increases in control room and field operatives? What operations workforce to safely apply O&M knowledge and skills, and take and maintenance shift criteria will be implemented? custody of the completed facilities. Knowledge transfer begins • Plant maintenance. How will the plant maintenance organization be affected by process complexity and equipment accessibility? What are the staffing requirements for shift-based Plant manager maintenance inside process units? How will plant ergonomics, maintainability and redundancy designs affect maintenance Production HSE & Fire workforce numbers? Which maintenance planning team Team crafts and turnarounds will be supported by external contract labor and consultants? Operation Maintenance Tech support • Management and support areas. manager manager manager Which staff positions sign off the policies and procedures that govern operations and maintenance? What are the contributing Shift operations HSE shift Mech HSE Chief lab Process sup’t managers engineers maintenance sup’t engineers chemist operational roles of technical support staff? Which personnel are accountable for hazMachinery engineers Area coordinators Shift chemists ard recognition, safe work planning, field Area coordinators Process engineers Specialty Rotary specialists verification, and measurement of compliTechnologists technicians Static equipment Quality Process Power and ance against safety standards? Which staff specialists control area “A” utilities Civil/bldg specialists Environment Engineering positions make up the in-plant fire brigade? sup’t shift sup’ts shift sup’ts sup’t sup’t The final organization chart and Shift leaders Shift leaders Plant inspectors accompanying job descriptions—modeled I/C maintenance Environmental Project engineers DCS operators DCS operators NDT specialists sup’t to reflect the plant’s technical complexengineers Planners/schedulers Field operators Field operators Disposal Civil engineers ity, culture, and business—are the basis specialists Instr/elec/mach Instr engineers Inspectors engineers for the plant owner’s campaign to recruit Area coordinators Offsites and Process Shift Estimators/cost Control/IT engineers depot area “B” maintenance the HR organization for a grassroots facilcontrollers Instr/SW/HW shift sup’ts shift sup’ts teams Doc’n specialists specialists ity, or fill in HR gaps for an existing plant expansion. The organization chart helps Shift leaders Shift leaders Team coordinators DCS operators DCS operators Rotary specialists management highlight HR “hot spots”— Training Elec Field operators Field operators I/C specialists ofﬁcer areas requiring a special skill focus (e.g., maintenance sup’t Electrical specialists complex process technologies, sophistiHSE trainers cated equipment and controls) and current Electrical engineers Process trainers Area coordinators workforce deficiencies in key knowledge Maint. trainers Electrical specialists and skill areas, which, if not addressed, can FIG. 2 Typical workforce blueprint for a process plant organization. pose barriers to the scheduled takeover of the completed facilities. 52

I DECEMBER 2011 HydrocarbonProcessing.com

Since 1968

Select 72 at www.HydrocarbonProcessing.com/RS

Job descriptions. They are a crucial resource for knowledge transfer because they specify unambiguously the required outcomes of HR recruitment and training processes. Assembling job descriptions is a straightforward and enlightening process, producing a calculated blend of: • Technical competencies specific to each position. These include detailed job task procedures, key interactions with other personnel, and HSE skills when and where they are required in the job. • Core competencies such as knowledge of processes, equipment and control systems, problem-solving ability, analytical thinking, business acumen, teamwork skills, negotiating ability, adaptability, etc. Each completed job description is an effective multi-tool to screen end-user candidates for training and employment, develop and deliver training material, and test personnel for competent job performance. With the plant organizational blueprint in hand, the EPC team and end-user managers work closely to plan and time the sourcing, selection and mobilization of plant personnel in line with project milestone dates and schedule of knowledge-building activities at and away from the plant jobsite. TRAIN FOR TAKEOVER COMPETENCE

Training’s role for the EPC project is to develop the individual and team capabilities, which underpin the plant’s operating and maintenance missions. To succeed, training must focus on closing the knowledge and skill gaps. Guided by this principle, effective process plant training hinges on six key steps (Fig. 3): 1. Define job performance requirements. Accurately describe the technical competencies of personnel who will staff the completed installations; produce detailed job descriptions of key job groups such as shift leaders, DCS operators, maintenance specialists, lab analysts and HSE engineers.

Current performance

Required performance

2 Timeline 4

5 6

FIG. 3

Work environment

Training goals bridge the gap separating trainees from their required job knowledge, skills and problem-solving abilities.

2. Quantify the learning gap. For each job group in the plant organization, carefully assess the real or expected entry level ability of recruited personnel against their job descriptions; document the learning gap that separates employees from the job competencies they will need at plant takeover. 3. Design training sequences. Bridge the learning gap quantified in Steps 1 and 2 by matching instructional content to the job performance requirements and individual capabilities of owner trainees; for each job group, set up a progressive timeline of instructional units leading to on-job integration during plant commissioning; support learning sequences with validated plans of instruction, O&M training materials, and training facilities; accurately screen candidate instructors (licensors, vendors, contractors) for the depth of subject matter competence and instructional expertise. 4. Conduct training at learners’ level and pace. Explain training objectives at the start of each session and link these clearly to job performance requirements so that trainees fully understand HYDROCARBON PROCESSING DECEMBER 2011

I 53

SPECIALREPORT

PLANT DESIGN AND ENGINEERING

why they are being asked to make the effort to acquire knowledge and skill; present learning material in a structured, logical sequence that leads naturally to stated objectives; use presentation aids that appeal to as many senses as possible, and to emphasize major learning points; use learning activities that are metaphors of traineesâ&#x20AC;&#x2122; job requirements, such as case studies, team projects, and in-tray exercises; involve the group in as many activities and interchanges as possible; conduct regular questioning to stimulate trainees, to create a climate of participation, and to stretch traineesâ&#x20AC;&#x2122; ability; include frequent recall, practice and impromptu testing during each learning session. People learn best by seeing, doing, failing and practicing until they succeed. 5. Test for retention and use. During instruction, test personnel to measure their retention of job knowledge, skills and attitudes and their ability to perform actual job tasks and troubleshoot work problems; diagnose learning difficulties and initiate corrective actions; where required by law or critical to safe, effective performance, formally test and certify learnersâ&#x20AC;&#x2122; ability to perform job procedures according to approved criteria. 6. Build bridges into the workplace. As construction completion and conditions permit, transfer trained personnel from the training setting to the work environment where they try out and gradually master newly learned skills under close supervision and coaching. The heart of the training process is the transfer of knowledge, skills and attitudes (KSAs) directly linked to each traineeâ&#x20AC;&#x2122;s job competencies. This tangible link between job tasks and learning content is crucial. It shows learners unambiguously the concrete work outcomes that training will lead to (Fig. 4) and reinforces their motivation to attain demonstrable, measurable job skills. Thanks to the profusion of available digital technologies, this transfer of KSAs to owner personnel can now take place in many formats which include CD-ROM, learning management system (LMS), local area network (LAN) based and web-based learning, instructor-assisted operator training simulator (OTS) training and instructor-led practical training. The final learning blend is a smart balance of training techniques and tools supporting the creation of requisite competencies needed within the takeover timeframe. Training scenarios. Training for a grassroots complex or large plant upgrade unfolds on two tiers: â&#x20AC;˘ Tier 1. Develop technical expertise and leadership ability in key supervisory personnel like unit managers, process shift leaders, maintenance supervisors and technical support engineers. â&#x20AC;˘ Tier 2. Build core job skills and problem-solving abilities in teams of operations and maintenance specialists who make up the bulk of the plant workforce. Competency: Fire prevention and containment Learning objects Job task Prevent/contain ďŹ res in process area

}

t 'JSF IB[BSET BOE UIFJS QSPQFSUJFT LOPXMFEHF PG

t &YUJOHVJTIJOH UFDIOJRVFT TLJMM

t 1SP BDUJWF TBGFUZ BXBSFOFTT BUUJUVEF

Competency: Plant preventive maintenance Job task Learning objects $BSSZ PVU QSFWFOUJWF NBJOUFOBODF PG FRVJQNFOU JUFNT

FIG. 4

}

t &RVJQNFOU EFTJHO BOE DPOTUSVDUJPO LOPXMFEHF PG

t 4BGF NBJOUFOBODF QSPDFEVSFT BOE UPPM VTF TLJMM

t .FUIPEJDBM BOE BDDVSBUF CFIBWJPSBM OPSNT BUUJUVEF

Job tasks and their underpining knowledge, skills and attitudes form the basis of technical learning content.

I DECEMBER 2011 HydrocarbonProcessing.com

End-user trainees are a mix of experienced and inexperienced personnel, and the EPC contractor will factor this into the planning of training content, delivery and durations. One technique for exploiting the variable skill backgrounds frequently present in trainee groups is to pair more experienced personnel with novice learners in a â&#x20AC;&#x153;buddy systemâ&#x20AC;? that enhances the role of more expert trainees while ensuring that less expert learners are not left behind in the training process. Tier 1 training slated for key managers and supervisors typically comprises: â&#x20AC;˘ Overseas training at the design offices of process technology licensors and the EPC contractorâ&#x20AC;&#x2122;s main engineering hub. Trainees receive intensive instruction in plant processes and equipment, the design and operating parameters, special operating procedures and related HSE issues. â&#x20AC;˘ Training at operating process units closely resembling in design and magnitude the licensed process units under supply. Trainees tap the knowledge of expert operators by observing and shadowing them as they operate, control and troubleshoot plant processes and execute standing operational and safety procedures â&#x20AC;˘ Training at the manufacturer workshops of critical plant items including rotary equipment, key package units, plant control systems and electrical machinery. Trainees receive valuable learning in equipment design, construction, operation and troubleshooting, maintenance and repair. Training is not restricted to building technical knowledge and expertise. End-user supervisors have the opportunity to form relationships with their licensor, vendor and EPC contractor counterparts with whom they will later cooperate closely onsite as plant facilities are mechanically completed, commissioned and performance-tested. Training is scheduled to give end-user personnel exposure to the learning opportunities available at design offices, similar process plants and manufacturer shops, but not so early in the project cycle that owner engineers retain but a vague memory of their learning as plant testing and commissioning get underway onsite. As the skill set of managers and supervisors also includes directing and motivating employees to produce results, their training curriculum should also incorporate shared learning in effective leadership, strategic management and communications. Another worthy form of Tier 1 knowledge transfer is the â&#x20AC;&#x153;engineer residencyâ&#x20AC;? by a team of plant-owner engineers at the EPC contractorâ&#x20AC;&#x2122;s engineering hub during project engineering and procurement activity. For this knowledge-transfer segment, the EPC contractor develops a detailed work-study and interface program with the dual aim of transferring relevant design and procurement knowledge to the owner engineers, and benefiting from their networking experience in the owner organization and with their regionâ&#x20AC;&#x2122;s regulatory environment. During the residency, owner discipline engineers (representing project management, major engineering disciplines and construction management) work closely with their contractor counterparts, exchanging information and ideas, reviewing and commenting project deliverables across several releases, and brainstorming design alternatives and solutions. Focal points covered during the residency include: â&#x20AC;˘ Project cycle and work breakdown, deliverables structure and schedule. â&#x20AC;˘ Design and engineeringâ&#x20AC;&#x201D;Process units, utilities and offsite facilities, civil and structural, PV&HE and piping, electrical, instrumentation and control systems, mechanical/packages.

Select 72 at www.HydrocarbonProcessing.com/RS

• Procurement cycle, specifying and purchasing materials and equipment, subcontracting, control of procurement and vendors, procurement software, inspection and expediting. • Construction organization, resources, management and scheduling. • HSE issues—Safety procedures, HAZOP studies, environmental impacts and constructability. • Planning and scheduling—Phases of network scheduling and control, project timing and time/resource constraints, planning software techniques. • Controlling project costs—Control budget, documenting costs, predicting trends and overruns, cost reporting and software techniques. Knowledge is delivered in many formats: formal seminars, roundtable sessions and discussion groups, meetings to review deliverables and design alternatives, and visits to licensor and vendor premises that focus on outstanding design issues and problems. The sum result is a transfer of need-to-know knowledge to core end-user personnel who will later work with contractor’s specialists onsite during construction and commissioning. Training end-user O&M teams. Workforce training on

Tier 2 is the large-scale instruction of operating and maintenance teams who will staff the completed installations, based on the HR quantity/quality profile of the plant organization blueprint. Tier 2 training concentrates on developing hands-on knowledge and problem-solving skills among key job groups such as control room personnel and maintenance specialists. In line with established job description and recruitment criteria, training follows a competency-based approach to develop teams that are highly skilled, flexible, and adaptable to change. Training is delivered at the plant jobsite and regularly includes:

Since 1968

• Operating teams. Formal, structured instruction in process and equipment design, operating parameters and operational procedures sandwiched with hands-on OTS-based practice in “live” process startups, control and troubleshooting, followed by supervised transfer to the plant control room and process blocks during pre-commissioning and commissioning where trainees’ span of control gradually increases as they practice and master job tasks and solve problems relating to process and equipment control and optimization. • Maintenance teams. Craft specialization training in mechanics, instruments and electronics by expert maintenance discipline instructors, enhanced with vendor specialist training in critical machinery and control systems as these are inspected, tested and commissioned onsite. Within each job-specific group under training, the competency-based approach dictates the quality and quantity of learning provided: • Outside operator training incorporates process systems, principles of mechanics and instrumentation, practical process equipment operation, local process control, equipment monitoring and care, and operative maintenance. • Control console operator training will emphasize chemical and physical processes, distributive control systems, advanced process control, IT management, console-specific procedures and monitoring, and process and plant troubleshooting. • Maintenance specialist training will develop the expertise needed for preventive and corrective equipment maintenance but also for major repair jobs during scheduled outages or turnarounds and emergency shutdowns, with equipment vendor support where required; training will also develop the close cooperative relationships needed between operating and maintenance teams to ensure plant availability and maintenance priorities. HYDROCARBON PROCESSING DECEMBER 2011

I 55

SPECIALREPORT

PLANT DESIGN AND ENGINEERING

Safety first. Safety during training is critical. Before receiving

specialized job instruction, all plant trainees undergo extensive induction in HSE and emergency procedures, job hazard analysis and the risks inherent in training and working in a process plant environment. An expert training engineer reporting to the EPC project manager leads all training and evaluation activities comprising development, validation, delivery and skill testing, and works closely with end-user management to ensure the timely mobilization of recruited O&M personnel for training. The training engineer also ensures that logistical requirements such as training facilities, access permits, ground transportation and personal protective equipment (PPE) are seamlessly in place as needed. An approved set of standardized templates are used throughout the training process to record plans of instructions (POIs), learning content, attendance-in-training, testing and evaluation, and training completions.

and reinforce acceptable work behaviors in individuals and teams, providing valuable, immediate feedback. • Self-assessment within work teams. The plant’s future O&M operatives critically evaluate their own work behaviors, taking on the responsibility of discharging and improving their tasks and enhancing their trouble-shooting effectiveness, with and without the intervention of contractor instructors and coaches. This evaluation tier brings owner O&M teams to the brink of autonomous facility management. A fourth tier of evaluation worth mentioning is the regulatory evaluation mandated for those job roles or job procedures requiring formal certification and compliance audits of housekeeping and safety practices performed by public safety and health authorities. The EPC team uses these ongoing audits as tools to underscore the knowledge and skill requirements and attitudes needed for effective owner takeover. Dynamic OTS. Among the high-tech supports available for

Testing and evaluation during knowledge transfer.

No knowledge transfer can succeed without continuing evaluation of the strategy’s success in shifting O&M know-how to the plant owner’s workforce. Systematic evaluation provides the data to correct and reinforce the knowledge transfer strategy, and opportunities to motivate employees and improve communications across work teams. Valid evaluations determine employee placements and degree of autonomy in the end-user’s site organization as plant activity transitions from E&C to commissioning and startup. Knowledge-transfer strategies include three progressive tiers of evaluation techniques: • Competence-based testing during formal training. This verifies the degree of knowledge and skill attained by plant personnel; testing includes written and oral examinations to test individual knowledge and skill, on-the-job testing to evaluate individual and team based skills, and emergency drills to test team responses to a variety of in-plant events and incidents. • Coaching during pre-commissioning and commissioning by competent job performers. This largely informal process enables EPC and owner supervisors to observe, direct, correct

Printer

OTS system interface

PIMS system interface Instructor Simulation Field station station station Plant data network FIG. 5

PIMS gateway

Printer

Sample layout of OTS.

I DECEMBER 2011 HydrocarbonProcessing.com

Plant data network

process operation and control training, the dynamic OTS is the high-tech tool of choice for effective process instruction and human error reduction. The OTS emulates process and control system behaviors dynamically in a setting closely resembling the control operator’s actual work environment and conditions. Trainees receive dynamic hands-on instruction in a full range of normal and transient operating conditions, and often make remarkably fast and reliable transitions from training to the real-world operating environment. OTS trainee workstations represent the human-machine interface (HMI.) It mimics the control operators’ future work environment, merging faithful duplications of process and plant dynamics with identical screen graphics and keyboard features. With this enhanced look and feel, the OTS gives operating teams (shift supervisors, DCS operators and field operators) a “live” experience in operating and troubleshooting complex processes in a wide range of operating scenarios—normal startups and shutdowns to rare plant upsets and recovery procedures during serious malfunctions. The OTS instructor directs training sessions from an instructor console (Fig. 5) at which the instructor can start up/shut down simulated process models, create scenarios and activate malfunctions, freeze and run simulations and adjust their speed, and monitor trainees’ operating performance in real time, giving corrective instruction and pointers to reduce errors and improve work safety. Using these monitoring and evaluation features, the OTS instructor can reliably forecast on-the-job operator performance and help end-user management make informed decisions about critical operator assignments post-training. Far-reaching as they are, OTS benefits go beyond operator training for the initial plant startup. The OTS can provide other important advantages as a performance support tool; these include: • Providing refresher training to operators whose skills may degrade due to the lack of rare upsets and emergency events in highly instrumented plants • Running periodic certifications of control operators to lower insurance premiums and promote the plant’s HSE compliance profile • Enabling process and startup engineers to try out control procedures (new operating conditions, modified control loops, multivariable control applications, etc.) and optimize standard operating modes, thus dramatically reducing the likelihood of stress damage to the real plant

Select 72 at www.HydrocarbonProcessing.com/RS

SPECIALREPORT

PLANT DESIGN AND ENGINEERING

human controllers. O&M documentation underpinning the knowledge-transfer Start pre FAT strategy covers three major categories of with DCS Issue Start interface 1st FDS End site work Hand over plant activity: Post Receive accepted post FAT Start OTS FAT • Plant operation and optimization, DCS Start OTS system ﬁx OTS model post I-FAT including analytical requirements devt Start w/devt Installation, DB kick off including validation OTS FAT HW • Maintenance planning and implesat. system meeting Pack, FDS reviews and mentation ship instructor • HSE plans and procedures. training These incorporate a wealth of information and guidance for plant operation and maintenance, and also for other key areas FIG. 6 OTS delivery schedule is anchored to process and DCS deliverables and quality. of plant management and control: HSE planning (information on hazards and • Aiding instruments and process engineers as they design actions to prevent or contain them), environmental safeguarding controls for a new process and tune existing control loops, and (O&M work instructions reduce risks of toxic release and specify checking the DCS database for consistency and stability response sequences when incidents do occur), manpower train• Observing the dynamics of process units under a variety of ing (manuals are the unquestioned knowledge basis for O&M new operating conditions. instruction) and plant engineering (process optimizations rely on With an OTS price tag for a grassroots refinery typically precise narratives of plant operation and maintenance). exceeding $1.5 million, several key aspects need close attention Access to O&M documentation by trained owner personnel when specifying an OTS for a cluster of process units: is crucial for an effective turnover. Operators need updated refer• OTS scope-of-work. This is a critical step, entailing definience data on process and equipment technology, process hazard tion of the OTS process models’ scope and size, boundaries and data, operating procedures and safe work practices. Maintenance accuracy, installed functionalities and simplifications that do not technicians need maintenance and servicing manuals, structural negatively affect core simulations such as the emergency shutdown plans and safe maintenance guidelines. Without ready access to (ESD) sequences. The final OTS scope is a balanced trade-off these, owner personnel cannot develop the independent takebetween content, performance functions and cost, and has the charge mentality required for successful takeover. consensus of the plant owner’s operations managers. The EPC contractor’s commissioning team plays a pivotal • OTS vendors. These are accurately screened for in-house role in developing O&M documentation and guiding end-user design expertise, reference projects of similar complexity and personnel in their effective use during: magnitude, reference experience of current design staff and com• Workforce training and integration onsite petitive pricing. • Dry plant check-out • Functional design specification (FDS). This is developed • Preparation of pre-commissioning and commissioning proby the OTS vendor and details the agreed OTS design basis cedures comprising custom process models, stimulated or emulated • Plant pre-commissioning and commissioning operator stations, instructor facilities and supporting software. • Plant startup, line-up and upset management The EPC contractor reviews and approves the FDS for accuracy • Performance testing and compliance with the OTS purchase order (PO) and techni• Planned and emergency shutdowns and recoveries. cal specifications. • OTS engineering in compliance with plant process, Complete article available online at HydrocarbonProcessing.com. equipment and I/C design. The project deliverables schedule, ensures OTS ready-for-use in line with the operator training Andrea Magarini is the head of start up, training and maintenance department schedule. at Technip Italy, Rome. He has experience in process engineering, construction com• OTS factory and jobsite acceptance testing. End-user missioning and start up, training and maintenance. He worked in the field of refining, training in correct OTS use, maintenance, and configuration LNG, petrochemicals and lube oils. Previously, he was employed at STP, Altran and Snamprogetti. Mr. Magarini holds an MS degree in chemical engineering from the and OTS as-built updating, along with end-user training in University of Rome, “La Sapienza” and is a registered professional engineer in Italy. correct OTS use, maintenance and configuration, and OTS as-built updating. Alessandro Altamura is the head of Technip Italy “customer training, OTS The OTS ready-for-use schedule is crucial. The project OTS and operating manuals” section. After achieving an MS degree in chemical engineerengineer must ensure that all design and control system inputs ing in 2000, he conducted many process simulation studies both for engineering support and for OTS development for Comerint. In 2002, he started to focus on the needed to complete process models and control simulations are “knowledge transfer” key-values, becoming responsible (2008) for the following available enough in advance (Fig. 6) to have the OTS up and areas: operating manual development, operator training simulator supply managerunning per the operator training schedule at the plant jobsite. ment and customer training Projects design. Process data provision to OTS vender

O&M DOCUMENTATION FOR KNOWLEDGE TRANSFER

Knowledge transfer cannot be effective without reliable plant O&M documentation to guide end-user teams through the phases of workforce training, plant pre-commissioning, commissioning and performance testing. O&M documentation is the interface between plant processes/equipment and their 58

I DECEMBER 2011 HydrocarbonProcessing.com

Ray Robertson, certified performance technologist, is a senior learning consultant with the Technip Group for whom he has designed and site-managed enduser capacity building projects on five continents for industrial investments in oil & gas, petrochemicals, manufacturing and food processing. He regularly conducts workshops on instructional design, competency certification, and learning project management and writes extensively on performance issues for specialized periodicals. He is a graduate of the University of London.

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PLANT DESIGN AND ENGINEERING

SPECIALREPORT

Manage risks with dividing-wall column installations A simple auxiliary configuration and an extensive modeling study can mitigate the implementation risks of DWCs J. SHIN, S. LEE and J. LEE, LG Chem Ltd., Daejeon, South Korea; and M. LEE, Yeungnam University, Gyeongsan, South Korea

ividing-wall columns (DWCs)—also called partitionedwall columns—have been introduced as an attractive option to reduce energy consumption and capital costs in distillation processes. However, risks and worries associated with the implementation of DWCs hamper the expansion of this technology in conservative process industries. This article introduces a real implementation case in which a conventional column was upgraded to a DWC. It also discusses how the risks in DWC implementation can be mitigated by establishing contingencies and predicting the column performance via modeling. BACKGROUND

Since Wright first introduced the concept of the DWC1 in 1949, over 90 commercial-scale applications have been reported.2 However, the industrial implementation of DWCs has been slow, despite the potential benefits and promising results of this technology. Most reported DWC applications have been attributed to a few leading companies, namely BASF, Dow and UOP. 3 Recently, other companies have begun to consider this technology more seriously, although only large companies with sufficient research and development (R&D) capabilities can evaluate and benefit from such complex, energy-saving technologies. The slow acceptance of DWCs is also due to industries’ entrenched preference for proven methods over potentially risky new technologies. Hydrocarbon plant operators generally prioritize stable production over energy savings. Such caution is necessary, and it is important that any new system be able to demonstrate its suitability before it is implemented. This article examines the implementation of a DWC in an LG Chem Ltd. plant, with emphasis on the practical risks of the installation. Extensive modeling studies were used to mitigate implementation risks, check for human error, and demonstrate the industrial suitability of DWCs. Plant specifications prior to DWC installation. Fig. 1 outlines a 2-ethylhexanol (2-EH) production plant, in which butyraldehyde (BAL) is synthesized from propylene and synthesis gas by the oxo reaction. Normal butyraldehyde (NBAL) and isobutyraldehyde (IBAL) isomers are then separated through an isomer process, and the NBAL is converted to 2-EH by aldol condensation. Crude 2-EH is then generated from EPA and

hydrogen by hydrogenation and purified to a final 2-EH product in an alcohol purification unit. The alcohol purification unit consists of two sequential simple distillation columns: a heavies-cut column and a lights-cut column. Column-targeting studies were performed to improve the energy efficiency of the alcohol purification unit. The studies showed that energy consumption could be reduced by 5% with a preheater that recovers heat from the second column’s bottom stream. Modification of the column’s interior with high-performance packing did not yield significant energy savings. A preliminary feasibility study for installing the DWC was conducted. The DWC configuration shown in Fig. 2—a retrofit of the existing column—was proposed. Simulation of this DWC IBAL

Propylene Syngas

Oxo unit

Isomer process

NBAL

Aldol unit

EPA H2

Alcohol puriﬁcation unit

Hydrogenation

FIG. 1

2-EH production.

Heavies-cut column

Lights-cut column

Lights

Heavies-cut column

Lights-cut column Lights

Crude 2-EH

Heavies FIG. 2

2-EH

Heavies

2-EH

Process flowsheet for 2-EH purification before (left) and after (right) DWC retrofit. HYDROCARBON PROCESSING DECEMBER 2011

I 59

SPECIALREPORT

PLANT DESIGN AND ENGINEERING

configuration showed that considerable energy savings could be achieved at a reasonable installation cost. Field engineers and plant operators reviewed the feasibility study, but some were skeptical about the DWC’s performance and reliability. Further technical evidence was needed to convince the field engineers of the DWC’s merits and to ensure safe operation before the installation of the DWC. DWC with conventional operation. DWCs involve sim-

ple concepts that should be familiar to chemical engineers. However, plant operators are more familiar with conventional, twoproduct column systems. A DWC column may also be required to switch between DWC operating mode and conventional operating mode, due to unforeseen circumstances or maintenance. Therefore, dual operation was incorporated into the DWC to allow for conventional operation as a contingency (Fig. 3). The operating mode of this DWC can be switched by varying the valve positions (Table 1). Additional features required for the

B1 FIG. 3

FIG. 4

E1,2

A DWC capable of two operating modes.

Three-dimensional models of the DWC.

I DECEMBER 2011 HydrocarbonProcessing.com

F1,2

contingency mode are vapor-equalizing lines, feed nozzles and several block valves that are also useful for maintenance. In DWC mode, the side product is withdrawn from the middle of the main section. Liquid flow from the overhead is directed to a liquid-splitting device (i.e., a reflux splitter), and the two liquid streams are then introduced into the prefractionator section and main section. Vapor- and liquid-splitting ratios in the dividing-wall section are the most important variables in DWC operation.4 Liquid splitting can be easily adjusted using the reflux splitter, making it suitable as a manipulated operating variable. Vapor splitting, however, is determined by the column’s interior and the pressure drop of each dividing-wall section, making it a design variable that cannot be freely adjusted after column installation. Therefore, the column’s internal design must be based on an accurate prediction of the hydraulics in the partition section to ensure that the vapor-splitting ratio follows the design. Ensuring the integrity of the column requires close collaboration with internal suppliers and other vendors at every stage of the DWC design. During contingency operation, the side draw is not used and liquid flow from the column overhead directly enters each partitioned section. A specially designed distributor can allow dual operation by evenly distributing liquid into each partitioned section. The difference between the pressure drops of the prefractionator and main sections should be minimized, and the two sections should act as one in the contingency mode. An equalizing vapor line must be present to alleviate pressure differences. It is possible to predict pressure drops in the partitioned section with hydraulic correlations from the column internal suppliers and through rigorous computational fluid dynamics (CFD) analysis. Simple correlation is generally sufficient to calculate the pressure drop of each section to reasonable accuracy. Also, as the arrangements of nozzles and pipes are complicated and potentially confusing, a 3D visual model was created to help reduce human error in construction (Fig. 4). Predicting column performance. Installing a partitioning wall does not guarantee energy savings. The benefits are system specific and depend on the properties of the separation system and the required products. Potential benefits should, therefore, be rigorously estimated through an extensive case study. Simulation software can be used to design a DWC and to predict its performance using built-in, thermodynamic physical properties. For an existing column, plant operations data can be used to reassure the reliability of the physical and thermodynamic property methods selected. Design variables—such as total number of trays, feed and product locations, and liquid- and vapor-splitting ratios in the partitioned section—can be determined by simulation. Construction costs should be estimated with regard to site-specific concerns. The concept of a DWC with dual operating modes can be realized without greatly increasing the installation cost. Before implementing the concept, the performance of each operational mode of the column was predicted through rigorous modeling. Fig. 5 shows column temperature profiles for the two operational modes. In DWC mode, the temperature profile of the prefractionator section differs from that of the main section, while they are identical in contingency mode. The vapor-splitting ratio in the partitioned section is uncertain and cannot be adjusted freely once the column is installed, while the liquid-splitting ratio can be easily manipulated during opera-

PLANT DESIGN AND ENGINEERING 156 Temperature, °C

tion. Therefore, to assess the effects of unexpected performance deteriorations, sensitivity studies are required that examine possible variations of the actual vapor-splitting ratio. Temperature profiles are shown for vapor-split ratios in DWC mode (Fig. 6) and contingency mode (Fig. 7). In the example column in Fig. 6, performance was not greatly affected by changing the vaporsplitting ratio. Product quality remained within the product specifications for the vapor-splitting ratios tested. The effects of changes in feed composition, the liquid-splitting ratio and other operating variables were modeled to ensure that performance and product quality could be maintained within acceptable ranges. Nominal operating conditions were set and reviewed before startup. The column’s temperature profile during operation was well-matched to the simulation results.

154 152 150 Main (design) Main (contingency) Prefractionator (design) Prefractionator (contingency)

148 146 144 1

11 13 15 17 19 21 23 25 27 29 31 Number of ideal stages

156 Temperature, °C

154 152 Main (VSL-1:1-2␣) Main (VSL-1:1-␣) Main (VSL-1:1) Main (VSL-1:1+␣) Main (VSL-1:1+2␣) Pre. (VSL-1:1-2␣) Pre. (VSL-1:1-␣) Pre. (VSL-1:1) Pre. (VSL-1:1+␣) Pre. (VSL-1:1+2␣)

150 148 146 144 142 1

Foundation reinforcement, instrumentation. In this

installation, the bottom section of the existing column could be used. The only problem related to the implementation was ensuring sufficient structural strength for the increased height and

Temperature profiles for DWC design and contingency modes.

FIG. 5

Turndown ratio. DWCs generally lack operational flexibility.

If a plant is not operating with a normal load during startup or shutdown, the column should be operated with a considerably lower feedrate. DWCs use less energy, implying that vapor and liquid loadings are lower than in conventional columns. With lower loads, internal flows can be increased by raising the boil-up and reflux rates, at the cost of increased energy use. The example column was successfully operated at below half of the normal load without showing problems during startup.

SPECIALREPORT

FIG. 6

9 11 13 15 17 19 21 23 25 27 29 31 Number of ideal stages

Temperature profiles for different vapor-split ratios in DWC mode.

Buzau - ROMANIA phone: +40 238 725 500 www.betabuzau.ro

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I 61

SPECIALREPORT

PLANT DESIGN AND ENGINEERING

Temperature, °C

CONCLUSION 155 154 153 152 151 150 149 148 147 146

Main (VSL-1:1-2␣) Main (VSL-1:1-␣) Main (VSL-1:1) Main (VSL-1:1+␣) Main (VSL-1:1+2␣) Pre. (VSL-1:1-2␣) Pre. (VSL-1:1-␣) Pre. (VSL-1:1) Pre. (VSL-1:1+␣) Pre. (VSL-1:1+2␣)

FIG. 7

9 11 13 15 17 19 21 23 25 27 29 31 Number of ideal stages

Temperature profiles for different vapor-split ratios in contingency mode.

TABLE 1. Stream connections for DWC and contingency modes Contingency DWC mode mode

Nozzle

Description

Total liquid draw-off to reflux splitter

Open

Closed

B1, B2

Inlets from reflux splitter

Open

Closed

Side product draw-off

Open

Closed

Feed for the DWC mode

Open

Closed

E1, E2

Vapor-equalizing line

Closed

Open

F1, F2

Feed for the contingency mode

Closed

Open

weight of the column after retrofitting. To evaluate the possibility of reusing the original column, its flooding factor was checked to analyze its hydraulic performance. Since the vapor load is generally proportional to the required reboiler duty, the existing column section, including the internals, could potentially be used in the retrofit. If modification is necessary, the first option is modifying the internals, which does not require major changes to the column’s bottom section, including the reboiler and piping. To reduce downtime, the rest of the column section was produced in the shop and welded to the bottom section at the plant site. The installation work was completed within 12 days. The increased number of temperature sensors helped engineers monitor the column operation and detect any abnormal behavior. The retrofitted column consisted of seven packing sections, with two to four temperature sensors installed in each. The Plant Information System (PIS) and the Distributed Control System (DCS) screens were modified, along with additional instruments and control loops. Operator training and troubleshooting. The con-

cepts of the DWC, its operational modes, and the new equipment were explained to the plant operators, as were the startup and shutdown procedures. The operators understood the concept and benefits of DWCs, and their questions were clarified with 3D models and simulation results. The help of operators and plant engineers was essential to the project’s success at all stages, from the preliminary study to the actual implementation. Thorough and clear communication reduces unnecessary time losses and risks during implementation. In most cases, process engineers who design DWC columns are not aware of site-specific concerns. 62

I DECEMBER 2011 HydrocarbonProcessing.com

A DWC with two operating modes was designed and studied to minimize operational risks and to ensure a safe retrofit to an existing column. The DWC was then installed in an LG Chem Ltd. plant, and it has been operating successfully since startup. Computer modeling was an important factor in establishing the DWC, as these columns require extensive analysis. The existing conventional column was easily upgraded to a DWC through the addition of a partition wall. This upgrade was achieved in an acceptable period of time. The proposed DWC arrangement can be used in the revamp of other single conventional columns, allowing for significant reductions of energy expenses at a reasonably low capital cost. The idea of a dual-mode DWC alleviates plant personnel’s concerns about the potential risks of DWC implementation and thus contributes to the greater application of DWCs in the hydrocarbon industry. HP ACKNOWLEDGMENT This research was supported by an Energy Efficiency and Resources grant from the Korea Institute of Energy Technology Evaluation and Planning (KETEP), funded by the Korean Government Ministry of Knowledge Economy. LITERATURE CITED Wright. R. O., “Fractionation Apparatus,” US Patent 2,471,134, May 1949. 2 Asprion, N. and G. Kaibel, “Dividing wall columns: Fundamentals and recent advances,” Chem. Eng. Prog., Vol. 49, 2010, pp. 139–146. 3 Adrian, T., H. Schoenmarkers and M. Boll, “Model predictive control of integrated unit operation: Control of a divided wall column,” Chem. Eng. Prog., Vol. 43, 2004, pp. 347–355. 4 Lee, S. H., M. Shamsuzzoha, M. Han, Y. H. Kim and M. Y. Lee, “Study of structure characteristics of a divided wall column using the sloppy distillation arrangement,” Korean Journal of Chem. Eng., Vol. 28, 2011, pp. 348–356. 1

Joonho Shin is a process systems engineer at LG Chem Ltd. in South Korea. He began his professional career as a design and control specialist at SK Engineering & Construction in 1997. Dr. Shin’s industrial experience has focused on modeling, optimization and control of chemical and petrochemical plants since 2002. He holds a BS degree in chemical engineering from Korea University, and an MS degree and PhD in chemical engineering from the Korea Advanced Institute of Science and Technology (KAIST).

Sungkyu Lee is a process systems engineer at LG Chem Ltd. in South Korea. He holds BS and MS degrees in chemical engineering from Chungnam National University. He has worked on modeling, optimization and control of chemical and petrochemical plants since 2002.

Jongku Lee is the vice president of LG Chem Ltd. Research Park in South Korea. He holds a BS degree in chemical engineering from Seoul National University, and an MS degree and PhD in chemical engineering from KAIST. Since joining LG Chem in 1994, he has worked on numerous process modeling and optimization projects. Currently, he is in charge of LG Chem’s process modeling and solutions group and is performing research in the areas of energy saving and sustainability in chemical plants.

Moonyong Lee (corresponding author) is a professor at the school of chemical engineering at Yeungnam University in South Korea. He holds a BS degree in chemical engineering from Seoul National University, and an MS degree and PhD in chemical engineering from KAIST. He worked in SK Energy refinery and petrochemical plants for 10 years as a design and control specialist. His current areas of specialization include modeling, design and control of chemical processes.

PLANT DESIGN AND ENGINEERING

SPECIALREPORT

Preserving knowledge: Keys to effective lifecycle management Plant information resides in many locations throughout the facility; capturing it is a challenge J. LIPPIN, Honeywell Process Solutions, Bracknell, UK

ork smarter; that is the mandate for every manufacturer in the 21st Century. In the face of tougher global competition and shrinking pools of expertise, many plants are realizing they need to maximize infrastructure investments and squeeze every last drop out of their assets to remain competitive. This realization is rapidly driving the adoption of innovative technologies that can offer maximum productivity and full enterprise visibility, among other things. But there is another realization that not every manufacturer has picked up on. Working smarter means much more than investing in the latest automation technologies. It means ensuring that companies understand the full, long-term impact these new technologies have across the enterprise when they are adopted, as well as, how they fit with their current systems and may integrate with future technologies that have not even been considered.

Cradle-to-grave issues. Lifecycle management (LCM) is

about to become a bigger part of the manufacturing lexicon, and a key ingredient to working smarter and staying competitive. Attempting to standardize an LCM program can squander the potential benefits it can deliver. Like automation systems then, the secret to developing a true LCM strategy is adapting it to an organization’s unique and changing needs. To that end, one aspect often underemphasized is the understanding and appreciation of the intellectual property that is often embedded in automation assets. By learning to identify and protect intellectual property, manufacturers can glean valuable information that can, in turn, be used to optimize operations, extend the life and value of assets and truly maximize the capabilities of their plants. And by truly appreciating the value of it, manufacturers can better understand the potentially huge costs associated with transitioning to a new automation infrastructure, because it may require them to fully recreate this intellectual property and embed it into a new environment.

in the many different systems that tie into operating assets. This knowledge, however, can also be difficult to keep track of because control-system intelligence and embedded work processes inevitably evolve over the many years of an assets’ life cycle. So where to start? Where is intellectual property found in a plant? Plants must start in the most critical places that intellectual property can be found, within the process control systems, graphical user interfaces and standard operating procedures (SOPs). The control system. The heart of the overall automation system is the control system; it is truly the building block from which all others interact with when it’s time to make process changes. The control strategies that run a plant and are embedded in these systems are the result of many years of accumulated experience and knowledge. The information is fine-tuned to understand interactions between many different physical systems that it controls. For instance, in the refining and petrochemicals industries, the very accurate control of a multi-port rotary valve can simulate the counter-current flow of a liquid feed over a solid bed of adsorbent in a paraxylene (PX) separation process. This enables feed and product to enter and leave the adsorbent bed continuously, at nearly constant compositions, and achieving separation of PX from a mixed-xylene feed, with a purity of over 99.9%. This is the key building block for the entire polyester industry. Graphical user interface (GUI). Over the past decade,

much work has been done to improve the user interface to con-

KNOWLEDGE VALUE: UNDERSTANDING INTELLECTUAL PROPERTY

One of the first steps in working smarter is figuring out where the smarts actually sit. Over the past few years, technology has evolved to the point where automation systems can incorporate vast amounts of knowledge, especially concerning recurring issues or known process bottlenecks. This enables faster and better decisions, and it frees resources to focus on more value-added tasks. The knowledge can be embedded in many different forms, and HYDROCARBON PROCESSING DECEMBER 2011

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PLANT DESIGN AND ENGINEERING

trol systems, as it forms a core part of a decision-support system. It can aid operators in preventing and minimizing the impact of unplanned plant disturbances, and improving plant performance. The Abnormal Situation Management (ASM) Consortium for instance has developed a novel approach to operator interface design, using a structured multi-window format to improve console operators’ awareness to changing plant situations so that abnormal situations could be identified early, and averted, or mitigated. The structured format includes the explicit use of color, navigational strategies, windows management and coordinated display associations to achieve this. From ASM research, it was determined that a good operator interface design was needed to integrate process alarms, process and trend information cohesively together. To do this effectively, the interface “requires the anticipation of the operators’ needs in understanding the plant’s process interactions, their interactions with computers, and with other individuals in the workplace.” The success of human-centered operator interfaces requires a deep understanding of the affected process, as well as the tasks and work processes that govern its control. This understanding is then embedded into the system design, and can lead to sizable benefits. In one study, using a simulated environment for an actual chemical plant, “improvement was measured by early detection of the upset (an average of 38% faster), completion time (an average of 41% faster), completion success (an average of 25% more successful completions.) While these results are impressive, even more meaningful was that this study successfully translated those improvements into an economic benefit as well, estimating that these human performance improvements could save a given plant approximately $1,089,800 CAD per year. Standard operating procedures. SOPs are, in effect,

same way that plants must retain a thorough understanding of the process functions and the logic behind the HMIs, they must also retain the knowledge behind any and all SOPs that dictate how operators must interface with the processes. Frequent changes are made in day-to-day operations of distributed control system (DCS), safety systems, programmable logic controllers (PLCs), field instrumentation databases and advanced solutions. To effectively manage automation information and engineering configuration data across all levels of automation, companies can deploy change-management solutions that track and document changes. Continuously aggregating and contextualizing the configuration databases, programs and user interface changes simplifies the visualization and the management of information in automation systems. This makes for effective operations and protects ongoing improvements to intellectual property. On the surface, the most obvious reason a plant would need to take inventory of the intellectual property embedded in these three areas is for planning a migration or other technological transition. But having this knowledge is not only beneficial for a migration—it’s critical for optimizing processes and operations. One of the best examples that illustrates how this knowledge can help a plant work smarter can be seen in advanced process control (APC). Ongoing advanced control and optimization of plant operations ensures responsiveness to inevitable changes in business demands through close linkages with planning, scheduling and management functions. The process knowledge tied to specific assets and applications can be used to inform debottlenecking strategies that in turn can be automated within APC. Implementation of these solutions enables complex work processes, touching many disciplines to be incorporated into a single application that can react to process changes instantaneously, and ensure maximization of benefits on an ongoing basis.

combinations of the control systems and GUIs. In much the TOOLS FOR CAPTURING ‘TRIBAL KNOWLEDGE’

The most difficult intellectual property to capture falls under the category of “tribal knowledge.” That is, a certain group of people who operate an asset may understand this property as the result of spending many years working with the asset. This knowledge, however, does not live in any manuals or workflows—rather, it lives in their heads. The methods for sharing this information naturally are not very formal, leaving a lot to become lost. Another related challenge that has exacerbated this issue is the well-documented high staff turnover in the process industries. Plenty of skilled workers are leaving the industry (mostly due to retirement) while not enough are signing up. While the mostpublicized consequences of this turnover problem have been loss of process knowledge and rise in potential safety incidents, another overlooked consequence is the resulting inability to keep track of change information. These are consequences that have implications all the way to the company’s bottom line. New technological advancements, though, are making it possible to finally capture this “tribal knowledge” and put it to use that ultimately streamlines operations and uncovers new process efficiencies. Embedded knowledge technologies—procedural operations. In an environment where plants are losing skilled

workers, using technology to capture and retain their knowledge is gaining momentum as an effective solution. By integrating automated procedure technology into control systems, companies are attempting to make critical procedures, particularly those that 64

I DECEMBER 2011 HydrocarbonProcessing.com

PLANT DESIGN AND ENGINEERING are infrequently performed, more repeatable and manageable such as startup/shutdown procedures, grade/mode change and catalyst preparation/regeneration. The goal is for plants to operate more safely, efficiently and reliably to preserve both employee and plant well being and revenue. The automation of SOPs delivers automated steps and computer-directed instructions to the operator. This allows the company to preserve their intellectual property by capturing best practices, while ensuring operator safety with consistent execution of operating practices, and documenting that the operating practice was properly executed with all exceptions documented. The control system captures each action taken during the procedure and records it for later analysis. In addition, the procedure events can be viewed with relevant process conditions, providing much-needed context for troubleshooting and continuous improvement efforts that help plants run better in the future. Required changes can then be updated in the procedure to ensure it consistently reflects current best practices the next time it is executed. Effective procedural operations are most commonly applied to: • Shutdown and startup procedures that are infrequently executed • Production grade changes (grades, rates and equipment) that require moving the plant from one mode of operation to another • Bringing the plant to a safe holding point that may be resumed by operations, or subsequently to shut down the plant • Cyclic planned activities such as regeneration, pump changeover or furnace decoking.

SPECIALREPORT

regulations. Overall, keeping this documentation up to date is a good way to ensure consistent performance over time from an automation system and to get the most out of it in the long run. Training. To ensure that knowledge value is institutionalized,

and can be sustained despite staff turnover, a well-designed training program is needed. This can be seen in two parts: training related to local knowledge and know-how, and training related to technology that provides access to, and leverages, knowledge and know-how. Regarding the former, the use of things like Post-It notes requires no training whatsoever. But computer-based documentation systems, of course, do—especially for new employees. Training for “read-only” users can be brief, and one-time. But training for those responsible for adding plant information to these systems must be comprehensive. Contributor training should be hands-on, so that employees leave training with a level of confidence that comes from having used the system. Initial training for both end users and contributors should be captured for the use of new employees, and it should be followed up by periodic refreshers, particularly to highlight new collections of information and new features, and to share and reinforce best practices. Training for control systems and advanced technologies should provide employees with focus on functionality while enabling a view to critical information and access to historical plant data. Unless operators, maintenance technicians and engineers are initially trained in the full use of these products, the plants’ knowledge investment will not yield its full potential benefit. Less obvious is that when the plant converts to upgraded versions

Documentation systems. Changes made to automation systems are done weekly, and sometimes even daily. For some plants that have experienced incidents, those incidents were due to changes made to the automation systems. It is, therefore, critical to manage and document these changes to ensure they are validated and approved. This is the key to improving safety, reliability and efficiency. It is imperative to have a system that automatically documents any changes made to the controls, and then creates a process map for approvals of any changes made to procedures. This enables companies to take changes made to procedures to as high a level as needed for approvals, because the solution provides the context needed to provide reviewers all necessary information. Such a management-of-change (MOC) software package is loaded onto the control system, where it then aggregates the configuration of databases, programs and user interfaces and presents it in a visual diagram. This will tag those changes and avoid any integrity issues that might happen. In addition to being able to fully track and document these important changes, software such as this also impacts a facility’s ability to comply with industry regulations that are more frequently requiring backup documentation. While this solution may seem like a “no-brainer” on face value, it is actually common for plants to have relatively unsophisticated methods for tracking changes. In some cases, changes are literally tracked using methods such as “Post-It” notes. Cost is often a deterring factor in implementing these software programs. While some may struggle with the justification to purchase such technology, it is difficult for plants to quantify the losses they may sustain if they do not have a robust MOC tracking system. For instance, documentation systems are proven to drive profitability because they leverage scarce human resources through collaboration. They also ensure plants stay in compliance with changing Select 164 at www.HydrocarbonProcessing.com/RS

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PLANT DESIGN AND ENGINEERING

of these products, personnel also need refresher training to fully understand and use new features. An obvious example is that enhancements to an alarm management product add no value, nor enhance safety, unless they are understood and used by operators. From an overarching lifecycle perspective, the use of training, in conjunction with training simulators, keeps operator skills at optimum levels—which is obviously another key component of improving operations and performance over the course of an asset’s or plant’s life. System knowledge that is captured over time can provide significant benefit being used in operator training and simulation, which support improved performance throughout a plant’s life cycle. This is achieved through offline use in steady-state design simulation, control check-out and operator training, to online use in control and optimization, performance monitoring and business planning. This embedded knowledge in the simulator increases plant performance by helping a plant operate closer to constraints, maximizing production and minimizing operating costs. This results in another significant benefit: improved safety. Using simulation in real-world situations improves safety with operational readiness of plant assets and personnel. Plants can more easily capture and share process knowledge, improve plant profitability and maximize the return on their simulation investments. Cyber-security measures. Process control systems are ben-

efiting from the economies of open commodity hardware and software platforms. With these benefits, though, comes the exposure to the threats of hackers, worms and viruses. And protecting intellectual property means more than just remembering how equipment or a process is configured—it also means protecting

it from cyber threats. Fortunately, many advancements have been made in the cyber security space to help with this. For existing assets, a baseline of security processes, procedures and safeguards is used to protect a process control network from external threats. This is a first step to mitigate vulnerabilities. Multiple aspects come into play when securing a process control network from a system standpoint, and involve: • Firewall management • DMZ management • Terminal server management • OS patch management • VPN remote PCN access management • Automated PCN vulnerability scanning • Intrusion detection/prevention • Anti-virus updates. These domains, paired with a robust set of policies and procedures are the foundations of a cyber-security strategy. Protecting knowledge = protecting value. Tremen-

dous value can be gleaned from identifying and embedding knowledge and know-how into the control systems of an operating asset. But perhaps the best value comes in the form of costeffectively extending the life of the total system. Plants make enormous investments in intellectual property (everything from safety-tested alarms and emergency shutdown logic to graphics and process control) that becomes embedded into an automation system and is preserved there over time. One thing that manufacturers may neglect when they consider replacing such an asset is how intertwined the intellectual property becomes with the underlying system. Dissociating system configuration from true embedded process knowledge to recreate it in a new environment can be an extremely costly task, and could prove very disruptive to process operations. The nurture and preservation of this embedded knowledge holds the key to optimal operations, and should form the basis of a comprehensive lifecycle management plan. The key elements in achieving this preservation include upto-date documentation that ensures optimal, ongoing performance, training and cyber security. Achieving this preservation also entails a plan for keeping technology updated in a progressive, non-disruptive manner, and incorporating applications that allow them to do more with less while significantly extending the life of the system and maximizing operating performance. In other words, a good life cycle management strategy allows plants to work smarter. HP LITERATURE CITED Bullemer, P., D. V. Reising, J. Hajdukiewicz, and J. Errington, Interaction Requirements and Methods for Effective Operator Interfaces, Abnormal Situation Management Consortium internal publication, 2004. 2 Proceedings of the Human Factors and Ergonomics Society 49th Annual Meeting, Orlando, Sept. 26–39, 2005. 1

Jon Lippin is the vice president and general manager of Honeywell Process Solutions’ (HPS) Lifecycle Solutions and Services business. The organization provides 24x7 support for HPS products, platforms and solutions on a global basis. The team includes over 2,500 process automation experts who engage with customers to keep their plants operating at target performance levels using HPS and other automation technologies. Prior to his appointment, he was the vice president and general manager for Asia Pacific. Mr. Lippin joined Honeywell in 1984 and has held leadership positions of increasing responsibility in business management, project operations, sales, estimating and technical consulting throughout his distinguished career with Honeywell. He holds a Business Management Degree from Edison State College and is currently based in Bracknell, UK. 66

I DECEMBER 2011 HydrocarbonProcessing.com

Select 62 at www.HydrocarbonProcessing.com/RS

CALL FOR ABSTRACTS

Unconventional Feedstocks and Heavy Oil Conversions You are invited to submit an abstract for Hydrocarbon Processing’s third annual International Refining and Petrochemical Conference (IRPC) that will be held 12–14 June 2012 in Milan, Italy. IRPC is a leading-edge technical conference, providing an elite forum within which industry leaders can share knowledge and ideas relating to the international refining and petrochemical industries. The conference emphasizes the latest technological and operational advances from both a local and global perspective, and is attended by project engineers, process engineers and hydrocarbon processing industry (HPI) management offi cials from around the world. With changes in crude supply around the world, refiners and technology companies will be able to present the latest developments in refining technologies. The topics to be covered at IRPC 2012 include (but are not limited to): • Heavy oil conversion/bottom-of-the-barrel • Plant and refinery sustainability • Profitability • Energy policy • Middle distillate developments • MARPOL regulations • Shift in gasoline to diesel ratio (subject to specific countries) • Renewables/biofuels • Future of fuel oil • Clean fuels • Plant safety • Flare systems • Gas treatment technologies • Rotating equipment

• Reﬁnery and petrochemical integration • Bio-based petrochemicals/chemicals • Alternative feedstocks—shale gas, GTLs, CTLs, etc. • Catalysts—rare earth issue and new developments • Metallurgy • New Materials • Mechanical equipment • Energy efficiency • Maintenance and reliability • Effluence management (water, air, solid waste) • Carbon management • Process control applications/automation

Abstracts should be approximately 250 words in length and should include all authors, affiliations, pertinent contact information, and the proposed speaker (who will present the paper). Please submit via email to Events@GulfPub.com by 3 February 2012. The conference advisory board will review all submitted abstracts and select which will be presented at the conference in June. For more information on the conference and to learn about other ways to get involved, please visit www.HPIRPC.com.

MAINTENANCE AND CORROSION

Consider these guides for stress relieving of vertical towers This case history investigates all required post-weld heat treatment for an existing column H. AYARI, D. TRUONG and K. T. TRUONG, Ultragen Ltd., Boucherville, Quebec, Canada

amage from corrosion mechanisms often leads to failure in refinery equipment and creates safety hazards, which interrupt refinery operations. The corrosion-under-insulation (CUI) phenomenon occurs in insulated vessels when the vessel shell is in continuous contact with insulation that has become wet, thus enabling oxidation and loss of material. During a routine external inspection, the removal of the insulation around the shell of a process vessel revealed that the CUI had extended around its entire circumference (Fig. 1). The remaining thickness in affected areas of the shell ranged from 0.338 in. to 0.625 in. (being the original thickness). The tower was assessed for potential risk of collapse, and an external weld overlay technique was used as a permanent repair method that restored the corroded areas to original thickness (Tables 1 and 2). Quality repair requirements. Usually, the weld metal zone is stronger than the parent metal but has less ductility. The heat-affected zone is the region where most cracking defects are likely to occur because the grain structure becomes coarse just beyond the fusion line, and the ductility is lowest at this point. The effect of the welding heat on the parent metal depends on the temperature reached, the time temperature is held, and the rate of cooling after welding. Thus, the welding operation generates a

harder heat-affected zone, tensile residual stress and cold-cracking susceptibility in the weld zone, as well as in the base metal.1–8 That is why proper heat treatment after welding—post-weld heat treatment (PWHT)—is one that renews the material as near as possible to its original state.9,10 The process of PWHT consists of uniform heating of a vessel or part of a vessel to a suitable temperature for the material below the critical range of the base metal, followed by uniform cooling. This process is used to release the locked-up stresses in a structure or to weld to “stress–relieve” it. Due to the great ductility of steel at high temperatures, usually above 1,200°F, heating the material to such a temperature permits the stresses caused by deformation or straining of the metal to be released. Thus, PWHT provides more ductility in the weld metal and a lowering of hardness in the heat-affected zone (HAZ). It also improves the resistance to corrosion and caustic embrittlement.11–15 Heat treatment procedures require careful planning and will depend on a number of factors: temperatures required and time control for material; thickness of material and heating band width sizes; and contour, or shape and heating facilities. If a vessel is to be fully post-weld heat treated, as shown in Figs. 1 and 2, then the furnace should be checked to ensure that the heat will be applied uniTABLE 1. Original design conditions Design temperature

650°F

Internal design pressure

350 psig

External design pressure

Nonspecified

MDMT

–20°F

Hydrostatic pressure

670 psig

Corrosion allowance (shell/top head/bottom head) 0.125 in./0.217 in./0.207 in. Radiographic test

100% X-ray

Efficience joint

95%

Material

SA-285 C

TABLE 2. Wind parameters Importance factor, Iw

1.0

Shape factor, Cf (cylinder)

0.7

Shape factor, Cf (platforms) FIG. 1

Corroded area (A) and inspection sketch (B).

Wind pressure, q (kPa) Site class

1 0.4 A HYDROCARBON PROCESSING DECEMBER 2011

I 69

MAINTENANCE AND CORROSION formly and without flame impingement on the vessel. Vessels with thin walls or large diameters should be protected against deformation by internal bracing. The vessel should be evenly blocked in the furnace to prevent deformation at the blocks and sagging during the post-weld-heat treatment operation (Fig. 2 and Table 3). During this operation, both the increase and decrease in temperature must be gradual to allow uniform temperatures throughout.9,10 Codes. The ASME code, Section VIII Div. 1 requires PWHT

Severe corroded area 18 in.

Corroded area 18 in.

of a pressure vessel for certain design and service (Par. UW-40).9 PWHT treatment requirements (according to the material, thicknesses, service, etc.) It is important that the PWHT conditions be determined based on desired objectives. For a successful PWHT, it must be based on engineering assessment and optimization of many parameters to meet the desired objectives. According to the WRC 452, the main parameters are:10 • Temperature gradient through material thickness that is defined by two important parameters: heating rate and band size. • Induced stresses and distortion during PWHT (compression and bending during heating, creep relaxation during holding, global stress recovery upon cooling) • Gradient control band. An important factor to control the axial temperature gradient and to minimize heat losses. • Axial temperature gradient. The control is important to limit thermal stress and to protect the vessel outside of the band • Other considerations: – Equipment support during heating – Buckling and distortion – Internal liquids – Thermal expansion. Details of the corroded vessel. Fig. 2 shows the distribution and extent of corroded areas along the developed surface area of Top head

Course 10

M10

Course 9

Course 8

Course 7

Course 6

Course 5

Course 4

Course 3 Course 2 Course 1 Skirt

M3 M2 M1 Ms

Fsh Fs10 Fs9 Fs8

the tower. In our case, it is impractical to heat treat the whole vessel and that is why a local PWHT should be performed in situ. According to the ASME Section VIII Div.1, the pressure vessel required a localized PWHT to reduce the induced residual stresses when it is subjected to local welding.9 Therefore, it is very important to analyze if the in situ PWHT can be done in safe conditions; to determine the optimal temperature profile and the maximum heated circumferential bandwidth to reduce the unit downtime. Two distinct studies were accomplished as engineering activities before the PWHT. The first part of this study is to determine the mechanical loads due to weight and wind during PWHT. The second part is to assess its impact on the equipment mechanical integrity to ensure that the entire operation is safe with respect to the code requirements. GUIDELINE FOR A LOCAL PWHT ANALYSIS

The tower was assessed for potential risk of collapse and an external weld overlay technique was used as a permanent repair method that restored the corroded areas to original thickness. If the tower is subjected to local repairs, a localized PWHT is mandatory to reduce the induced residual stresses. The inspection group has determined that a vertical dimension for the applied heat patches is of 26 in. to cover the required area with a damaged height of 18 in. (26 in. =18 in. + 2 6 0.625 in.) and a maximum temperature for the PWHT of 1,200°F. A parametric finite element (FE) model was developed to analyze the heat treatment after welding and to determine the optimal temperature profile and the maximum circumferential length covered by heat patches. The vessel in consideration was analyzed using FE software. All the cylindrical sections of the tower and the skirt support were included in the numerical model (76 ft). A parametric FE model was created to investigate different circumferential dimensions for the PWHT area. Four different circumferential lengths were considered: 1⁄8 the circumference, 1⁄6 the circumference, 1⁄4 the circumference (about 29 in.) and 1⁄3 the circumference. The model was created using 4-node thin “Shell4” elements with membrane and bending capabilities. Geometrical parameters for the FE model/analysis (see Figs. 1 and 2) include: • Outside diameter: 37 in. • Corroded wall thickness: 0.5 in. (original wall thickness of 0.625 in. minus original CA of 0.125 in.) TABLE 3. Wind loads

Fs7 Fs6

Location

Fs5 Fs4 Fs3 Fs2 Fs1 Fss

MT = ∑ Mj + ∑ Fsj = dj FsT = ∑ Fsj

Bottom top head

75.134

29.30

Bottom course #10

67.717

459.320

5436.432

Bottom course #9

60.300

408.370

–1227.44

Bottom course #8

52.884

230.620

860.344

Bottom course #7

46.759

183.890

574.578

Bottom course #6

39.342

393.870

6514.642

Bottom course #5

31.925

203.170

760.5092

Bottom course #4

24.509

196.960

730.395

Bottom course #3

17.092

313.310

–1824.07

Bottom course #2

12.801

278.830

6421.514

Bottom course #1

5.384

197.370

687.9633

0.0

281.280

–3798.16

Bottom support skirt FIG. 2

Wind loads.

I DECEMBER 2011 HydrocarbonProcessing.com

Elevation dj, ft

Total wind shear Bending moment (lbf) per (lbf-ft) per component, Fsj component, Mj

FsT and MT at bottom FsT = Fsj = 3,176 support skirt

13.18

MT = Mj + Fsj dj = 130,672

MAINTENANCE AND CORROSION â&#x20AC;˘ Material of construction: SA-285 C â&#x20AC;˘ Tower height: 76 ft (the skirt length is included) â&#x20AC;˘ PWHT. Thermal and mechanical material properties. The thermal and mechanical properties (ASME, Section II, Part D, 2007) were defined as a function of temperature (Table 4):16 â&#x20AC;˘ Thermal conductivity (TC), Btu/sec in Â°F (Table 4) â&#x20AC;˘ Convection and radiation coefficient for vertical surface, Btu/in.2 sec Â°F (Table 5) â&#x20AC;˘ Thermal expansion coefficient, in./in./Â°F (Table 6) â&#x20AC;˘ Modulus of elasticity, psi (Table 7).

Thermal strain. The thermal strains for the PWHT operation were compared with 0.2% strain â&#x20AC;&#x153;marginâ&#x20AC;? as recommended in WRC 452.10 The strain range of 0.1% in./in. to 0.2% in./in. is the proportional limit of steel and is also a characteristic parameter in the curve of stress vs. strain of metal according to Hookeâ&#x20AC;&#x2122;s Law. Static stress. The evaluation criteria for the tower and support

skirt were established using ASME, Section VIII, Division 1, 2007, UG-23(b) for allowable longitudinal compressive stress in a cylinder.9 This stress is a function of the diameter, thickness and TABLE 4. Thermal conductivity T, Â°F

Thermal stress. According to the classification of ASME

Code Sect. VIII Div. 2, the stresses due to temperature gradient are considered secondary stresses.17 The calculated stress intensity should be compared with the allowable stress, S, that is equal to two times the average tabulated yield strength of the material for the highest and lowest temperature: S = Syc + Syh

(1)

where Syc = material yield strength at ambient temperature = 30,000 psi Syh = material yield strength at PWHT temperature = 15,000 psi (extrapolated value). Since the ASME, Section II, Part D only covers yield values, up to 1,000Â°F, for higher temperatures, the required value was extrapolated. In this case, the allowable stress, S, is equal to 45,000 psi.16

250

350

400

450 â&#x20AC;Ś

700

1,100

1,150

1,200

TC 7.62e-4 7.31e-4 7.15e-4 7.01e-4 â&#x20AC;Ś 6.16e-4 4.84e-4 .000468 .000451

TABLE 5. Convection and radiation coefficient T, Â°F

130

180

230

h 3.55e-6 4.13e-6 4.67e-6

280 â&#x20AC;Ś

1,030

1,080

1,200

5.2e-6 â&#x20AC;Ś 19.02e-6 20.49e-6 26.35 e-6

TABLE 6. Thermal expansion T, Â°F â?Ł

100

200

400 â&#x20AC;Ś

4.6e-6 6.5e-6

6.7e-6

7.1e-6 â&#x20AC;Ś

800

900

7.8e-6 7.96e-6

1,000

1,200

8.1e-6 8.3 e-6

TABLE 7. Modulus of elasticity T, Â°F E

400 â&#x20AC;Ś

700

800

29.3e6 28.6e6 28.1e6 27.5e6 â&#x20AC;Ś

200

300

25.3e6

24e6

900

1,200

22.3e6 15.4e6

EMISSIONS

REDUCED

FUEL CONSUMPTION

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I 71

MAINTENANCE AND CORROSION

Buckling. The buckling analysis of the tower is done following

the method of Bifurcation Analysis. This analysis is based on the load resistance factor design (LRFD). According to ASME Section VIII Div. 2 Part 5, 2007 edition, the allowable safety factor, LRFD, is calculated using the formula:17 LRFD = 2 / Beta

(2)

where Beta = 338 / (389 + D/t ). The minimum safety factor against buckling (LRFD) must be of 2.64. The margin of safety in the design takes also into account for manufacturing imperfections. Maximum deflection (DEFa ). Based on practical rules, the vessel deflection during PWHT is limited to 6 in./100 ft. For the tower in consideration, the maximum permissible deflection DEFa is 4.56 in./76 ft.

Tower contour

Envelope of radial force, Fr Fs

θi Fr

Envelope of shear force, Fsi

FIG. 3

Fsi

Boundary conditions. The bottom nodes of the skirt base are restrained in all direction. The weight (80,085 lbs) is applied as a distributed load on the upper edge of the tower. The shear forces at different levels of the tower due to wind are distributed over the half circumference. To reflect this reality, it was considered that the applied loads follow a sinusoidal distribution on the contours. The decomposition of wind shear forces (Fs ) is based on the approach described here. A point load, Fs applied over a cylindrical contour (Fig. 3) can be decomposed as elementary forces having a sinusoidal shape. The point force Fs (shear force) is equal to: N

Fs = ∑ Fsi

(3)

Where N is the number of nodes along half of the circumference. Fsi is the nodal shear force that is equal to: F sin θi Fsi = Fr sin θi and si = (4) Fsi +1 sin θi+1 Fr is a uniform radial force equal to:

Fs Fr = N ∑ sinθi 1

(5)

The angle ␪i defining the node position is equal to: π θi = (i −1)( ); 1 ≤ i ≤ N ; 0 ≤ θi ≤ π N −1

Fig. 4 illustrates the distribution of the point load, Fs , in nodal forces, Fsi , of sinusoidal shape. Bending moments, M, due to the wind, are transformed into elementary forces distributed over the contours of the tower. A sinusoidal shape distribution was also adopted, and the sum of these elementary forces should be equal to zero. If we consider a half of circumference (symmetry), the moment can be decomposed. Let M be a moment on the tower contour and Fi a nodal force at ␪i (Fig. 4). This force will induce an elementary moment, Mi .

Sinusoidal distribution of the point load Fs . FE model

Tower contour M/2

n=1

θi

FIG. 4

Force distribution to create an overturning moment.

I DECEMBER 2011 HydrocarbonProcessing.com

Stress

Strain

DEF

RFB

≤ σa

≤ εa

≤ DEFa

≥ LRFD

No (if one only)

Yes (all)

Fsi

(6)

Modiﬁed temp. proﬁle and/or circumferential length

temperature. (Length does not enter into this particular calculation.) The allowable compressive stress B at design conditions was determined following the steps in UG-23(b): A = 0.125 / (R / t) • Using the value A in Fig. CS-2 from ASME Section II-D or Table CS-2, for a particular design temperature, the allowable compressive stress, B, is determined.16 • For the present work, the allowable longitudinal compressive stress, B, at design temperature of 650°F is 10,818.93 psi.

PWHT possible// optimal temp. prof. and circumferential length RFB: risk factor of buckling obtained by FE; DEF: Deﬂection at the vessel top obtained by FE. σa: allowable stress, εa: allowable strain.

FIG. 5

Flowchart of iterative calculation.

MAINTENANCE AND CORROSION Mi = Fi Xi

(7)

With Xi = R sin i and Mi = Fi R sin i The moment on a half vessel contour is equal to:

(8)

N M = ∑ Mi (9) 2 1 Where N is the number of nodes along half of the circumference. M = RF1 sin θ1 + 2RF2 sin θ 2 + ......... 2 (10) +2RFn−1 sin θn−1 + RFn sin θn

Where n is the number of nodes along the ¼ of the circumference, sin i = 0; sin n = 1( 1 = 0°; n = 90°) and n = (N +1)/2

Fn−1 sin θn−1 Fn−2 sin θn−2 = ; = ........ Fn sin θn sin θn−1 Fn−1 F3 sinθ3 F2 sin θ 2 = ; = F4 sin θ 4 F3 sin θ3

(11)

The angle i , defining the node position is equal to: π π θi = (i −1)( ); 0 ≤ θi ≤ ; 1≤ i ≤ n 2(n −1) 2

The ASME code Section VIII Div.1 (UW Para. 40) and WRC Bulletin 452 require a gradual degradation in temperature around the treated area in order to minimize the effect of a sudden drop.9,10 It is, therefore, recommended to have a controlled temperature profile around the portion subject to PWHT. To obtain an acceptable level of thermal stress, deflection, strain, and without any risk of buckling, the temperature beyond the treated area should be kept to 650±50°F (Fig. 6). At this temperature (650±50°F), the mechanical strength of metal can be considered the same as at ambient temperature. (The tower was built before 1999.) Also, this condition ensures a relatively uniform expansion all around the circumference (not localized) that minimizes the deflection of the tower. In addition, analysis of the different circumferential lengths of the PWHT area has showed that the FE model, with ¼ of vessel perimeter (29 in.), respects the code limitation and represents a maximum length to reduce the downtime of the affected vessel. For the tower in consideration, the green area subjected to a controlled temperature ranging from 600°F to 700°F must have the following dimensions: the cylinder perimeter and along the vertical axis covered by the affected height plus two times of 24

(12)

By a simple substitution, we can deduct the nodal force, Fi , applied on half of the vessel contour (Fig. 4). CIRCUMFERENTIAL HEATED BAND WIDTH AND OPTIMAL TEMPERATURE PROFILE

FIG. 7

Proposed temperature profile.

FIG. 8

Thermal stress intensity due to PWHT.

18 in.

Corroded area

24 in.

26 in.

24 in.

The vessel is erected on the site and a local PWHT could not be performed on the entire circumferential length without causing an imminent collapse of the vessel. It is then important to optimize the heated circumferential length while assuring the mechanical integrity of the vessel. A steady-state heat transfer analysis is then required to determine the temperature profile of the vessel around the PWHT area limited by the circumferential dimension of the PWHT patch. A temperature of 1,200°F was used, as a maximum temperature, for the area exposed to PWHT. The optimal temperature profile and the heated area are determined by an iterative simulation as shown in the flowchart (Fig. 5).

1,200°F 650°F ± 50°F FIG. 6

π D/4 πD

Developed dimensions of controlled temperature and circumferential length, D/4.

HYDROCARBON PROCESSING DECEMBER 2011

I 73

MAINTENANCE AND CORROSION in. Fig. 6 shows the optimal temperature profile and dimensions of the heated area determined by iterative calculation according to the flowchart shown in Fig. 5. RESULTS OF THE ANALYSIS

According to the refinery’s inspection, the extent and severity of the thickness loss are immediately recognized as a safety hazard. As a first security measure, a preliminary analysis was conducted in according to ASME Section VIII Div. 1 to determine the minimum code thickness; and as per the National Building Code of Canada 2005 for the loads that are supported by the tower due to the weight and wind.9,18 The heat-treatment operation will be performed in situ during the shutdown. The mechanical loads present during the PWHT are identified as here: Dead loads. This is the total weight of the tower in new condition (to be in the safe side), platforms, ladders, attached piping, fire proofing, insulation and internals.

FIG. 9

FIG. 10

Wind loads. The wind pressure during PWHT is considered equivalent to the hydrostatic test case. This is typically as low as one-third of the design load, since it can be assumed that the vessel will not be PWHT during a hurricane or severe storm. The tower was then recalculated, using the original design conditions. Data used for calculations are summarized in Table 1. The main parameters used to calculate the wind loads, as defined by the NBC2005 and customer specifications, are summarized in Tables 2 and 3.18 The output results show that the minimum thickness required (0.625 in.) exceeds the remaining thickness measured by the inspection group (0.338 in.) The total weight of the tower including water and materials in new condition—platforms, ladders, attached piping, fire proofing, insulation and internals—is 80,085 lb. The platforms and ladders have also been modeled to properly reflect the effect of wind. Applying the NBC2005 and the customer specifications to determine wind loads, we find that the bending moment computed at the bottom of the skirt is 130,672 lb-ft.18 In addition, the wind velocity should not exceed 50 km/h during PWHT (for

Stress intensity due to weight and wind.

Stress intensity for combined loading (Case 1).

I DECEMBER 2011 HydrocarbonProcessing.com

FIG. 11

Equivalent strain.

FIG. 12

Deformed shape.

MAINTENANCE AND CORROSION Montreal East) to ensure 33% of design wind loads applied at the tower. Figs. 7 and 8 present the loads for the critical loading condition corresponding to the hydrostatic test case of a new tower. STRESSES EVALUATION

The stress evaluation is conducted in accordance with the rules of ASME Boiler and Pressure Vessel Code, Section VIII, Division 2, Part 5.17 In this FE study, three types of analysis were performed to assess the mechanical integrity of the vessel during the PWHT: thermal analysis, static analysis, combined analysis (thermal + static) and buckling. Temperature profile. The optimal temperature profile and

heated area are determined by an iterative simulation, as shown in the flowchart in Fig. 7. The calculated temperature profile resulting from the heat-transfer analysis around the exposed area to PWHT is shown in Fig. 8. Based on the determined nodal temperatures, the stress intensities, equivalent strain, deflection and risk of buckling are reported in this article. Thermal stress intensities. The thermal stress intensities resulting from the temperature distribution (Fig. 7) are shown in Fig. 8. Using the thermal boundary conditions described, the maximum stress intensity is of 36,100 psi. The calculated stress by FE is inferior to the allowable stress permitted by the ASME code (45,000 psi).

Combined stress intensities. In this section, we present the results of the combined loading case. Three critical cases of wind application can arise during the PWHT: • Case 1—Wind acts on the back of the heat-treated area, • Case 2—Wind acts on the front of the heat-treated area, • Case 3—Wind acts on the side of the heat-treated area. The stress intensity obtained by the FE model, due to the combination of mechanical and thermal loading, is shown in Fig. 10. The maximum stress is obtained for Case 1 (most critical case). The maximum stress is equal to 38,553 psi. This stress remains less than the allowable stress (45,000 psi). Strain results. Fig. 11 shows the equivalent strain in the case of combined loads. The largest deformation is observed in the case where the wind acts on the side to the area subjected to PWHT. The maximum strain calculated for the combined load case is equal to 0.122%. This deformation is also acceptable and inferior to 0.2%, assuring that the tower stress state stays within the elastic limit.

Static stress intensities. This section presents stress intensity related to mechanical loads applied on the tower (weight and

wind). The stress intensity obtained by the FE due to the weight and wind is shown in Fig. 9. The maximum stress intensity, as expected, is located at the bottom of the support skirt, which is remote from the PWHT area. The stress intensity values were calculated, using the mechanical properties as a function of the temperature profile determined during the thermal study of the FE model. The calculated stress intensity at the bottom of the skirt is small compared with the allowable stress (4,976 psi vs. 10,818 psi).

O V

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HYDROCARBON PROCESSING DECEMBER 2011

I 75

MAINTENANCE AND CORROSION deflection. The detailed dimensions of the area that must have a controlled temperature are shown by Fig. 9. For the tower in consideration, the analysis showed that the PWHT patch length should be limited to 1⁄4 of vessel perimeter (about 29 in.) In addition, during PWHT, the wind velocity should not exceed 50 km/h (Montreal East) to ensure 33% of design wind load applied on the tower. This approach can be generalized and applied for different sizes of the corroded vessel subjected to in situ PWHT. In the presence of a local discontinuity (for instance, a nozzle located inside or near the PWHT area), a more detailed FE model should be developed to take this into consideration. HP FIG. 13

A) Opening dimensions and B) deformed shape.

Deflection verification. Fig. 12 shows the deflection of the tower due to combined loads. The maximum deflection is 4.31 in. and it is observed at the top of the tower. This displacement is considered acceptable because the maximum displacement allowed is 4.56 in./76 ft. Risk factor of buckling (RFB). To be more conservative, in

the buckling analysis, we considered the PWHT area (which has a very low modulus of elasticity at 1,200°F) as an opening in the FE model. Based on the calculated heat-transfer profile, the heat treated zone is characterized by a centered high temperature that attenuates gradually to 650°F. Thus, the approximate dimensions of the opening are 40 in. by 36 in. (Fig. 13A). The results show that the calculated RFB is equal to 5.45, which is greater than 2.64 (theoretical permissible value for buckling). This demonstrates that the tower is capable of sustaining the current load without any risk of buckling during the PWHT. Fig. 13 shows the deformed shape and the risk factor of buckling of the tower with an opening. Conclusions. This article presents a numerical approach using the FE technique to analyze a tower subject to PWHT in the field. The analysis is accomplished in accordance with ASME Code Section VIII, Division 1 and 2, the National Building Code of Canada 2005 and the recommendations of WRC Bulletin 452.9, 10, 17, 18 The minimum required thicknesses, as well as the induced loads due to the weight and wind, were obtained in accordance with the NBC2005 design parameters. According to the procedures of ASME Code Section VIII Div.2, the calculated stress intensities were found to be of acceptable values, and thus do not permanently deform the vessel shell and/or cause buckling. As stated in this article, the combined stresses were compared with S with the hot yield value extrapolated from the ASME Code Section II, Part D since at the PWHT temperature, the hot allowable stress for the SA-285 Gr.C material is not available.16 The verification of thermal strains induced in the vessel around the PWHT area becomes necessary and recommended by WRC Bulletin 452.10 Thermal strains are calculated based on “displacement fields” which, in this case, are temperature related. The calculated strains for the PWHT operation were compared with 0.2% strain “margin.” The calculated thermal strain around the PWHT area is 0.122% (max.) The results from the thermal analysis demonstrate that the temperature around the treated area should be maintained from 600°F (min.) to 700°F (max.) to not induce excessive stresses and 76

I DECEMBER 2011 HydrocarbonProcessing.com

ACKNOWLEDGMENTS The authors gratefully acknowledge the technical and financial support provided by the Ultragen Group Ltd./ Engineering Consultant. LITERATURE CITED Xue, Q., D. Benson M. A. Meyers, V. F. Nesterenko, and E. A. Olevsky, Constitutive response of welded HSLA 100 steel, Materials Science and Engineering A354: pp. 166–179, 2003. 2 Ramirez, J. E., S. Mishael and R. Shockley, “Properties and Sulfide Stress Cracking Resistance of Coarse-Grained Heat-Affected Zones in V-Micro alloyed X60 Steel Pipe,” Welding Research, Welding Journal, 2005. 3 Okabayasi, H. and R. Kume, Effects of Pre-and Post- Heating on weld cracking of 9Cr.-1 Mo-Nb-V Steel, Transaction of the Japan Welding Society, Vol. 19, No. 2, 1988. 4 Funderburk, R. S., “Key Concepts in Welding Engineering- fundamentals of Preheat,” Welding Innovation, Vol. XIV, No. 2, 1997. 5 Kasuya, T., N. Yurioka and M. Okumura, “Methods for predicting maximum hardness of Heat Affected Zone and selecting necessary Preheat temperature for Steel Welding,” Nippon Steel Technical Report No. 65, 1995. 6 Tso-Liang, T. and P-H. Chang, “A study of residual stresses in multi-pass girth-butt welded pipes,” International Journal of Pressure Vessels and Piping, No. 74, pp. 59–70, 1997. 7 Lee, S., B. C. Kim and D. Kwon, “Correlation of microstructure and fracture properties in weld heat-affected zones of thermomechanically controlled processed steels,” Metallurgical Transactions, 1992. 8 Eigenmann, B., V. Schulze, and O. Vo¨hringer, “Surface residual stress relaxation in steels by thermal or mechanical treatment,” Fourth International Conference on Residual Stresses, Society of Experimental Mechanics, Bethel, Connecticut, Baltimore, pp. 598–607, 1994. 9 ASME, 2007, ASME Boiler and Pressure Vessel Code, Section VIII, Division 1. 10 WRC Bulletin 452: Recommended Practices for Local Heating of Welds in Pressure Vessels by J. W. McEnerney and Pingsha Dong–June 2000. Library of Congress Card Catalog: 85-647116, p. 64. 1

Complete literture cited and nomenclature available online at HydrocarbonProcessing.com. Houcine Ayari is a mechanical engineer with Ultragen Limited, engineering consultants from Québec, Canada. He has over five years of experience in pressure vessel and process piping design. He holds an DScA degree from École de Technologie Supérieure, Montréal, Canada, 2010. Daniel Truong has over nines years of experience in project management and pressure vessel design related to hydrocarbon processing industries. During this period, he was working for several different companies such as ABB Dryer, Shell Canada and SNC-Lavalin before joining the ULTRAGEN Group. He holds an BS degree in mechanical engineering from Concordia University and is a registered engineer in the province of Quebec.

K. T. Truong has over 30 years of experience in pressure vessel and process piping design. During this period, he has been lead mechanical engineer and piping consultant on a broad spectrum of refinery, chemical and petrochemical plants for different engineering firms such as Tecsult, SNC/Foster Wheeler, Bantrel and Fluor Daniel. Since 1988, he has been president and co-founder of the ULTRAGEN Group Ltd. Dr. Truong holds BScA, MScA and DScA degrees from Laval University, Québec. He has served as assistant professor at Moncton University and Université du Québec à Montréal. He is a registered engineer in the provinces of Québec and Ontario and a member of ASME.

PLANT SAFETY AND ENVIRONMENT

Proper relief-valve sizing requires equation mastery These simple and rigorous critical-flow equations will help stem the tide of potential catastrophic failures J. S. KIM and H. J. DUNSHEATH, Bayer Technology Services, Baytown, Texas; N. R. SINGH, Bayer CropScience, Institute, West Virginia

ressure-relief valves are reliable and effective pressure-relief devices that protect personnel from the dangers of overpressurizing equipment, prevent damage to equipment, and minimize release of hazardous materials. Sizing relief valves involves determination of the rate of material release through the relief valve during the identified worst-case contingency. Relief valves are designed to relieve liquids, vapors or two phases from protected pressure vessels before excessive pressures are developed. A mistake in the relief-valve sizing can result in catastrophic failures because relief valves are usually the last defense to the process equipment against instrument failures, process upsets and operator errors. This article focuses on sizing the pressure-relief valves for critical flow of gases or vapors. Two-phase sizing methods1,2 are not well established, but it is generally understood that sizing methods for vapor or gas are well established and the results are relatively accurate. Relief-system designers favor simple sizing equations, and use the conventional vapor-sizing equation in American Petroleum Institute (API) Standard 520, using the ideal gas specific heat ratio.3 Although rigorous calculations using isentropic flash calculations give the most accurate results, the simple API relief-valve sizing equation is still preferred because of its simplicity. However, sometimes the real gas specific heat ratio is more readily available from a process simulator than the ideal gas specific heat ratio. Thus, a simple sizing equation using the real gas specific heat ratio was developed. Emerging from that development is an improved sizing equation using the real gas specific heat ratio. The results are compared with the conventional API sizing equation. Furthermore, a rigorous critical-flow equation with the isentropic flash is introduced as a recommended estimation tool for gas or vapor critical flow when the gas or vapor is known to deviate significantly from ideal conditions.

Conventional API flow equation. Eq. 1 is the conventional API relief-valve sizing equation for critical vapor flow. The conventional API sizing equation requires five fluid property data: absolute pressure, P ; kPa, absolute temperature, T ; K, molecular weight, M , compressibility factor, Z , and ideal gas specific heat ratio, k *, at inlet conditions. The equation provides satisfactory sizing results over a wide range of process conditions. However, the sizing equation is only valid for 0.8 < Z < 1.1.3 This means that the sizing results may not be satisfactory for very high pressure conditions or critical-point regions.

T1Z1 W M C k* K d P1K b K c

where:

(1) k* +1 â&#x17D;&#x17E; k* â&#x2C6;&#x2019;1

â&#x17D;&#x203A; 2 â&#x17D;&#x; â&#x17D;&#x; C k* = 0.03948 k* â&#x17D;&#x153;â&#x17D;&#x153; â&#x17D;&#x153;â&#x17D;? k* +1â&#x17D;&#x;â&#x17D;&#x;â&#x17D;

Pchoke

2 P1 k* 1

k* k* 1

(2)

where: A = Relief valve orifice area, mm2 W = Mass flow rate, kg/h Ck* = A function of the ratio of ideal gas specific heat at inlet conditions Kd = The coefficient of discharge Kb = The capacity correction factor due to backpressure Kc = The combination correction factor for installation with a rupture disk upstream Subscripts 1 = Fluid conditions at the inlet of the relief valve, where velocity is equal to zero choke = Choked (critical) conditions. Real gas specific heat ratio. The new equation uses the

real gas specific heat ratio in the sizing equation instead of the ideal gas specific heat ratio. In order to figure out what assumptions are needed to use the gas specific heat ratio as an isentropic expansion coefficient, it is required to check with Eq. 3. This equation is one of the widely used methods for calculating the isentropic expansion coefficient where rigorous relief-valve sizing is deemed necessary. The equation is based on the assumption that the isentropic expansion coefficient is constant. Although the isentropic expansion coefficient is actually not constant during the expansion process, the sizing results with the isentropic expansion coefficient are relatively good. The derivatives in Eq. 3 for the Redlich-Kwong and Peng-Robinson equations are readily available in the literature.4,5 HYDROCARBON PROCESSING DECEMBER 2011

I 77

PLANT SAFETY AND ENVIRONMENT The Peng-Robinson equation of state appears to be the most favorable with the SRK equation. Eq. 4 shows the derivative of pressure with respect to specific volume, v; m3/kg, at constant temperature and constant compressibility factor. The gas specific heat ratio becomes the isentropic expansion coefficient (n) when the compressibility factor is constant. Of course, the real gas specific heat ratio, k, will be the ideal gas specific heat ratio, k*, if the compressibility factor is 1. In conclusion, it is required to assume the constant compressibility factor when developing a sizing equation with the real gas specific heat ratio. v â&#x17D;&#x203A; â&#x2C6;&#x201A;P â&#x17D;&#x17E; n = â&#x2C6;&#x2019; â&#x17D;&#x153;â&#x17D;&#x153;â&#x17D;&#x153; â&#x17D;&#x;â&#x17D;&#x;â&#x17D;&#x; k (3) P â&#x17D;? â&#x2C6;&#x201A;v â&#x17D; T â&#x17D;&#x203A; â&#x2C6;&#x201A;P â&#x17D;&#x17E;â&#x17D;&#x; â&#x17D;&#x153;â&#x17D;&#x153; â&#x17D;&#x; = â&#x2C6;&#x2019; ZRT â&#x17D;&#x153;â&#x17D;? â&#x2C6;&#x201A;v â&#x17D;&#x;â&#x17D; v2 T

among the compressibility factor, real gas specific heat ratio and isentropic expansion coefficient over the range of 0 < n < 2.5. 2 Z1 k k 1

(4)

W C n K d P1K b K c

T1Z1 M (10)

â&#x17D;&#x203A; 2 â&#x17D;&#x; C n = 0.03948 n â&#x17D;&#x153;â&#x17D;&#x153;â&#x17D;&#x153; â&#x17D;&#x; â&#x17D;? n +1â&#x17D;&#x;â&#x17D; n

where R is a universal gas constant, 8.314 Eq. 5 is easily found in textbooks. 6 When ideal gases are expanded, they follow Eq. 5. However, Eq. 6 is for real gases provided that the compressibility factor is constant. Eq. 6 explains why the inlet compressibility factor is not to be included in Eq. 7. The real gas specific heat ratio already accounts for the value of the compressibility factor and non-ideality at high pressure conditions. Therefore, when the real gas specific heat ratio is used in the sizing equation, the compressibility factor is not necessary. If one uses the real gas specific heat ratio in Eq. 1, the compressibility factor will be accounted for twice. This may result in inadequate relief valves, as addressed in API-520.7 A statistical analysis shows that about 7% of the equipment in the oil, gas and chemical industries had pressure-relief devices undersized.8 Pvk* =

constant (5) â&#x17D;&#x203A; v â&#x17D;&#x17E;â&#x17D;&#x;k (6) P â&#x17D;&#x153;â&#x17D;&#x153;â&#x17D;&#x153; â&#x17D;&#x;â&#x17D;&#x; = constant â&#x17D;?Z â&#x17D; The authors developed Eq. 7 for relief-valve sizing for critical vapor flow with the real gas specific heat ratio. The simple equation follows fundamental thermodynamic rules.

W C k K d P1K b K c

T1 M (7) k +1 â&#x17D;&#x17E; kâ&#x2C6;&#x2019;1

â&#x17D;&#x203A; 2 â&#x17D;&#x; C k = 0.03948 k â&#x17D;&#x153;â&#x17D;&#x153;â&#x17D;&#x153; â&#x17D;&#x; â&#x17D;? k +1â&#x17D;&#x;â&#x17D; k

â&#x17D;&#x203A; 2 â&#x17D;&#x17E;â&#x17D;&#x;kâ&#x2C6;&#x2019;1 = P1 â&#x17D;&#x153;â&#x17D;&#x153;â&#x17D;&#x153; â&#x17D;&#x; â&#x17D;? k +1â&#x17D;&#x;â&#x17D;

(8)

where Ck is a function of the ratio of real gas specific heat at inlet conditions. Although Eq. 7 may be satisfactory for critical-flow relief-valve sizing, the critical pressure prediction is not sufficiently accurate. In order to predict the accurate critical pressure, Eq. 9 is derived based on Eq. 7 being equal to Eq. 10. Instead of solving Eq. 9 for the isentropic expansion coefficient with the real gas specific heat ratio and compressibility factor, Eq. 12 fits well the correlation 78

(9)

n+1 â&#x17D;&#x17E; nâ&#x2C6;&#x2019;1

kPa-m3/kg-mole-K.

Pchoke

n 1 n 1

Finally, Eq. 10 can be obtained as a critical-flow sizing equation with the compressibility factor and isentropic expansion coefficient. Eq. 7 and Eq. 10 are identical, and the two equations give the same sizing results. However, Eq. 11 predicts better choked pressures than Eq. 8.

Pv = ZRT

where:

2 n n 1

where:

k 1 k 1

I DECEMBER 2011 HydrocarbonProcessing.com

Pchoke

â&#x17D;&#x203A; 2 â&#x17D;&#x17E;â&#x17D;&#x;nâ&#x2C6;&#x2019;1 = P1 â&#x17D;&#x153;â&#x17D;&#x153;â&#x17D;&#x153; â&#x17D;&#x; â&#x17D;? n +1â&#x17D;&#x;â&#x17D;

(11)

n = a + bY + cY 2 + dY 3 + eY 4

(12)

k +1

â&#x17D;&#x203A; 2 â&#x17D;&#x17E;â&#x17D;&#x; kâ&#x2C6;&#x2019;1 Y = Z1k â&#x17D;&#x153;â&#x17D;&#x153;â&#x17D;&#x153; â&#x17D;&#x; â&#x17D;? k +1â&#x17D;&#x;â&#x17D;

(13)

a = 4.8422E-5 b = 1.98366 c = 1.73684 d = 0.174274 e = 1.48802 where Cn is a function of the isentropic expansion coefficient at inlet conditions. Isentropic flash. Eq. 14, which requires a few iterations in

an isentropic flash routine, is the most accurate sizing equation. The rigorous method uses the best predictions of the actual fluid properties since the calculated isentropic expansion coefficient is constant between two data points. The first trial of isentropic flash can start with an initial estimate of choked pressure at 55% of the inlet pressure. The choked condition is usually attained when the downstream pressure is about 45% to 65% of the inlet pressure. Repeat the isentropic flash with the new estimate until it stops changing. In case of liquid formation during the isentropic flash, the overall specific volume of the fluid has to be used in Eq. 15. Otherwise, it is better to use the temperature and compressibility factor in Eq. 15 to indicate that there is no condensation during expansion. The calculation details will be illustrated in the â&#x20AC;&#x153;example calculationsâ&#x20AC;? section. However, the equivalent results can be obtained using numerical integration with numerous flash calculations. The intensive numerical integration method is presented in API Standard 520.

W C r K d P1K b K c

T1 Z1 M

where:

n+1

â&#x17D;&#x203A; 2 â&#x17D;&#x17E;â&#x17D;&#x;nâ&#x2C6;&#x2019;1 C r = 0.03948 n â&#x17D;&#x153;â&#x17D;&#x153;â&#x17D;&#x153; â&#x17D;&#x; â&#x17D;? n +1â&#x17D;&#x;â&#x17D;

P1 v ln 2 P2 v1

P1 PT Z ln 1 2 2 P2 P2T1Z1

(14) 1

(15)

PLANT SAFETY AND ENVIRONMENT

Comparison. The predictions of the simple flow equations

have been compared with the most accurate estimates for the following two cases at six different pressures. The two cases include high pressures and critical-point regions to evaluate the limitations of the new simple method. The Peng-Robinson equation of state was used for the estimation of necessary fluid properties. Case 1: Air at 250 K. The first case considers the discharge of air at 250 K that is relieving at six different pressure levels of the inlet reduced pressure from 0.5 to 8. The inlet compressibility factors are in the range of 0.9 < Z < 1.1. Fig. 1 shows the mass flux (W/A) deviations of Eqs. 1 and 7 from Eq. 14. Here, the compressibility factor decreases during expansion. Therefore, both of the simple sizing equations appear to oversize the relief valves. The difference between the compressibility factors increases with increasing the inlet reduced pressure. Fig. 1 shows that both simple equations give conservative estimates as expected. The results of both equations are satisfactory at low pressures. However, if the vapor or gas is at high pressure and low temperature, one should use them with caution. Generally, the vapor or gas tends to behave ideally at high temperatures. Case 2. Saturated n-hexane vapor. The second case considers the discharge of a pure component-saturated vapor (n-hexane) that is relieving at six different pressure levels of the inlet reduced pressure from 0.15 to 0.9. The inlet compressibility factors are in the range of 0.4 < Z < 0.9. Here, the compressibility factor increases during expansion. The difference between the compressibility factors increases with increasing the inlet reduced pressure. Therefore, the simple sizing equations appear to undersize the relief valves. Fig. 2 shows that the conventional simple API equation gives profoundly unconservative estimates as expected. Unlike the conventional simple equation, the results of Eq. 7 or Eq. 10 are satisfactory up to the inlet reduced pressure of 0.75. However, if the inlet reduced pressure is greater than approximately 0.7, one should use it with caution. TABLE 1. Results of isentropic flashes Z2

First trial at 994.059 kPa

453.8

0.7959

0.7554

Second trial at 1,208.05 kPa

459.5

0.7534

0.7272

Third trial at 1,222.584 kPa

459.9

0.7505

0.7252

Fourth trial at 1,223.63 kPa

459.9

0.7503

0.7251

Eq. 1

Eq. 7

Ideal gas specific heat ratio used

N/A

1.041

N/A

Real gas specific heat ratio used

N/A

1.265

Inlet compressibility factor used

0.6279

N/A

0.6279

Isentropic expansion coefficient used

0.7251

N/A

0.6866

Choked pressure calculated Outlet temperature used Outlet compressibility factor used Required orifice area calculated Remarks

1,224 kPa 1,080 kPa

998 kPa 1,244 kPa

459.9 K

N/A

0.7503

N/A

556 mm2 482 mm2 567 mm2 566 mm2 –

Undersized

–

= 0.7251

0.7251

Pchoke

0.7251+1

⎛ ⎞⎟0.7251−1 2 = 0.0211 C r = 0.03948 0.7251⎜⎜⎜ ⎟ ⎝ 0.7251+1⎟⎠ A=

(474)(0.6279) 10,000 = 556 mm 2 86.18 (0.0211)(0.877)(1,807.38)(1)(1)

Calculations with Eq. 1. Using the ideal gas specific heat ratio along with the inlet compressibility factor gives the required orifice area of 482 mm2, which is much smaller than the best estimate of 556 mm2. 0 -2 -4 -6 -8 -10 -12

Eq. 1 Eq. 7 or 10

-14 -16

FIG. 1

Eq. 10

−1

⎛ ⎞⎟0.7251−1 2 = 1,807.38 ⎜⎜⎜ = 1, 224 kPa ⎟ ⎝ 0.7251+1⎟⎠

0.5

TABLE 2. A summary of example calculations Eq. 14

⎛ 1,807.38 ⎞⎟ ⎡ ⎛⎜ (1,807.38)(459.9)(0.7503) ⎞⎟⎤ ⎢ ln ⎥ n = ⎜⎜ln ⎜⎝ 1, 223.63 ⎟⎟⎠ ⎢ ⎜⎜⎝ (1, 223.63)(474)(0.6279) ⎟⎟⎠⎥ ⎣ ⎦

Mass ﬂux deviation from Eq. 14, %

T2 , K

Examples. A relief valve should release 10,000 kg/h of saturated n-hexane vapor (M = 86.18) at a relief pressure of 1,807.38 kPa (inlet reduced pressure of 0.6) and a relief temperature of 474 K. The compressibility factor at the conditions is 0.6279. Calculate the required actual orifice area based on Kd = 0.877, Kb = 1 and Kc = 1. The authors used a process simulator with a selection of the PengRobinson equation of state to obtain the necessary fluid properties. Calculations with Eq. 14. The results of isentropic flashes for Eq. 14 that were obtained from a process simulator are summarized in Table 1. Iterations were stopped after four trials, as the new choked pressure was close enough to the old one. The best estimate of required orifice area is 556 mm2.

Mass ﬂux deviation from Eq. 14, %

where Cr is a function of the rigorous isentropic expansion coefficient, and Subscript 2 refers to fluid conditions at the outlet of the relief valve (at the nozzle throat).

2.0

3.5 5.0 Inlet reduced pressure

6.5

8.0

Calculation results for high-pressure air at 250 K (Case 1).

35 30

Eq. 1 Eq. 7 or 10

25 20 15 10 5 0 -5 0.15

FIG. 2

0.30

0.45 0.60 Inlet reduced pressure

0.75

0.90

Calculation results for saturated n-hexane vapor under critical conditions (Case 2). HYDROCARBON PROCESSING DECEMBER 2011

I 79

PLANT SAFETY AND ENVIRONMENT Calculations with Eq. 7. Using the real gas specific heat ratio gives the required orifice area of 567 mm2. Calculations with Eq. 10. Eq. 10 is technically identical to Eq. 7. This method will give a better estimate of the choked pressure than the Eq. 7 method. 1.265+1

⎛ ⎞⎟1.265−1 2 Y = (0.6279)(1.265)⎜⎜⎜ = 0.2742 ⎟ ⎝1.265 +1⎟⎠ n = 4.8422E-5 +1.98366Y +1.73684Y 2 + 0.174274Y 3 +1.48802Y 4 = 0.6866 0.6866+1

⎛ ⎞⎟0.6866−1 2 = 0.0207 C n = 0.03948 0.6866 ⎜⎜⎜ ⎟ ⎝ 0.6866 +1⎟⎠ A=

(474)(0.6279) 10,000 = 566 mm 2 86.18 (0.0207)(0.877)(1,807.38)(1)(1)

Pchoke

⎛ ⎞⎟0.6866−1 2 = 1,807.38 ⎜⎜⎜ = 1, 244 kPa ⎟ ⎝ 0.6866 +1⎟⎠

0.6866

All calculation results are summarized in Table 2 for comparison. The required orifice area estimated by the API sizing equation is not satisfactory as expected, and this may result in an undersized relief valve. On the other hand, the new method by Eq. 7 or Eq. 10 produces satisfactory results. Recommended usage. Proper sizing of a relief valve requires not only using an accurate critical-flow equation, but also using

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I DECEMBER 2011 HydrocarbonProcessing.com

accurate fluid properties. The simple sizing equation for critical vapor flow using the real gas specific heat ratio has been tested on two cases: air at higher pressures and n-hexane under critical conditions. Although in both cases the conventional API equation is difficult to properly size pressure relief devices, the new approach results in a significant improvement. It is also important to note that the compressibility factor should be removed in the simple sizing equation where the real gas specific heat ratio is used as an isentropic expansion coefficient. However, relief-system designers should be careful when sizing the pressure relief devices for vapor or gas at critical regions or high pressures where the gas or vapor deviates significantly from the ideal conditions. Any simple equation involves assumptions that generally introduce errors. As demonstrated in the example calculations, the rigorous flow equation with isentropic flash is not so complicated and difficult to use. The rigorous flow equation with no assumptions uses the most accurate fluid properties. Therefore, using the rigorous flow equation with isentropic flash is recommended when the gas or vapor is known to behave significantly non-ideally. HP LITERATURE CITED Darby, R., “Evaluation of two-phase flow models for flashing flow in nozzles,” Process Safety Progress, Vol. 19, No. 1, pp. 32–39, 2000. 2 Diener, R. and J. Schmidt, “Sizing of throttling device for gas/liquid twophase flow, Part 1: Safety valves,” Process Safety Progress, Vol. 23, No. 4, pp. 335–344, 2004. 3 “Sizing, selection and installation of pressure-relieving devices in refineries,” API Standard 520, Part I—Sizing and selection, December 2008. 4 “Guidelines for pressure-relief and effluent-handling systems,” Center for Chemical Process Safety (CCPS), AIChE, New York, 1998. 5 Pratt, R. M., “Thermodynamic properties involving derivatives using the Peng-Robinson equation of state,” Chemical Engineering Education, pp. 112–115, Spring 2001. 6 Crowl, D. A. and J. F. Louvar, Chemical Process Safety: Fundamentals with Applications, Prentice-Hall, Englewood Cliffs, New Jersey, 1990. 7 Shackelford, A., “Using the ideal gas specific heat ratio for relief-valve sizing,” Chemical Engineering, pp. 54–59, November 2003. 8 Patrick, C., R. A. Kreder and W. Lee, “Analysis identifies deficiencies in existing pressure-relief systems,” Process Safety Progress, Vol. 19, No. 3, pp. 166–172, 2000. 1

Jung Seob Kim is a principal process safety engineer at Bayer Technology Services, where he is responsible for designing emergency pressure relief systems and technical consultation. He has more than 25 years of experience in different roles with chemical process industry including with Samsung BP Chemicals Co. and Samsung Engineering Co. in Korea. He holds a BS degree in chemical engineering from the University of Seoul. Mr. Kim is a member of AIChE, and is a registered professional engineer in the state of Texas.

Heather Jean Dunsheath is a pressure safety specialist at Bayer Technology Services, where she is responsible for identifying potential overpressure scenarios and designing emergency pressure relief systems. She holds a BS degree in chemical engineering from Rice University and is a member of the Design Institute for Emergency Relief Systems.

Dr. Navneet R. Singh is a senior process engineer at Bayer CropScience LP, where he is responsible for process design, process modeling and emergency relief system design. He holds an MS degree and a Ph.D. from Purdue University, and a bachelor’s degree in chemical engineering from the Institute of Chemical Technology in Mumbai, India, is a senior member of AIChE and a certified functional safety professional.

ROTATING EQUIPMENT

Enhancing pump design How modern tools accentuate pump performance S. KRUEGER, Sulzer Pumps, Winterthur, Switzerland; M. CROPPER, Sulzer Pumps (US), Portland, Oregon; and J. PARKER, Sulzer Pumps (US), Brookshire, Texas

nly a few decades ago, product development of pumps was performed by the use of drawing boards and simple calculation methods. Most of the development time was spent on 2D CAD drafting, limiting the amount of iterations to a minimum. Together, advances in information technology, computer-aided engineering (CAE), drafting (CAD) and simulation have evolved significantly. A number of step-changes in technology have allowed for an automation of design tools, thereby reducing the development time needed for drafting and allowing for further design iterations. Progress with faster computers, tools for computational fluid dynamics (CFD), structural analysis, standards and databases, releases even more time for pump performance optimization with respect to efficiency and reliability.

Service. The stringent requirements of the hydrocarbon pro-

cessing industry demand a guaranteed level of product quality and performance reliability. Todayâ&#x20AC;&#x2122;s social and economic standards also demand that modern pump designs are produced with a focus on safety, reliability, energy optimization, material usage and environmental sustainability. Leaders in pump design technology strive for a continual improvement of their products with a view toward optimizing design for any given application. Improvements in performance-range coverage are the starting point. The addition of further hydraulic performances into an existing product range will certainly increase the probability of finding a performance selection at, or close to, the pumpâ&#x20AC;&#x2122;s best efficiency point.

FIG. 1

BBS between bearings single-stage double-suction pump.

The creation of compact hydraulic designs has a significant effect on the overall size of the pump casing, thereby allowing a reduction in the overall use of materials while still ensuring the integrity of the pressure boundary and meeting the requirements of pressure vessel design codes. Combining this with a reduction in the pump case suction and discharge nozzle sizes can also allow the piping designer to use smaller connecting piping, valves and piping supports. The overall result is continual improvements to product performance, with optimized use of materials by both the pump manufacturer and the plant designer (Fig. 1). Modern tools improve the product. The impeller is

the heart of a pump, as it is responsible for hydraulic efficiency and pump head. In addition (as is the case for the BBS pumps), a suction impeller has to achieve a required NPSH3% (Fig 2).

FIG. 2

Cross-sectional view of a BBS impeller.

FIG. 3

Result analysis in modern impeller design.

HYDROCARBON PROCESSING DECEMBER 2011

I 81

ROTATING EQUIPMENT

FIG. 4

Flow visualization in impeller and volute.

FIG. 5

Total deformation (same scale and load case) for basic design (left) and optimized design (right).

Sulzer Pumps developed its own fully parametric, multifunctional impeller design program, and has validated its reliability over decades. More than 80 parameters define meridional contour, blade shape and thickness, ensuring a high flexibility of the impeller geometry. When designing a suction impeller, the developer faces opposing objectives, such as maximizing hydraulic efficiency while minimizing NPSH3% values. This yields different geometry solutions that are all compromised in some manner. For a performance enhancement project, the main impeller dimensions are given (e.g. shaft, impeller eye and outer diameter, as well as impeller length), allowing freedom for a fine tuning of meridional contour and blade shape. The performances and suction capabilities of these designs are usually evaluated by CFD for a wide range of operating points. This automated process—consisting of impeller design, simulation and result analysis—is implemented into an optimization environment that drives the entire impeller design to achieve overall objectives of efficiency, and head and suction performance. Within this optimization, the simulations are usually done for customer-specified operating points, e.g. duty point, partload and overload operating conditions. Automation allows for impeller design and analysis to continue normal outside working hours. This greatly increases the amount and variety of design information that can be studied when striving towards an optimum solution. Fig. 3 gives an example for such a result analysis within the impeller design. It visualizes the relationship 82

I DECEMBER 2011 HydrocarbonProcessing.com

between overall impeller efficiency (a combined value of duty point, partload and overload efficiency), impeller head and cavitation at duty point. The red cross-hatched section shows that four designs can best fulfill the requirements. They are all checked for design and manufacturing constraints and their entire impeller performance curve is simulated and compared against performance impairment and suction behavior. This process allows the selection of the final impeller geometry. With other in-house tools, the suction and volute casing passageways are generated, and, if necessary, a full transient simulation can be undertaken to check the entire hydraulic and suction performance. Fig. 4 shows the flow field in impeller and volute of a BBS pump. This technique has the great advantage of allowing visualization of flow separation and recirculation zones, based on which the designs can be reiterated and manually optimized. Based on the selected waterway designs, the pump casing’s mechanical designs are generated and a structural analysis is then performed. The deformations and the stress behavior of pump casing, cover and bolts can be evaluated for different load cases with the use of 3D finite element analysis (FEA). From the designer’s standpoint, the first design is most likely a light one with a consequential lack of stiffness and higher resulting stresses and deformations than acceptable. In this case, FEA indicates those areas where excessive stress and deformations are beyond target limits. The designer can then decide to modify the casing by selectively increasing wall thickness and using additional stiffening ribs to increase stiffness and to reduce any deformation to acceptable limits. This also allows the designer to optimize the use of raw materials. Use this case as an example: Adding two ribs under the 180° flange is a simple modification that shifts deformation and stresses into the acceptable limits (Fig. 5). Product development has changed significantly over recent decades and innovation and concept changes are major keywords. The application of the latest tools, codes and standards are of great help to enhance both efficiency and reliability for new generations of pumps. HP Susanne Krüger is heading the Core Technology and Tools Group within the Sulzer Pumps headquarters in Winterthur, Switzerland. Her responsibilities involve the definition of strategy, the monitoring of the ongoing projects, the research processes, the evaluation of research and the integration into product design processes. Dr Krüger has been working in the turbomachinery business for seven years and joined Sulzer in 2005. She holds an MS degree from the Technical University of Stuttgart, Germany, and a PhD from the Swiss Federal Institute of Technology of Zurich.

Mick Cropper is heading the Product Development Engineering at Sulzer Pumps (US) Inc. in Portland, Oregon. He is currently responsible for global product development activities, which have included over the last five years, upgrades and additions to Sulzer product lines to conform to the latest industry requirements for applications in refining, oil and gas applications, power generation and water industries. Mr. Cropper graduated from Barnsley College of Technology in England with a higher national certificate in mechanical engineering.

John Parker is the Head of Segment for the hydrocarbon processing industry (HPI) located at Sulzer Pumps (US) Inc. in Brookshire, Texas. Mr. Parker is responsible for the global strategic coordination of Sulzer Pumps activities in the HPI. Mr. Parker has been in the pump industry for 38 years. He earned a BS degree in mechanical engineering from Northern Arizona University.

WATER TREATMENT DEVELOPMENTS

Onsite water services help refinery go from idle to online Assistance enables quick return to profitable production levels C. McCLOSKEY, Siemens, Hoffman Estates, Illinois

“I

t takes a lot of water to run a refinery and even more to start up a cold one.” —Charles McCloskey

A major US East Coast refinery recently started up after a lengthy shutdown and overhaul. The refinery needed assistance in restoring the purified water flow to the facility. Engineers were called on to inspect and recommend repairs and upgrades to critical components such as the raw water clarifiers, filters and demineralization systems. The refinery was provided with a mobile reverse osmosis (RO) treatment system to furnish up to 1,500 gallons per minute of boiler feedwater required to restart operations. Water is a critical component of the refining process, with an estimated 80 gallons of water required per barrel of oil converted. Steam is used extensively for process heating and fractionation. Copious amounts of cooling water are used in heat exchangers to condense the valuable end products of the refining process. Additional

water is required for onsite electricity generation to power the facility. A cold startup of process units is very water-intensive, as returned condensate can be significantly lower, intermittent and of unreliable quality, compared to normal steady-state operations. From idle to online. When new owners decided to bring the idle East Coast refinery back online to meet rising market demand, water was one of the first concerns addressed by the management team. To meet the aggressive schedule for returning the plant to profitable production levels, the refinery’s engineering team needed assistance. To illustrate what the refinery was looking at, as far as infrastructure goes, Fig. 1 shows the basic design of the plant’s water treatment system. Water for this refinery is available from multiple sources including wells, surface water and municipal supply (Table 1). Pretreatment is generally required for most waters to remove suspended solids and turbidity before further purification for pro-

cess water and steam production. The first step to restoring full water flow, therefore, was a detailed engineering review of the pretreatment system. The pretreatment system was originally designed to deliver 3,160 gpm and consisted of one cascade aerator, one flash mixer (7 ft square and 7.5 ft deep), two precipitators (each 38 ft square and 16 ft deep) and four gravity filters (each 18.51 ft wide, 21.33 ft long and 13 ft deep). As might be expected, the equipment had undergone significant modifications over the past 55 years of operation. An evaluation team detailed the condition of the equipment and alterations in the

RO trailers are fully instrumented for efficient operation.

Adjusting flow for maximum recovery.

Short-term operating contracts include all labor, chemicals and consumables. HYDROCARBON PROCESSING DECEMBER 2011

I 83

WATER TREATMENT DEVELOPMENTS

Flash mixer Weir box

Filtered water tank

No. 1

Filter water tank make-up

No. 2

To units 6 and 7

No. 3

No. 2 clariﬁer

No.1 clariﬁer

Reﬁnery condensate to power station

Demineralized water tank Reﬁnery condensate tank

Oily sewer No. 4 gravity ﬁlter

No. 3 gravity ﬁlter

Clear well make-up To domestic water Filtered water pumps

No. 2 gravity ﬁlter

No. 1 gravity ﬁlter

Clear well

Demineralized water to reﬁnery and power station Zeolite water to reﬁnery Raw water top/S&WWTP Raw water to mills

Lamella separator

Reﬁnery condensate pumps

Cascade aerator

To No. 4 zeolite

Water from north wells

Reﬁnery condensate to tank

Raw water inlet

Demineralized water pumps

Boiler wash pump

Backwash pump To zeolite units

Zeolite pumps

Pumps A/B

No. 5

Degasiﬁer No. 4

No. 4

No. 3

No. 2

No. 1 No. 3 demineralized degasiﬁer ab ad on

United water 6-in. line

No. 7

No. 6

No. 5

No. 4

No. 3

No. 2

No. 1

Demineralized degasiﬁer pumps

Demineralized water to storage

No. 1 demineralized degasiﬁer abandon

No. 6

Zeolite degasiﬁer

No. 1

No. 2

No. 3

No. 4

From 6 and 7 anions No. 7

Anion Zeolite Cation Carbon ﬁlter

United water 10-in. line United water pumps

FIG. 1

Basic design of plant’s water treatment system.

TABLE 1. Source water for refinery Constituent

Units

Well water

Surface water

Filtered Municipal water water

Calcium (Ca)

ppm as CaCO3

187

Magnesium (Mg)

ppm as CaCO3

783

Sodium (Na)

ppm as CaCO3

59.5

3,924

Potassium (K)

ppm as CaCO3

100

Bicarbonate (HCO3) Alkalinity

ppm as CaCO3

Carbonate (CO3) Alkalinity

ppm as CaCO3

Sulfate (SO4)

ppm as CaCO3

12.5

452

Chloride (Cl)

ppm as CaCO3

88.9

4,478

Silica (SiO2)

ppm

Conductivity

␮S/cm

330

3,000

250

330

Standard unit

7.6

7.5

7.7

7.6

NTU

150

< 1.0

15 minute basis

pH Turbidity SDI 84

I DECEMBER 2011 HydrocarbonProcessing.com

engineering report, and provided recommendations to replace critical components. The team also reviewed operations with onsite personnel and provided suggestions to improve the efficiency, consistency and reliability of the pretreatment system. A crucial component of the evaluation was that a complete set of original equipment drawings were recovered and presented to the new operators and engineering staff. The major conclusion of the study was that, while the system had aged, it was in serviceable condition to produce the design flow rate of 3,160 gpm. By following the recommendations, the useful life of the equipment could be even further extended. While plant personnel worked on the pretreatment system to implement the necessary changes, the timetable for the refinery restart required that at least 50% of the

WATER TREATMENT DEVELOPMENTS estimated 3,000 gpm of purified water be supplied in short order. The refinery contracted with an outside company to provide up to 1,500 gpm of treated water for boiler makeup to begin steam production. The temporary water system consisted of the following key components: • Three bag filtration skids. Each skid was rated for 1,000 gpm. Bag filtration using 10-micron bags provided an added layer of protection against turbidity fluctuations. • Four anti-scalant feed systems. Each RO trailer had its own dedicated antiscalant feed system. • Cartridge filtration. Cartridge filters were provided as a final filtration step prior to the RO units. Each RO unit had a housing that contained 12 30-in. cartridges. • 16 RO units. Each unit had a 3:2:14M array and 24 8-in. x 40-in. RO membranes. The unit was capable of delivering up to 100 gpm of RO permeate at 16.4 GFD flux and 75% recovery at a temperature of 40°F. Each unit had online feed and permeate conductivity monitoring, as well as permeate and concentrate flow indicators. • Four membrane separation trailers (MSTs). Each MST housed four RO units, and provided interconnecting piping, electrical distribution, lighting and heaters. • Four mobile deionization (DI) trailers. Each trailer consisted of two cation and three anion exchange vessels, each containing 90 ft3 of resin, and one mixed bed vessel containing 60 ft3 of resin.

ing service was employed to restore the capacity. Vessels were inspected, and linings and laterals were replaced as needed. Most of the cation resin was purchased and replaced. The contractor provided the engineering resources, parts and contract labor to support this effort. The contractor also provided tankering service to remove, separate and reload the resin while these tasks were completed. Work continues in this area to bring the water system up to full capacity.

Working with water treatment suppliers has enabled this refinery to go from cold to hot with nearly full water and steam production while ramping up its refining capacity. HP Charles (Chuck) McCloskey is the director of business development for mobile and onsite services for Siemens Industry, Inc. Mr. McCloskey is a graduate of Slippery Rock University of Pennsylvania, and has been actively involved with industrial water treatment applications for the past 34 years. He is located in Hoffman Estates, Illinois.

Becoming operational. Within days

of the go-ahead, the temporary system was up and delivering the desired water quality to the refinery’s power island. The system has operated without interruption for the past six months, consistently meeting the water quality specifications (Table 2). These are critical parameters for safe operation of the onsite 1,300-psig boilers. The next step was to restore the onsite demineralizer systems to full production capacity. Two systems are onsite: an older conventional design and a newer packedbed system. Resin analyses indicated that significant fouling of the anion resin had occurred over time. An onsite resin cleanTABLE 2. Water quality standards for system Parameter

Value

Conductivity

< 1 µS/cm

Silica

< 20 ppb

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FREE Product and Service Information—DECEMBER 2011 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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RS#

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Axens . . . . . . . . . . . . . . . . . . . . . 92

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I 89

HPIN AUTOMATION SAFETY WILLIAM GOBLE, CONTRIBUTING EDITOR wgoble@exida.com

Safety equipment qualification During a functional safety assessment of a packaged equipment manufacturer, the issue of instrumentation equipment qualification came up on the audit checklist. The IEC 61511 standard requires that all equipment used in a safety instrumented function be justified based on having either met requirements of IEC 61508 (IEC 61508 certified) or “prior use” experience. On this project, the equipment justification had not been done. So, we went through the details of the standard. At first, we were focused on the requirements for “prior use” justification. The standard itself is somewhat vague, lacking specifics such as the numbers of hours of field experience required or the level of vendor auditing required. Most end users do not feel comfortable with their failure-data collection systems. Records of successful proof testing are especially important, and, often, these results are not recorded, organized and retained. While this company had a failure-data collection system that was better than most, there was clearly a lack of comfort with the “prior use” approach. Problem solved. Much of the chosen instrumentation equipment was already functional safety certified per IEC 61508. That was good; no further work was required to justify safety integrity. But some pieces had no functional safety pedigree. We searched the Internet and found a safety automation equipment list. It contained hundreds of entries with equipment of most types certified by various certification agencies. For example, sensors included pressure, temperature, flow, level, flame detection, gas detection and others. The products were available from many different manufacturers with all the right functional safety and even cybersecurity certification. Several alternative products were selected that had the functional safety certification. Problem solved, right? When looking at the lists, it was clear that functional safety has come a long way in recent years. There were over 20 safety certified programmable logic controller (PLC) products. This makes sense since the safety certifications started with these products. Back in the mid-1990s, these microprocessor-based products were even prohibited by some companies. Functional safety certification provided some assurance that these products were sufficiently safe. Today, virtually every major distributed control system (DCS) manufacturer has produced a safety certified controller for use within their system. Several of the safety PLC vendors have even obtained cyber-security certification. Compare this situation to a decade ago. IEC 61508 had been released only for a couple of years. IEC 61511 was only a draft standard about to be released. There were only a few functional safety certified PLC-type products and one certified pressure transmitter that was made obsolete when the manufacturer was bought out by a larger company. Certified field equipment. The big changes are in the field equipment category. In addition to the sensors, over 100 products were listed in categories such as solenoid valves, pneu90

I DECEMBER 2011 HydrocarbonProcessing.com

matic actuators, hydraulic actuators, ball valves, butterfly valves, plug valves and specialty valves. I have heard some say, “Who cares?” “Why bother with field devices?” “These products are so simple that they could not cause a safety issue.” A deeper look shows the real story. In sensor products, some designs in the 2000s use 32-bit microprocessors with multi-tasking operating systems that are more complicated than the PLC designs of the 1990s. Once when I made this statement, I was challenged. “Why is there a need for more computing power in a simple pressure transmitter?” Manufacturers are improving products with faster response time and more features. Some of the newer devices have high-speed sampling of the pressure sensor with significant statistical analysis used for plugged impulse-line detection, etc. This functionality has no chance of actually working well without the available computing power of today. So like the complex microprocessor PLCs, it is appropriate that they be examined in the detail that comes with an IEC 61508 assessment. This leaves the simple ball valve. Why bother with looking at functional safety certification for that product class? In fact, functional safety assessment of products without complex microprocessors and software is a much simpler and limited job. Even so, the fundamental quality and safety principles still apply. It is surprising how many valve companies fail the audit due to fundamental issues. Successful companies make certain that their quality procedures, design testing, field-return feedback systems and user documentation are strong and rigorous. Successful companies learn to recognize the different operational profile of a low-demand safety application where the valve may sit motionless for years. They evaluate their products under those conditions and provide the needed information to help users design optimal safety instrumented functions. To me, it is comforting that things have changed for the better in this area of safety. It is almost like safety certification is becoming the defacto standard. Will all products have functional safety certification as standard? One vendor advertises this with the tagline “Safety is not an option.” Much like the early days of intrinsic safety, when special instruments were sold as an option, functional safety is this way with many current product lines. As things move forward, we should expect functional safety certification to be standard, just as electrical safety ratings are today. This will save time and money on all safety projects. HP The author is a principal partner of exida.com, a company that does consulting, training and support for safety-critical and high-availability process automation. He has over 25 years of experience in automation systems, doing analog and digital circuit design, software development, engineering management and marketing. Dr. Goble is the author of the ISA book Control Systems Safety Evaluation and Reliability. He is a fellow member of ISA and a member of ISA’s SP84 committee on safety systems. Dr. Goble can be reached by e-mail at: wgoble@exida.com.

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