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PROCESS DESIGN Dynamic models improve safety for high-pressure vessels ®

ENVIRONMENT Investigation reviews inert gas usage

HydrocarbonProcessing.com | MAY 2014

SAFETY Hazard analysis identifies alarm/control problems

SPECIAL REPORT:

Maintenance and Reliability

SENTRON LD 5000 Field Tested. Field Proven.

Petro-Canada is a Suncor Energy business TM

Trademark of Suncor Energy Inc. Used under licence.

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MAY 2014 | Volume 93 Number 5 HydrocarbonProcessing.com

21

10

52 SPECIAL REPORT: MAINTENANCE AND RELIABILITY 53

Reliability tips for centrifugal process pumps H. P. Bloch

61

Micro-alloyed steel: New standard for reformer tubes A. Steckmeyer, B. Fournier, H. Chasselin and C. Mougel

67

Evaluate piping for displacement-controlled loading J. Tharakan and M. Anisuzzaman

PROCESS DESIGN 71

Use dynamic models when designing high-pressure vessels J. Renfro, G. Stephenson, E. Marques-Riquelme and C. Vandu

REFINING DEVELOPMENTS 77

DEPARTMENTS 4 10 21 23 101 102 104 106

COLUMNS 9 Editorial Comment What separates the best-of-class companies from the rest?

25

Innovative catalyst solution mitigates FCC operational issue

back to service faster

29

M. Sawyer

ENVIRONMENT 99 What every refiner should know about nitrogen generation and delivery

Automation Strategies The automation challenge requires new approaches

31

Project Management Better strategies avoid project delays—Part 2

J. Hair

SAFETY 95 Minimize false assurances in hazard analyses

Reliability Make equipment decisions with up-to-date technical information

J. Sexton, J. Highfield, N. Larsen, S. Ismail and D. Neuman

TERMINALS AND STORAGE—SUPPLEMENT T-85 Use innovative solutions to return storage tanks

Industry Perspectives News Forum Industry Metrics Events Marketplace Advertiser Index People

37

Global Russian executives to build country’s first waste oil refinery

39

Petrochemicals Ammonia production booms on cheap natural gas

43

Gas Processing Asian gas market seeks lower pricing, infrastructure expansion: Part 1

D. Connaughton

45 Cover Image: In Rotterdam, an entire refinery was shut down, modernized and put back into operation. Bilfinger is the specialist for these extensive turnarounds. Photo courtesy of Bilfinger SE.

Boxscore Construction Analysis Qatar’s petrochemical sector surges through new projects

49

Viewpoint What characteristics define the world’s best refineries?

www.HydrocarbonProcessing.com

Industry Perspectives Reflections from a petrochemical giant Frank Popoff, retired chairman and CEO of the Dow Chemical Co., shared his insight on the petrochemical industry at the AFPM’s 2014 International Petrochemical Conference (IPC). With a career spanning over 41 years, Mr. Popoff has witnessed the evolution of the petrochemical industry between two Gulf coasts—the US and the Middle East. As a former leader of an international petrochemical company, Mr. Popoff shared some observations on the industry to IPC attendees. First, expect change in the business cycle; more importantly, embrace it. Since its inception, the petrochemical industry has always followed cycles. Unfortunately, companies still over-invest in new capacity at the top of the business cycle, thus creating an overcapacity situation. Second, change within the petrochemical industry is accelerating. Operating companies are enduring pressures internally and externally that are linked to underperformance, especially with respect to profits. Reality vs. perception. Mr. Popoff also remarked that the public

has a disconnected view of the downstream. In the 1950s, the petrochemical industry was viewed as an innovative and high-tech industry. Fast-forward to present day, the petrochemical industry is very disconnected from the public and the regulatory agencies. More importantly, younger people do not consider employment opportunities in the petrochemical industry. This perception of the industry must change. Advice from a veteran. How can the downstream change its

image? Mr. Popoff advised: First, companies will be judged by their deeds, and not by their media programs. Petrochemical companies must be active and visible in their communities. Corporate creditability is the key to success and the legacy of the industry.

PUBLISHER

P. O. Box 2608 Houston, Texas 77252-2608, USA Phone: +1 (713) 529-4301 Fax: +1 (713) 520-4433 [email protected] Bret Ronk [email protected]

EDITORIAL Editor Managing Editor Reliability/Equipment Editor Technical Editor Online Editor Associate Editor Director, Data Division Contributing Editor Contributing Editor Contributing Editor

Stephany Romanow Adrienne Blume Heinz P. Bloch Billy Thinnes Ben DuBose Helen Meche Lee Nichols Loraine A. Huchler William M. Goble ARC Advisory Group

MAGAZINE PRODUCTION Vice President, Production Manager, Editorial Production Artist/Illustrator Graphic Designer Manager, Advertising Production

Sheryl Stone Angela Bathe David Weeks Amanda McLendon-Bass Cheryl Willis

ADVERTISING SALES See Sales Offices, page 104.

CIRCULATION Director, Circulation

Suzanne McGehee +1 (713) 520-4440 [email protected]

SUBSCRIPTIONS Subscription price (includes both print and digital versions): Print—One year $239, two years $419, three years $539. Digital format—One year $239. Airmail rate outside North America $175 additional a year. Single copies $35, prepaid. Because Hydrocarbon Processing is edited specifically to be of greatest value to people working in this specialized business, subscriptions are restricted to those engaged in the hydrocarbon processing industry, or service and supply company personnel connected thereto. Hydrocarbon Processing is indexed by Applied Science & Technology Index, by Chemical Abstracts and by Engineering Index Inc. Microfilm copies available through University Microfilms, International, Ann Arbor, Mich. The full text of Hydrocarbon Processing is also available in electronic versions of the Business Periodicals Index.

ARTICLE REPRINTS If you would like to have a recent article reprinted for an upcoming conference or for use as a marketing tool, contact 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 [email protected]. Hydrocarbon Processing (ISSN 0018-8190) is published monthly by Gulf Publishing Company, 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 © 2014 by Gulf Publishing Company. 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.

FIG. 1. Former Dow Chemical Chairman Frank Popoff (left) is presented with the 18th Petrochemical Heritage Award by Jerry Law, president of the Founders Club.

President/CEO Vice President Vice President, Production Editor-in-Chief Business Finance Manager

Part of Euromoney Institutional Investor PLC. Other energy group titles include: World Oil and Petroleum Economist Publication Agreement Number 40034765

4MAY 2014 | HydrocarbonProcessing.com

John Royall Ron Higgins Sheryl Stone Pramod Kulkarni Pamela Harvey

Printed in USA

BEING FLEXITALLIC SAFE IS THE RESULT OF USING NEW MATERIALS THAT BETTER WITHSTAND TEMPERATURE AND PRESSURE EXTREMES. CO-ENGINEERED SEALING SOLUTIONS. AND ONSITE BOLT TRAINING TO IMPROVE INSTALLATION—A MAJOR FACTOR IN FLANGE FAILURE.

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JULY 30–31, 2014 2014 2014 Speakers Include:

V.K. Arora Director-Process & Operations Kinetics Process Improvements, Inc

Norris Conference Centers – CityCentre Houston, Texas

Hear from Experts at the Forefront of GTL Technology Join us for the second annual GTL Technology Forum, to be held July 30-31, 2014 in Houston, Texas, as we explore the latest trends and cutting-edge solutions at work as GTL usage and products continue to gain momentum. Over the course of two-days, attendees will hear from experts at the forefront of GTL technology regarding the economics of GTL, market opportunities, the latest products and developments, case histories, new project announcements and more. Register online today at GTLTechForum.com.

2014 Sessions will Focus on: • Syngas • What’s new in small scale GTL? • Catalysts

• The future of non-FT • Emerging technology and future users • Modular construction

Panel Discussions Devoted to: George Boyajian Vice President, Business Development Primus Green Energy

• Modular GTLs

• Future uses of GTL

Real-World Case Studies on: • GTL technology development-The optimal path to Micro-GTL commercialization • Refinery integration with gasification >> Plus, attendees will hear presentations on the economics of natural gas and ammonia production from off-gases. Don’t miss this opportunity to learn from industry experts and connect with top operators and technology leaders from across the global industry.

Who Should Attend: Jeff McDaniel Commercial Director Velocys

• Professionals at Engineering & Construction • Petrochemical, Lubricant, Refining, and Process Control Companies • Specialized Equipment Providers and Consultants.

Ways to Participate: To Register Offline: Gwen Hood, Events Manager, at +1 (713) 520-4402 or [email protected]. Speaker Inquiries: Melissa Smith, Events Director, at +1 (713) 520-4475 or [email protected]

Ebrahim Salehi Process Engineer Hatch

Sponsor/Exhibitor Inquiries: Lisa Zadok, Events Sales Manager, at +1 (713) 525-4632 or [email protected]

GTLTechForum.com

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SAVE 10% 2014 Agenda at a Glance: Wednesday, July 30, 2014

Thursday, July 31, 2014

8:45 a.m.

Keynote Presentation

8:45 a.m.

Keynote Presentation

9:15 a.m.

The Economics of Monetizing North American Natural Gas Tom Jones, Manager of Studies, Bechtel Hydrocarbon Technology Solutions, Inc.

9:15 a.m.

Economics of Ammonia Production from Off-Gases VK Arora, Director-Process & Operations, Kinetics Process Improvements, Inc

Session 1: Syngas 10:10 a.m.

Co-processing of Waste CO2 with Natural Gas to Produce High Value Transport Fuels Paul E Koppel, Vice President, Process Technology, Fluor Enterprises

10:35 a.m.

Autothermal Reforming – a Preferred Technology for Conversion of Natural Gas to Synthesis Gas in Industrial GTL Applications Neils Udengaard, Haldor Topsoe

11 a.m.

Partial Oxidation Gas-Turbine Based Turbo-POx Syngas Generation Technology for GTL Applications Kenneth Sprouse, Chief Technology Officer, Aerojet Rocketdyne Energy Systems

11:25 a.m.

Session 4: Emerging Technology and Future Users 10:10 a.m.

Mixed Alcohols as an Oxygenate and Fuel Extender Peter Tijm, Chief Technology Officer, Standard Alcohol Company of America, Inc.

10:35 a.m.

Case Study: Refinery Integration with Gasification Dr. K.S. Balaraman, Chief Consultant, Wissenschaftler Consulting Engineers

11:05 a.m.

Panel Discussion: Future Uses of GTL

12:30 p.m.

Lunch

Session 5: Catalysts 1:30 p.m.

Effect of Addition of Zeolite to Iron-Based Activated-Carbon-Supported Catalyst for Fischer–Tropsch Synthesis in Separate Beds and Mixed Beds Avinash Karre, Jacobs Engineering

1:55 p.m.

The New CatFTTM Process Dr. Thomas Holcombe, President & CEO, EnviRes LLC

Lunch

Session 2: The Future of Non-FT 12:25 p.m.

CO2 and CO fermentation: A Route from Waste to Fuels and Chemical Building Blocks at Scale Dr. Michael Schultz, Vice President, Engineering, LanzaTech, Inc

12:50 p.m.

A New Era in GTL: Cost-Effective Technology Enables Conversion of Natural Gas to Drop-In Liquid Fuels at Small Scale Dr. George Boyajian, Primus Green Energy

Session 3: What’s New in Small-Scale GTL 2:10 p.m.

2:35 p.m.

3:05 p.m.

Microchannel Fischer-Tropsch Reactors: Enabling Smaller Scale GTL Jeff McDaniel, Commercial Director, Velocys Case Study: GTL Technology Development – The Optimal Path to Micro-GTL Commercialization Ebrahim Salehi, Process Engineer, Hatch

Session 6: Modular Construction Presentations TBD

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Panel Discussion: Modular GTLs

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Customer:

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Challenge:

Q

Result:

Refinery, Louisiana, USA. Increase reliable, on-site power generation within the plant’s existing carbon footprint. An Elliott 36 MW FCC hot gas expander-generator converts refinery waste gas to electrical power.

They turned to Elliott for “green,” reliable power. The customer turned to Elliott because of our 50 years of experience and nearly 500 MW of installed capacity in FCC power recovery. Elliott TH expanders routinely operate 5 years and more between shutdowns, extending FCC maintenance cycles and reducing maintenance costs. Who will you turn to?

EBARA CORPORATION

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The world turns to Elliott. www.elliott-turbo.com

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Editorial Comment

STEPHANY ROMANOW, EDITOR [email protected]

What separates the best-of-class companies from the rest? Many metrics can be used to define the top-performing downstream companies. Often, it includes financial (profits) results, environmental and safety performance, equipment availability and more. However, organizational culture probably has the most impact in determining a company’s performance. Also, it is the most difficult to change. Before a company can change its performance, it must amend or upgrade its organizational culture. Managing people is the toughest task. A recent UK health, safety and en-

vironment (HSE) research program identified the top five human-factor errors. These factors, sourced from previous organizational accidents listed in HSE databases, are: 1. Managing people 2. Procedures 3. Training and competence 4. Staffing 5. Organizational changes. As the downstream workforce undergoes a significant shift change when experienced employees retire, the listed human factors will have an even higher impact on an organization’s performance. Staffing and training will carry heightened concerns as employers plan for a smaller workforce undertaking vital roles in the operation of process units and the maintenance of equipment. More important, what resources will be used to train and certify plant operators and crafts? As fewer younger people enter apprentice and craft training programs, the pool of qualified and competent employees shrinks. Maintenance is a key priority for topperforming facilities. Achieving high

equipment availability is an organization’s ability to minimize the amount of annualized turnaround downtime. The less time that key equipment or process units are down for repair increases the uptime of

the facility. The world’s best downstream companies minimize both the duration and the cost during a turnaround by rigorously challenging all of the work done and how that work is executed. By using state-of-the-art techniques for inspection and repair, they are able to achieve performance that significantly outpaces the rest of the world. The organizational culture on maintenance is evolving. Predictive maintenance programs strive to monitor equipment and to do planned shutdowns, thus shortening the total duration for repairs. Training. Employees come to work with skills, knowledge and experience, and they are trained for plant tasks. However, there are huge performance differences among operators. Some are competent and some not so much. The goal is to ensure that they all are truly competent, but that may not always be the case. Organizations cannot just wave a magic wand and fix all problems. Without standards or discipline, it can take years to resolve the problem. The fix. “Human error is a normal func-

tion of humans; it is inevitable, but it may be preventable,” said Ian Nimmo, president & CEO, of the Center for Human Factors and Ergonomics, LLC. Everyone makes mistakes and has lapses in attention. Accordingly, management systems and tools should be used to reduce error rates. Nimmo recommends that an organization invest in a gap analysis and prepare strategic operational plans to identify a comprehensive investment plan. The plan will itemize a path to achieve total performance improvements in a prioritized way. Human error introduces risk that must be addressed. Only when the holes in the protection system are sealed and performance is measured, then companies can find profits.

INSIDE THIS ISSUE

49 Viewpoint.

What defines the world’s best refineries? New process equipment and a higher refinery complexity index do not guarantee a place on the world’s best refineries. Other metrics, such as return on investment, energy efficiency, net cash margins, maintenance practices and more, separate leading from laggard performance in the global refining industry.

and 52 Maintenance reliability.

Operating companies use maintenance programs to protect their capital investments. Since equipment failures can result in expensive unit and plant shutdowns, or environmental or safety incidents, best-of-class companies maintain the mindset that spending to improve reliability and equipment conditioning is a great benefit to the organization.

71 Process design.

In this article, rigorous models are used to simulate effective depressurization procedures for high-pressure vessels containing hazardous gases and liquids. Well-designed depressurized events review changes in the vessel’s contents (vapor and liquids) and the effects from changing pressure and temperature on these fluids. Extremes in temperature and pressure impact material choices to construct such vessels.

95 Safety.

Hazard analysis is a powerful and effective tool to evaluate potentially hazardous plant and process conditions. What are the best methods to use when identifying job hazards involving maintenance and operational tasks? This article reviews several proven methodologies to consider when performing process safety reviews. Hydrocarbon Processing | MAY 20149

| News EU-US Energy Council discusses European energy security The EU-US Energy Council met recently in Brussels, Belgium. Following the gathering, the council issued a statement indicating that developments in Ukraine prove the need for reinforced energy security in Europe. “The Council underscored that energy relations with Russia must be based on reciprocity, transparency, fairness, non-discrimination, openness to competition and continued cooperation to ensure a level playing field for the safe and secure supply of energy,” the statement said. Another result of the meeting was that the Council affirmed its support for Ukraine’s efforts to diversify its supplies of natural gas, including through the rapid enhancement of reverse flow capacities and increased gas storage capacity. The Council also issued remarks supporting the restructuring and reform of Naftogaz.

BILLY THINNES, TECHNICAL EDITOR [email protected]

News

While US total net crude oil imports fell during 2013, the share of imports last year from the US’ top three foreign oil suppliers—Canada, Saudi Arabia and Mexico—was the highest in at least four decades, according to preliminary annual trade data from the US Energy Information Administration’s (EIA’s) Petroleum Supply Monthly report (FIG. 1). These three countries provided almost three out of every five barrels of oil imported into the US market last year. US net crude oil imports in 2013 declined 10.2% to 7.6 million barrels per day (MMbpd), the lowest level since 1996, as rising domestic crude oil production cut into the import volume needed to meet refinery demand. The overall decline in US net imports has led to an increasing concentration of net imports from Canada, Saudi Arabia, and Mexico. Combined net oil imports from these countries decreased by 1.5% last year. As a result, the 4.6 MMbpd of oil supplied by these three countries accounted for 61% of total US net oil imports in 2013, up from 55% the year before and their biggest share since at least 1973. These countries generally produce medium to heavy sour crude oil that is desirable to US refineries, while increasing US crude oil production from tight oil formations is typically of the light sweet quality. Also, with the exception of Saudi Arabia, these countries are near the US, with Mexico having a short shipping distance for its oil to the large number of refineries along the US Gulf Coast. Canada, Saudi Arabia and Mexico have consistently been America’s three largest crude oil suppliers, although their rankings vary from year to year. Canada. Crude oil imports averaged a record 2.5 MMbpd, up 3.9% from 2012. Canada has few other outlets for Alberta’s rising heavy crude oil production, so most of it is exported to the US.

Saudi Arabia. Crude oil imports averaged 1.3 MMbpd, down 2.6%, but still the second highest in five years. Through its Motiva Enterprises joint venture, the country’s state oil company is a partial owner of three large US Gulf Coast refineries that it partially supplies with Saudi crude. Mexico. Crude oil imports of 850,000 bpd were down 13% and the lowest in more than 20 years, reflecting the continued decline in Mexico’s crude oil production. Still, Mexico produces significant amounts of heavy crude that is well-suited for US Gulf Coast oil refineries.

Oil spill contained at S-Oil Korean refinery S-Oil’s refinery in Ulsan, South Korea, suffered an oil spill from a storage tank in early April. The spill was contained after three days, but not before 140,000 bbl of crude had leaked. To mitigate further problems with the damaged storage tank, refinery officials relocated an additional 380,000 bbl of crude. The spill started after a broken blending mixer created a hole in the storage tank. The refinery will conduct an investigation into the exact cause of the accident

in cooperation with the police and the fire authorities of Ulsan.

Murphy Oil’s Wales refinery facing closure Murphy Oil has indicated it could be forced to close its Milford Haven refinery in Wales, UK, after talks with a private equity firm collapsed. Murphy’s UK subsidiary Murco said it had started 45 days of consultation with employees and their representatives on the future of the 135,000 bpd refinery. UK refining remains a challenging market, caused in part by declining demand and increased international completion, Murco said in a statement. The UK has seven oil refineries, down from a peak of 18 in the 1970s. Murphy Oil has negotiated with numerous parties but has not yet been able to find a buyer for the refinery. Private equity company Greybull had been in advanced stages of talks with Murco to buy the plant and associated assets for around $500 million, but exclusive talks between the two entities have expired. “Our focus today is on helping our people understand what this means for them,” said Murco’s Director Tom McKinlay.

12 US annual net crude imports 2003–2013, MMbpd

US crude imports fall, but share of top suppliers highest in decades

Other nations Mexico Saudi Arabia Canada

10 8 6 4 2 0

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

Source: US EIA, February 2014 Petroleum Supply Monthy

FIG. 1. US annual net crude imports, 2003–2013. Hydrocarbon Processing | MAY 201411

News “For over three years, we have left no stone unturned in trying to find a buyer for the plant. Our efforts highlight the challenges and ongoing changes confronting the European refining industry and are in no way a reflection on the attitude and work ethic of the Murco team. We will continue to do all we can to ensure our employees are supported during this time.” The plant employs 370 staff and between 100 and 150 contractors.

BP to close Bulwer Island refinery in Australia BP intends to halt refining operations at its 102,000-bpd Bulwer Island refinery in Brisbane, Queensland, Australia, by mid-2015. Andy Holmes, president of BP Australasia, said that the growth of very large refineries in the Asia-Pacific region was driving structural change within the fuels supply chain in Australia

and putting huge commercial pressure on smaller-scale plants. “It’s against this background that we have concluded that the best option for strengthening BP’s long-term supply position in the East Coast retail and commercial fuels markets is to purchase product from other refineries,” he said. “And while more of our transport fuel demand will be met by imports in the future, ample supplies are available to maintain Australia’s energy security.” To ensure no disruption to customers, alternate supply arrangements have been made. This includes imports of jet fuel and a long-term agreement with Caltex to supply motor spirit and diesel from the nearby Lytton refinery. It is expected that it will take some 12 months to implement the changes required to maintain supply and safely shut down the process units. Once processing has been halted, the import jetty, aviation fuel tanks and associated pipelines will remain operational while other storage tanks and pipelines will be placed on a care and maintenance basis pending a decision to convert the site to a multi-product import terminal. The processing units will be isolated and made safe while plans for their eventual removal and any environmental remediation are developed. BP currently employs some 380 staff at the refinery. Between now and mid2015, this is expected to fall to around 25. The Bulwer Island refinery was built on reclaimed land by Amoco between 1964 and 1965 and was bought by BP in 1984. Over the years, it has been subject to a number of modifications and improvements. In 2000, it was significantly upgraded to produce low-sulfur fuels.

IChemE unveils new process safety alliance with Texas A&M The Institution of Chemical Engineers (IChemE) and Texas A&M Engineering have signed an agreement paving the way for a suite of new process safety products and services. The memorandum of understanding (MOU) will see both organizations commit to collaboration in process safety education and strategic leadership. The Texas A&M Engineering Experiment Station is home to the Mary Kay O’Connor Process Safety Center, which 12

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INNOVATIVE SOLUTIONS FOR THE HYDROCARBON PROCESSING INDUSTRY –––––– Bilfinger’s engineering department constantly works to offer the best and innovative solutions to the Hydrocarbon Processing Industry: JOHNSON SCREENS® SHAPED SUPPORT GRID (SSG) designed to be installed into the bottom head of hydroprocessing or gas dehydration vessels, allowing better liquid and gas flow, bed utilization, distribution and an overall more efficient process than traditional flat surface grid assemblies. Patented design.

JOHNSON SCREENS® INLET DIFFUSER BASKET designed to control velocities of gas or liquid distribution over media, providing improved performance over traditional plate disc type distributor designs as well as even distribution and minimal scouring at the top of the bed. Patented design.

–––––– BILFINGER WATER TECHNOLOGIES www.water.bilfinger.com Australia - Asia Pacific Phone +61 7 3867 5555 Fax +61 7 3265 2768 [email protected]

France Phone +33 5 4902 1600 Fax +33 5 49021616 [email protected]

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North & South America Phone +1 651 636 3900 Fax +1 651 638 3171 [email protected]

News houses one of the world’s biggest process safety libraries and is regarded as a leader in process safety education. The MOU was signed at the American Institute of Chemical Engineers 2014 Spring Meeting in New Orleans, Louisiana, by IChemE chief executive David Brown and Sam Mannan, director of the Mary Kay O’Connor Process Safety Center. “This is good news for IChemE and good news for Texas A&M, but, impor-

tantly, this is good news for chemical and process engineers with an interest in process safety,” Dr. Mannan said. The collaboration’s projects and priorities will be announced at IChemE’s Hazards 24 process safety conference next month in Scotland. “Texas A&M and IChemE are both recognized as international leaders in the provision of process safety products and services,” Mr. Brown said. “This new

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agreement will help us to share information more freely and cooperate on a range of new projects.”

Siemens and McAfee team up to offer industrial security services Siemens and McAfee, a division of Intel Security, are extending their partnership to enhance the security offerings for industrial customers to protect against rapidly evolving global cyber threats. This partnership utilizes the depth of both companies’ security portfolios and further enhances the joint effort started in 2011. Industrial customers face unique new challenges including a wider range of cyber threats than ever before. They often lack the resources necessary to respond efficiently to security incidents, and they do not have access to the global threat intelligence that would allow proactive defensive measures. This critical information is needed in order to keep up with evolving government regulations, industry standards, sector-specific best practices, and other risk information necessary for making informed business decisions. The cooperation with McAfee will complement Siemens’ service offerings by leveraging security solutions such as next-generation firewall, security information and event management, endpoint security, and global threat intelligence as part of its managed security service along with offering professional services. These offerings provide greater visibility and control at the factory level while reducing the risk of intellectual property theft. In addition, the companies will continue to cooperate on the development of security products and solutions, specifically based on industrial protocols, that will enhance managed security service offerings for the process and factory automation industry.

Air Products to supply nitrogen for Singapore hub to store petrochemicals Air Products was awarded a contract to supply liquid nitrogen to Singapore’s Jurong Rock Caverns ( JRC) project, an underground storage facility for petrochemical products. It is the first of its kind in the country and across Southeast Asia.

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News JRC is being developed by the JTC Corp., a government agency responsible for industrial infrastructure development in Singapore. Located on Jurong Island, the JRC project will complement and enhance the existing infrastructure and support the growth of the chemicals and energy clusters. Air Products’ liquid nitrogen will be used as a blanketing gas for the oil storage caverns for safety purposes. “We are honored to have been selected by JTC to take part in and supply this groundbreaking solution to oil storage needs,” said Leong Wah Fong, managing director of Air Products Southeast Asia. “Singapore’s energy and chemical industry is a strategic market for us and we have built a foundation to serve its needs through diverse supply modes.” Air Products began serving petrochemical customers on Jurong Island in 1997 through an air separation plant located at Sakra. To meet the increasing gas demand in Singapore’s major chemical hub, the company has recently announced a pipeline extension from the area to the newly developed areas in Tembusu to expand coverage. In addition to the air separation plant on Jurong Island, the company also has a fleet of road tankers delivering liquid products, a helium and specialty gas plant in Senoko and an epoxy additives and a polyamide plant in Gul Crescent.

be aided by regulatory changes—particularly regarding potable water quality, diesel engine emissions and pollution from electric utilities—supporting sales of existing filters and the development of new products. The improved outlook for manufacturing and capital investment will also support filter demand stemming from greater purchases of equipment that require filters. The motor vehicle market will continue to account for the largest portion of to-

tal demand, with a 27% share in 2018, owing to the high volume of filters sold both as original equipment and in the aftermarket. Motor vehicle filter demand will be supported by a rising number of vehicles in use and increasingly strict standards for vehicle emissions. Value growth will also be supported by the introduction and increasing adoption of newer products, such as cabin air filters and other specialty and high-value vehicle filters. Demand for

US demand for filters to reach $14.8 billion in 2018 US demand for filters will advance 3.6% annually to $14.8 billion in 2018, with replacement demand accounting for the vast majority of filter sales. This is according to a report from The Freedonia Group. “The filter aftermarket will be aided by the increasing penetration of newer products,” said report contributor David Petina, “particularly motor vehicle cabin air filters, diesel emissions filters, and many varieties of home air and water filters, as well as rising end-user awareness of their recommended service lives.” The development of filters featuring technologies that extend their service life will have a mixed impact on demand, boosting sales since they are priced at a premium, but also restraining demand in volume terms. Both the original equipment and replacement filter markets will Select 153 at www.HydrocarbonProcessing.com/RS

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News filters in the industrial and manufacturing, consumer, and utilities markets will all witness above-average growth. In 2013, fluid filters and internal combustion engine and related filters accounted for 37% and 35% of total filter sales, respectively. However, air filters, which represented the remaining 28% of sales in 2013, will achieve the fastest gains through 2018, benefiting from changes in pollution regulations, improvements in manufacturing activity, rising consumer interest and rebounding construction spending.

health, safety and environmental (HSE) programs and initiatives. “Our employees are our most valued asset and we are committed to their wellbeing,” said Vincent Volpe, Dresser-Rand’s CEO. “Safety is a core, critical company value. Our total recordable injury rate for 2013 was 0.38—a great result and one of which we are extremely proud.” The judges of the Gulf Coast Oil & Gas Awards reviewed more than 400 entries

and selected 75 finalists. Dresser-Rand was one of four finalists in the health and safety category. “This recognition elevates our commitment to becoming an operationally excellent company without injuries,” said Peter Salvatore, Dresser-Rand’s chief safety officer. “Our ultimate goal is to eliminate workplace injuries through disciplined processes, execution and employee empowerment and engagement.”

US approves Jordan Cove LNG exports in Oregon The US Energy Department has conditionally authorized the Jordan Cove Energy Project to export domestically produced LNG to countries that do not have a free-trade agreement (FTA) with the US. The exports will originate from the Jordan Cove LNG terminal in Coos Bay, Oregon. The Jordan Cove application was next in the order of precedence after the Energy Department conditionally authorized the proposed Cameron LNG facility, according to department officials. Subject to environmental review and final regulatory approval, the facility is conditionally authorized to export at a rate of up to the equivalent of 0.8 Bcfd of natural gas, for a period of 20 years. US federal law generally requires approval of natural gas exports to countries that have an FTA with the US. For countries that do not have an FTA with the US, the Natural Gas Act directs the US Department of Energy (DOE) to grant export authorizations unless the DOE finds that the proposed exports “will not be consistent with the public interest.” “Given the situation in Ukraine, this license sends a positive signal to our allies and to energy markets that the United States is ready to join the growing global gas trade,” US Senator Lisa Murkowski (R-Alaska) said. “While this license moves us in the right direction, I would be strongly opposed to any ‘pause for further study,’ as some have proposed.”

Dresser-Rand wins US Gulf supplier safety award

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19

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GULF PUBLISHING EVENTS [email protected]

Forum

IRPC 2014: Defining the course of the global HPI Leading hydrocarbon processing industry (HPI) executives and technical experts will come together June 24–26 in Verona, Italy, to share ideas, innovation and vision for the global downstream industry at Hydrocarbon Processing’s fifth annual International Refining and Petrochemical Conference (IRPC). As major forces reshape the HPI, managers and engineers are actively seeking information and solutions to make their companies more efficient, to increase equipment reliability and to meet safety and environmental regulations. Many downstream products are commodity products and traded worldwide. To participate in the international downstream markets, HPI companies will put into action innovative technologies and ideas to improve the profitability and performance of existing plants. Such developments will be used to build grassroots plants. Where innovation happens. IRPC

2014 will feature more than 70 technical presentations by company leaders, managers, engineers and other professionals. In addition, the 2014 forum will use three technical tracks to cover the broad spectrum of HPI topics and disciplines. The tracks are refining, petrochemicals and biofuels. The refining track will address the processing of heavy oil into clean transportation and marine fuels. Presentations will address new processing technologies to handle present-day crudes, and heavy and extra-heavy feedstocks. The petrochemicals track will focus on olefins and aromatic operations and demand trends. The biofuels track will feature next-generation biofuels and the methods to integrate them into transportation fuel systems. Other technical sessions are dedicated to energy efficiency, process optimization, corrosion mitigation/prevention methods, petrochemical-refinery integration, clean fuel technologies, advanced catalytic

technologies, licensed technologies for refining and petrochemicals, water management, process control, process modeling / simulation, maintenance techniques and planning and plant management. The conference will feature several keynote presentations. Giacomo Respoli, Vice President of Research and Development Projects of Eni SpA, will discuss the design of Eni’s biorefinery and the future of the downstream. On Day 2, Bakheet Al-Rashid, CEO and president of Kuwait National Petroleum, will share his view on the European refining industry and the factors reshaping the region. Forefront of the industry. The HPI is a global industry; success hinges on companies and their staff finding accurate and vital information in real time to make informed and profitable decisions. At IRPC 2014, HPI professionals will have the opportunity to network and brainstorm with executive and leaders that are charting the course of the global HPI. Meeting place for the global HPI. Companies involved in the following areas will benefit from attending IRPC: refining, natural gas processing, technology and equipment manufacturing, consult-

ing, construction and engineering, chemicals and petrochemicals, and oil and gas services and supplies. Eni’s Venice biorefinery tour. IRPC

2014 will begin with an exclusive tour of Eni’s Venice biorefinery, the first refinery in the world to convert from a conventional refining complex into a biofuel-production operation based on Eni’s patented Ecofining technology. Following the conversion, the Venice biorefinery will be able to produce highgrade biofuels, including green diesel, green naphtha, LPG and, potentially, jet fuel, from biological raw materials to meet the EU directive on renewable energy and derive 10% of energy in conventional fuels from renewables by 2020. With the startup of the green refinery, Eni will be able to produce around 300,000 tpy of green diesel in 2014. The feedstock will initially be palm oil; in the second phase, the green refinery will process animal fats, used oil, oils from algae and other types of biological waste. For more information about the 2014 International Refining and Petrochemical Conference, hosted by Gulf Publishing Company and Hydrocarbon Processing, please visit HPIRPC.com.

FIG. 1. A tour of Eni’s Venice biorefinery is a preconference event. This refinery is converting from a conventional refining complex to biofuel production. Hydrocarbon Processing | MAY 201421

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Industry Metrics

40 35 30 25 20 15 10 5 0 -5

6

Feb 14

Jan 14

Dec 13

Nov 13

Oct 13

Sep 13

Aug 13

Jul 13

Jun 13

May 13

80

Mar 14

Jan 14

Dec 13

Nov 13

Oct 13

Sep 13

Mar 13

Aug 13

60

Production equals US marketed production, wet gas. Source: EIA.

Feb 14

US EU 16 Japan Singapore

70

Jul 13

1 0

Jun 13

2

90

May 13

F M A M J J A S O N D J F M A M J J A S O N D J F 2013 2014 2012

3

Apr 13

Monthly price (Henry Hub) 12-month price avg. Production

100 Utilization rates, %

4

Global refining utilization rates, 2013–2014* Gas prices, $/Mcf

Production, Bcfd

5

Apr 13

7

Mar 14

WTI, US Gulf Dubai, Singapore Arab Heavy, US Gulf LLS, US Gulf Brent, Rotterdam

Mar 13

US gas production (Bcfd) and prices ($/Mcf) 80 70 60 50 40 30 20 10 0

Global refining margins, 2013–2014* Margins, US$/bbl

The OPEC Reference Basket for crudes fell $1.23 in March. Changes in the crude oil markets are attributed to a slowdown in China’s economy and reduced crude oil demand by refineries. Non-OPEC supply growth is expected to outpace global consumption growth and stabilize oil prices. North America leads in new production stemming from shale oil in the US and growth in the Canadian oil sands. Global product markets are expected to receive support from increased diesel and gasoline demand by OECD nations.

Selected world oil prices, $/bbl 135

US Gulf cracking spread vs. WTI, 2013–2014*

World liquids fuels supply and demand, MMbpd

01 Nov 08 Nov 15 Nov 22 Nov 29 Nov 06 Dec 13 Dec 20 Dec 27 Dec 03 Jan 10 Jan 17 Jan 24 Jan 31 Jan 07 Feb 14 Feb 21 Feb 28 Feb 07 Mar 14 Mar 21 Mar 28 Mar 04 Apr

Apr 14

Mar 14

Feb 14

Jan 14

Dec 13

Nov 13

Oct 13

Sep 13

Aug 13

Jul 13

Jun 13

Apr 14

Mar 14

Feb 14

Jan 14

Dec 13

Nov 13

Oct 13

Sep 13

Apr 14

Mar 14

Feb 14

Gasoil, 50 ppm S Fuel oil, 180 CST, 2% S

Jan 14

Prem. gasoline unl. 92 Jet/kero

Dec 13

2

0 -2

Cracking spread, US$/bbl

0

-10 -20

Nov 13

4

10

Oct 13

Dubai Urals

20

Sep 13

6

Cracking spread, US$/bbl

Light sweet/medium sour crude spread, US$/bbl

8

Singapore cracking spread vs. Brent, 2013–2014* 30

Mar 13

Brent dated vs. sour crudes (Urals and Dubai) spread, 2013–2014*

Aug 13

2015-Q1

Gasoil, 10 ppm S Fuel oil, 1% S

Aug 13

2014-Q1

Jul 13

2013-Q1

Source: EIA Short-Term Energy Outlook, April 2014.

Jul 13

2012-Q1

Prem. gasoline unl., 50 ppm S Jet/kero

Jun 13

2011-Q1

30 20 10 0 -10 -20 -30

Jun 13

2010-Q1

Rotterdam cracking spread vs. Dubai, 2013–2014*

Mar 13

Forecast

Stock change and balance World consumption World production

2.5 2.0 1.5 1.0 0.5 0.0 -0.5 -1.0 -1.5

Stock change and balance, MMbpd

Supply and demand, MMbpd

96 94 92 90 88 86 84 82 80 78 2009-Q1

May 13

A S O N D J F 2014

May 13

F M A M J J A S O N D J F M A M J J 2012 2013

May 13

Source: DOE

Apr 13

45

Apr 13

W. Texas Inter. Brent Blend Dubai Fateh

Apr 13

90 60

Prem. gasoline unl. 93 Jet/kero Gasoil/diesel, 0.05% S Fuel oil, 1% S

Mar 13

Oil prices, $/bbl

105 75

60 50 40 30 20 10 0 -10

Cracking spread, US$/bbl

120

* Material published permission of the OPEC Secretariat; copyright 2014; all rights reserved; OPEC Monthly Oil Market Report, April 2014. Hydrocarbon Processing | MAY 201423

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Reliability

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

Make equipment decisions with up-to-date technical information Answering lube practice-related questions is important. These questions provide insight on the status of education and technology, along with trends in understanding equipment reliability, safety and more. Hopefully, these trends are moving forward; however, they sometimes stagnate or even regress. Several professionals dealing with machinery in petrochemical plants and oil refineries have mentioned that their meantime-between-failures (MTBF) on process pumps are no longer as favorable as they were two decades ago. Interestingly, such negative trends can be attributed to “tightening” specifications without reviewing the end effects.

some ambient air space are located between the pumpage and the bearings, as illustrated in FIG. 3. Therefore, most of the heat is radiated to the surrounding air. Also, barrier seals often assist in further heat removal. Differences in heat removal. There is obviously a signifi-

cant heat loss along the shaft between the pumpage in the pump casing and the lightly loaded and thinly oil-coated radial bearing in the bearing housings of API process pumps. Additional heat will be lost while moving from the radial bearing to the more highly loaded thrust bearing set. Long-term bearing housing temperatures on liquid oil-lubricated pump bearings have

Oil-mist and high-pumping temperatures. Recently, the man-

ager from a prominent oil-mist-system supplier made this point: “I have had numerous questions lately about hot services and how we (the company) size oil-mist nozzles (or reclassifiers, as shown in FIG. 1) for temperatures of the pumpage. We never really considered temperature before, and the limits imposed seem to be getting lower. Two refineries, among the world’s six largest, set specifications limiting oil-mist temperatures to 450°F. At present, I even have one specification that indicates a 300°F limit. Many specifications call for “heavy-service-factor reclassifiers” on pumps in hot service. But what is the basis for such restrictions? Was the pumping temperature ever a concern with the highly successful oil-mist systems at your best-of-class (BOC) employer 20 or 30 years ago?” Answer. The answers can be found in many texts; they are not secrets. Since the 1960s and on numerous occasions, pure oil mist has been applied with great success to all types of API pumps, as shown in FIG. 2. These applications include dozens of pipe-stillbottoms pumps with fluid temperatures of 740°F (393°C) in some of the world’s largest oil refineries. As in a number of other services, oil-mist lubrication has been outstandingly successful, and BOC oil refineries are pleased with pure oil mist. Regrettably, below-average performers seem to be held back by personnel with little ability to analyze why they have problems and their competitors do not. For example, they have no knowledge of optimum reclassifier location, effects of inadvertently bypassing the oil mist around certain bearings, lubricant type best suited for critically important hot-service pumps, etc. Some would rather voice opinions than search for facts. To assist people with older (outdated) information on pumps and lubrication systems, a field trip to review later-model API610 style pumps is a viable solution. They could visit the pumps either in the field or on one of the numerous pump manufacturers’ websites. With a first-hand view, the person with the question may realize that a high-temperature mechanical seal and

FIG. 1. Cut-away of an oil-mist reclassifier. Oil mist enters from the left; as the bore diameter becomes smaller, its velocity increases. The small oil-mist globules combine into heavier globules, which then coat the bearing’s rolling elements.

FIG. 2. Oil-mist lubrication applied to a pump bearing housing in accordance with API-610, 12th Ed. Note: Dual mist-injection points and use of face-type bearing protector seals prevent the mist from escaping to the atmosphere.2 Hydrocarbon Processing | MAY 201425

Reliability never exceeded 240°F (116°C) in pumps at major oil refineries. Operation at these temperatures would require installing a

FIG. 3. API-style pump with Flush Plan 53C—pressurized and cooled barrier fluid circulation in the outboard seal of a dual-seal configuration. A tapered pumping ring maintains circulation while running. The pressure is maintained and fluctuations are compensated in the seal circuit by a piston-type accumulator, upper right. Note the distance from pumpage to bearing housing and the advanced-style bearing housing protector seal. Source: AESSEAL Inc., Rotherham, UK, and Rockford, Tennessee.

personnel protection shield on bearing housings. In the 1970s, ISO VG100 mineral oil-based lubricants were used in many of the open-oil-mist systems. Pure oil-mist-lubricated pumps use neither oil rings (slinger rings) nor constant level lubricators. Today, one either uses a specially formulated, moderately priced mineral oil/synthetic oil mixture or a more expensive, pure synthetic ISO VG68 in pure oil-mist systems. These serve pumps with fluid temperatures from 600°F to 740°F. With ISO VG 68 diester-based synthetic lubes, bearing housing temperatures have yet to exceed 190°F (88°C), and, with pure oil-mist bearing, cooling is no longer needed.1, 2 For the past 40 years, the reclassifier selection has never been influenced by pumping temperatures in API-style pumps. This temperature rating does not enter the picture, especially when applying oil mist per modern API-610 standards. The oil mist must flow from the space nearest the bearing housing protector seal to the center of the bearing housing, as shown in FIG. 2. Through-flow mode, incidentally, was routinely done at BOC plants after 1977. As an aside, if occasional risk takers were to use a closecoupled non-API pump for a 740°F hydrocarbon service, they would be making a totally unacceptable choice. In that instance, changing the system would become a priority task. Consider changing the system. It has been said that one cannot change the safety and reliability culture without first changing the system. Of course, the system is the organization.

alves Best V 67 8 since 1

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Reliability If we allow specifications to be written or amended by people who are not informed on new developments and standards, then the company or employer will soon lag behind others. Without detailed lubrication knowledge, an employer will lose more ground to the competition. Of course, a specification update will sometimes make sense and provide benefits for safety and reliability. Yet, when an unduly tight specification is issued, then the exact opposite may result. Vision. When working or purchasing rotating equipment, consider the whole picture and always make informed choices. Not allowing oil mist to be applied in pumping services over 300°F raises the question: What lube application method will these user-specifiers choose for the 600°F and 740°F pumps? Other than well-proven oil mist, only liquid oil sprayed directly into a rolling element bearing’s cages is a suitable option for the reliability-focused engineer. Returning to wet sumps with tricky oil rings and constant-level lubricators is very maintenance-intensive. An even worse choice is reverting to grease-filled singlepoint automatic lubricators for motors.1 Premium-grade motor greases separate into soap and oil when pressurized. Lesserquality greases, while not separating as readily under pressure, will not provide superior protection. Only plantwide oil mist answers all of these concerns. As of 2013, well over 130,000 process pumps are successfully lubricated by plantwide oil-mist systems. Also, 26,000 electric motors use oil mist on their bearings, and some of these have been using oil mist for 35 years without ever replacing or changing a bearing. Based on decades of successful installations, applying pure oil-mist systems on electric motor drivers makes sense and can yield rapid payback. Nudging some user-specifiers to reliability-focused choices should be a priority. Perhaps some could be persuaded to attend a simple vendor-arranged update on plantwide oil-mist systems. Oil mist is highly successful for lubricating electric motors in the 15 hp–500 hp range. Of course, there is no diplomatic way to remind an indifferent purchaser that making informed choices is better than selecting equipment based on old anecdotes. By not including electric motor lubrication and standby/ storage protection in cost-justification studies, the uninformed have locked entire plants into a cycle of avoidable expenditures. Their BOC competitors have captured the lead by making wise choices decades ago. LITERATURE CITED Bloch, H. P. and A. R. Budris, Pump User’s Handbook: Life Extension, 4th Ed., 2013, The Fairmont Press, Inc., Lilburn, Georgia, p. 296. 2 Bloch, H. P., Pump Wisdom: Problem Solving for Operators and Specialists, John Wiley & Sons, Hoboken, New Jersey. 1

HEINZ P. BLOCH resides in Westminster, Colorado. His professional career commenced in 1962 and included long-term assignments as Exxon Chemical’s regional machinery specialist for the US. He has authored over 580 publications, among them 18 comprehensive books on practical machinery management, failure analysis, failure avoidance, compressors, steam turbines, pumps, oil-mist lubrication and practical lubrication for industry. Mr. Bloch holds BS and MS degrees in mechanical engineering. He is an ASME Life Fellow and maintains registration as a Professional Engineer in New Jersey and Texas.

28

Select 158 at www.HydrocarbonProcessing.com/RS

Automation Strategies

DICK HILL Vice President, ARC Advisory Group

The automation challenge requires new approaches It might be human nature to feel that the professional challenges that we face every day are unique. However, while business and production objectives may vary greatly from company to company and from industrial sector to industrial sector, nearly everyone needs to move projects from plans to startup as quickly as possible. The task must be completed using as few resources, especially as little capital, as possible. This task must be accomplished without missteps that require rework or cause delays. All industrial companies must manage their production assets and associated automation assets effectively over the entire asset lifecycle. One session at the 2014 ARC Advisory Group Industry Forum focused on the automation side of this equation. Senior automation specialists from the oil and gas (O&G) and other industries shared their challenges, along with some recommended solutions for automation suppliers and users, with the session participants. While the production processes were very different, the automation-related challenges were amazingly similar. New approaches needed. Automation technology suppli-

ers have come a long way over the last several decades. But technology alone is not sufficient to address the multiple challenges that today’s industrial organizations face. These challenges span both the project design/construction/commissioning phase for a new industrial facility, and the much longer operations and maintenance phase, in which ongoing improvements over the lifecycle of the facilities can play such a critical part in the business’ success. In many industrial facilities, this lifecycle can span decades. While it may just represent a small fraction of the total project cost, automation plays a key role in operations and maintenance. During the capital project phase, the challenge for the automation team is often simply to keep their needs off the critical path, without compromising the end results at startup and commissioning. During the much longer operations and maintenance phase of the industrial asset’s lifecycle (which could be up to 20 years or more), the automation team must be able to modify, update and improve the automation assets on almost a continuous basis, and, do so at minimum cost, with minimum production interruptions, often with shrinking internal resources. This requires technology users and suppliers alike to apply whole new approaches. ‘It (automation) just happens.’ In his Forum presentation,

Sandy Vassar, facilities I&E manager for ExxonMobil Development Co., used the phrase “it just happens” to indicate his team’s goal for the automation portion in each of the more

than 100 O&G projects now in various stages of planning and execution at the company. This is meant to convey the fact that it is too costly and difficult to manage complex automation projects using the same approaches as in the past. Mr. Vasser called upon both his own resources and those of his technology suppliers to “step way back and look at whole new ways of doing things.” According to Mr. Vasser, “By default, projects are sequential in nature … and things are never ready at factory acceptance testing.” He believes the industry needs “lean project execution” that separates the physical system from the software. Toward this end, the technology suppliers have to think differently and deliver technology in a way that allows the team to eliminate, simplify and/or automate steps in the overall execution of automation. Mr. Vasser listed several challenges, with the top four being: 1. Eliminate, simplify and/or automate steps in the total execution of automation 2. Minimize customer engineering and reduce the total amount of engineering 3. Shift the custom engineering to the software and rely on standard hardware components; progress hardware fabrication independent of software and design 4. Virtualize the hardware and prove the software design against the virtualized system. As an example, Mr. Vasser highlighted how thinking about I/O differently led to smart configurable I/O. This new technology allows the project team to continue the design and engineering well past the traditional point where decisions get cast in concrete. He also discussed using virtualization to reduce dependence on design and remove functional design deficiencies. “By virtualizing hardware, we’re also less susceptible to technology churn.” The challenge. Mr. Vasser threw out a challenge to the tech-

nology suppliers in the audience to partner with technology users to come up with new and innovative solutions to the technology challenge. At the end of the presentation, he stated, “We want our (automation) guys to become the unknown engineers, because … it just happens.” DICK HILL is vice president of ARC Advisory Group in Dedham, Massachusetts, and is responsible for developing the strategic direction for ARC products, services and geographical expansion. He is responsible for covering advanced software business worldwide. Mr. Hill has over 30 years of experience in manufacturing and automation. He has broad international experience with The Foxboro Co. Mr. Hill previously worked as a senior process control engineer with BP Oil and as the US general manager of Walsh Automation. He is a graduate of Lowell Technological Institute, with a BS degree in chemical engineering. Hydrocarbon Processing | MAY 201429

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Project Management

JOSÉ CORRALES-PÉREZ Project Director, Tecnicas Reunidas, Madrid, Spain

Better strategies avoid project delays—Part 2 How can project managers avoid project schedule overruns? Part 1 discussed how to analyze the root causes for project delays. In Part 2, strategies to overcome project delays will be explored. Critical information management method. It is a methodology to overcome the fundamental causes for delays. It can reduce the project duration and avoid unexpected overruns. Critical information management (CIM) stresses the importance of information flow, concentrating on the most critical items. Since advice is quickly forgotten, this method focuses on changing work procedures, because they have a long-term effect. Redesigning the project scheduling process. To achieve drastic improvements in project planning, it is necessary to involve the project manager in the preparation of the initial schedule. The scheduling specialist’s knowledge should not be ignored; however, combining this expertise with the experience and creativity of the project manager and other key project members with the scheduling specialist may yield a more robust project plan. To engage project managers in the process, reengineering of the scheduling process is needed because the present PERT network preparation can be intimidating. A simple and user-friendly scheduling environment is necessary. It must enable overloaded managers to easily understand the project activity network and to effortlessly reflect on using their ideas and experience. The first step is a lower-level breakdown to reduce the PERT size to 100–200 activities, but more action is needed, as the charts produced by PERT software tools are not sufficiently user friendly for this purpose. To develop a user-friendly planning environment, discipline maps must be developed. As shown in FIG. 1, a discipline map is a graphical network illustrating the main activities for each discipline and the precedence relations connecting them. The maps must be readable, including those who are not familiar with PERT and easy to understand while facilitating changes and improvements. As shown in FIG. 2, the complete procedure is: • The scheduling specialist prepares a map for each of the discipline or departments (construction, mechanical, civil, piping, etc.) • Each discipline map is thoroughly analyzed with the disciple involved and key project members. The objective is to visualize the potential problems and to propose practical and creative solutions. • After analyzing the individual discipline maps, it is necessary to concentrate on precedence relations linking activities from different disciplines. For instance, bypass sizes cannot be shown on PIDs (a process or piping discipline) if the control valves (an instrument discipline) have not been sized. These relations need special attention from project

management, because their impact is not often sufficiently understood by involved disciplines. • Once the map analysis is complete, the scheduling specialist can use the maps to produce the PERT schedule, with whatever level of breakdown is necessary. Construction-driven plans. If you ask any project manager if

the initial plan is construction driven, the answer will be “yes,” but only because the project managers are skilled in politically correct replies. To be construction driven, the plan has to contemplate the dates on which construction will need drawings, equipment and materials. These dates cannot be established without a reliable construction schedule. Therefore, experienced construction staff must be involved in the preparation of the construction map. Additionally, the construction strategy admits numerous alternative solutions (one or several subcontractors, prefabrication vs. site construction, modular vs. stack construction, etc.) and provides many opportunities for time and cost savings. Consequently, the construction map deserves more attention. Project success begins with construction-driven planning of engineering and procurement activities. Many construction failures are due to late arrivals of drawings and materials, especially piping materials. List of Single line and consumers load balance 2m 2m Equipment list Power distribution dwgs 4m

Plot plan

MV and MCC design and requ. 2m

Short circuit 2w

Transformer requisition Prelim. cable list and sizing 2m

Tray layout 1.5 m

Tray levels 1.5 m

Trench layout 3m

Soil resistivity Soil report H. area classification

Cable requisition 1.5 m

Grounding and lightning 2m

Key m = months w = weeks

FIG. 1. Fragments of an electrical discipline map.

Best practice discipline maps

Review maps with each discipline

Review maps with project management

Review interdiscipline precedence relations with project management

Prepare PERT network

FIG. 2. Procedure for initial project schedule. Hydrocarbon Processing | MAY 201431

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Project Management Activity duration and safety buffers. Eliyahu Goldratt’s theory of constraints, published in his best seller The Goal: A Process of Ongoing Improvement, has helped hundreds of factories around the world to achieve dramatic improvements in delivery times. In his second book, Critical Chain, he extended the same theory to project planning and developed a new method, which many believe to be the main contribution to project management since the introduction of PERT. Goldratt’s method predicts total project duration better than PERT when resources are limited. The critical chain method arises from the fabrication environment. The main application has been in projects closely related to fabrication. Process plant projects are different, and thus this method needs some tuning. Goldratt says that planned durations are extremely conservative, but they will not be met due to the combined effect of the student syndrome and Parkinson’s law, as mentioned in Part 1. He recommends to reduce all activity durations by 50% and to introduce, later in the schedule, a safety time buffer. In the case of process plant projects, a 50% reduction is too much, at least for the first project. However, a 25% reduction is possible for most engineering and procurement activities. Construction activities should also be compressed, but only by 10%. Duration of equipment and material deliveries is usually estimated from previous projects; it should not be shortened because it is controlled by other factors. Piping deliveries deserve special attention. Generally, they are part of the critical path and

have a very high impact on construction. The duration should not be decided without a detailed analysis of recent projects and present market conditions. Part of the time gained by these cuts must be accumulated into one or several safety-buffer activities. In the case of construction activities, the full-time cut must go directly into the safety buffer. The simplest solution for safety buffers is to have only one, located at the end of the project. But, in practice, the location of buffer activities needs careful consideration, including contractual liabilities. For instance, if piping delivery to the prefabrication yard is scheduled without any safety buffer, it may later cause substantial prefabricator claims in case of delays. Safety buffers are the only sensible way to cope with unexpected problems such as extreme weather, accidents or human errors. During project development, the duration of buffer activities may be reduced to absorb delays in the critical path. The remaining buffer durations must be carefully watched, because they are an indication of the schedule’s health. Management of critical vendor information. Several years

ago, everyone hoped that 3D CAD systems would reduce piping design and, therefore, total project duration. Many still wonder why it did not happen. The main reason is that piping design and vendor information are so intermingled, that cutting only one of them is not enough. Without vendor information, piping design cannot be completed, and isometrics cannot be issued for fabrication.

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Hydrocarbon Processing | MAY 201433

Project Management Vendor information is an input for civil design and piping design, sometimes for the procurement of other downstream equipment. Therefore, it is crucial for both project duration and design efficiency. The time required to obtain vendor information may be broken into two periods: placing the purchase order (PO) and waiting for the vendor to prepare the information. Every project manager knows that early procurement is necessary for timely projects; it guarantees early arrival of vendor information and timely delivery of long-lead equipment. A recurring problem that delays POs is the time taken to negotiate price and delivery conditions with vendors. Too frequently, award decisions are deferred waiting for small discounts; meanwhile, this delays the arrival of much needed information. After the PO, the time required by the vendor to send approved drawings may take from one to five months for each piece of equipment, and more for the total project. However, this period can be reduced if the request is redefined. Example: Ordering an overhung centrifugal pump. The perfectionist will request a “complete set of certified vendor drawings.” This step can easily require three months because the fabricator may have to wait for the details of a junction box supplied by another vendor. A complete set of drawings is not required. The only details needed to proceed with the design are: • Civil design requires the footprint with dimensions. • Piping design needs the exact location of inlet and outlet flanges.

The perfectionist will say, “Not enough. The civil designer needs pump weight, the stress analyst needs allowable piping loads on flanges, and the electrical engineer needs the exact cable gland location.” But this is just typical procrastination. The weight is meaningless; API 610 specifies flange allowable loads, and the electrical engineer can wait. Instead of a “complete set of certified vendor drawings,” we can ask the vendor to make first information delivery with exactly the minimum data needed, and to share the purpose and criticality of the data. Result: The waiting times will be dramatically reduced. It is also necessary to consider the criticality of vendor information when preparing the requisition for inquiry. For instance, specifying unusual base plates or uncommon motor brands can increase the time in receiving vendor information. Next month—Part 3. The author lists the key ways to improve

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JOSÉ CORRALES-PÉREZ has over 30 years of experience as a project manager in the oil and gas and chemical industries. He has worked for Brown & Root, Foster Wheeler, Initec and other international EPC contractors. At present, he is the project director with Tecnicas Reunidas for a $3.5 billion refinery project in Talara, Peru. Mr. Pérez has authored over 20 technical papers and two management books. He holds BS and MS degrees in mechanical engineering, a BA degree in economics, and an MBA degree.

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AVEVA’s Integrated Engineering & Design solution supports the Engineering & Design for Lean Construction vision. AVEVA’s Integrated Engineering & Design solution improves project efficiency and reduces engineering and design costs by offering complementary products that draw on common processes, disciplines and deliverables. AVEVA’s Integrated Engineering & Design solution shares critical information efficiently between disciplines and across teams, simplifying the process and improving project scheduling and quality.

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Global

HAL FOSTER Guest Columnist

Russian executives to build country’s first waste oil refinery Andrei Yermolaev, founding partner and general director of the Kirishi-2 oil refinery in Russia, remembers watching a refinery rise 150 km southeast of St. Petersburg, Russia, when he was a boy in the 1960s. He did not just watch it, however; he experienced it, smelling the grime and dust on the clothes of his construction-worker mother and his truck-driver father as they helped build the Kirishi refinery. Fifty years later, life has come full circle for Mr. Yermolaev, a career oil man and former deputy of the Leningrad Regional Assembly. He and Giorgi Ramzaitsev (FIG. 1), owner of CHEKSU.VK, Russia’s largest felloalloy and manganese ore processing company, are spearheading an effort to build a second refinery in Kirishi. It will be more ecologically efficient than the original plant, and it will refine waste oil, along with crude oil. The immediate task for the project is finding investors. The 4-million-tons-per-year (MMtpy) Kirishi-2 refinery is anticipated to cost $3.14 billion (B) to construct. Plans call for the refinery to be expanded to a capacity of 12 MMtpy at a later date, at an additional cost of $5 B–$7 B. The owners are seeking partners in both Russia and abroad. The Kirishi-2 refinery is expected to increase the area’s economic base and create 1,000 jobs. Mr. Yermolaev’s involvement in the Kirishi refinery project, and more generally the Russian oil business, grew out of a series of lucky breaks rooted in his practice of martial arts. While pursuing a law degree at St. Petersburg State University, he served as a combat instructor for the police and the military. The center where Mr. Yermolaev instructed military recruits was lacking in government funding, so he asked Kirishi’s state-owned oil refinery for help. Adolf Smirnov, general director of the refinery’s distribution

arm, Kirishineftehimexport, was impressed with Mr. Yermolaev’s determination and resourcefulness. Three years later, Mr. Smirnov asked Mr. Yermolaev to join the Kirishi refinery business as assistant to the general director. In his new job, Mr. Yermolaev also met Mr. Ramzaitsev, who would become his business partner. At the time, Mr. Ramzaitsev was running the oil company Urals Moscow, which had a close relationship with the Kirishi refinery. Upon Mr. Smirnov’s recommendation, Mr. Yermolaev became the head of Urals Moscow’s new representative office in Kirishi in 1993. The early 1990s were a chaotic time in Russia as a market economy took shape. Former state-owned corporations were split into pieces, consolidated or bankrupted at a rapid pace. New

FIG. 1. Andrei Yermolaev (left) and Giorgi Ramzaitsev (right) have formed a partnership to build the Kirishi-2 refinery, which will be the only refinery in Russia to process waste oil into high-quality refined products.

Kirishi-2 refinery primary ecological advantages: • A dramatic reduction in emissions will result from the combustion of petroleum products by the end user. The refinery complex will showcase new, ecologically efficient technologies and accrue greater attention for the environment among oil production companies. • NOx emissions will largely decrease as a result of the denitrification and decomposition of the raw ammonia to obtain a final product with a low N2 content. • The reduction of NOx emissions at the refinery through the use of clean fuels in furnaces with direct heating, and burners with a reduced NOx level in all furnaces, will contribute to significantly reducing emissions.

• All refinery wastewater will be collected and cleaned onsite. • Oily water will be gathered and sent to a pool corresponding with American Petroleum Institute standards to extract hydrocarbons. The hydrocarbons obtained in this process will be returned and mixed with crude oil. De-oiled wastewater will be sent for biological treatment. • The primary source of solid waste is the spent catalyst, which is exchangeable at the end of its lifecycle. Many catalysts can be returned to the manufacturer for regeneration or sent for metals extraction. Hydrocarbon Processing | MAY 201437

Global businesses were formed. Many of those went bankrupt as well. As was the pattern elsewhere in the regions, a handful of companies came to dominate the business world in the Kirishi area. They included Urals Moscow; Kirishinefteorgsintez, the company that ran the refinery; Kirishineftehimexport; and Help-Moscow, a distribution firm. Surgutneftegas later bought the Kirishi refinery. However, even dominant companies ran into problems. Urals Moscow began slipping in the late 1990s, and eventually was dissolved. Mr. Ramzaitsev formed Urals Energy Public Co. Ltd. in the early 2000s to capitalize on some of Urals Moscow’s former business, and Mr. Yermolaev quickly joined him. The catalyst for the Kirishi-2 refinery was the Russian government’s decree in the early 2000s that all oil companies, including Urals Energy Public, needed their own refineries. The order was aimed at resolving a refinery shortage in the country. Urals Energy Public began working on the refinery in 2006. During the global economic downturn of 2008–2010, Mr. Ramzaitsev was forced to sell Urals Energy Public. However, he and Mr. Yermolaev remained committed to Kirishi-2, forming a partnership to make it become a reality. The partnership has acquired most of the land that will be needed, along with a 13-km rail spur from the refinery to a main rail line. The rail link, an expensive but strategic purchase, will allow the refinery to transport its refined products to St. Petersburg for shipment overseas. The refinery will also help satisfy domestic supply, which is presently lacking in northern Russia. The Northwestern Federal

District is forced to import a substantial volume of crude oil and oil products from other geographic areas of the country, due to a lack of production in the region (TABLE 1). The permitting process can take time in Russia, so it was not until 2013 that the partnership obtained a green light from the government for the refinery. The partnership is now ramping up its effort to turn a dream into a reality, starting with financing. It has signed an agreement with the Ufa Design Institute to design the refinery, and it has received positive feedback from top oil executives on the viability of the project. One reason the project has already attracted investor interest is that it will be breaking new ground in Russia. Kirishi-2 will be the only complex to convert heavy heating oil and slag oil into gasoline and other refined products. The industry considers heavy heating oil and slag oil, which are byproducts of refining, to be waste. However, the refinery’s ability to convert them into high-end refined products means that other refiners will be able to dispose of their unwanted byproducts for refining at Kirishi-2. Mr. Yermolaev touts the Kirishi-2 project as a model for new refinery projects in Russia. It will also help his hometown of Kirishi, where he watched his parents pour their hearts into creating opportunity for their fellow citizens more than 50 years ago. TABLE 1. Oil product supply and demand balance in the Northwestern Federal District, 2010 Gasoline, thousand tons per year (Mtpy)

Diesel, Mtpy

Residual oil, Mtpy

432.3

1,064.2

1,162.6

Kirishinefteorgsintez

2,387.8

5,129.2

7,159.4

Total

2,820.1

6,193.4

8,322

187

457

1,185

252.7

242.8

1.4

Production by company Lukoil Ukhtaneftepererabotka

Demand by region Arkhangelsk Vologda Kaliningrad

175.5

231.6

122.2

Leningrad

1,900.9

1,841.3

2,089.5

Murmansk

151.9

234.8

1,268.5

Novgorod

117.2

152

11.3

170

246.8

15

106.4

119.4

256.8

Pskov Republic of Karelia Komi Republic

152.2

586

183

Total

3,213.8

4,111.7

5,132.7

Discrepancy between production and consumption volumes

–393.7

2,081.7

3,189.3

Source: InfoTEK, 2011

HAL FOSTER is a journalist and journalism professor. He was a writer, editor and manager at San Francisco Chronicle, Los Angeles Times, Omaha World-Herald, Portland Oregonian and Seattle Post-Intelligencer. He was also a journalist in Japan for nine years. After obtaining a PhD in journalism and mass communication at the University of North Carolina in 1988, Dr. Foster taught at Sam Houston State University in Texas; Auburn University in Alabama; the University of Alaska; and the Kazakhstan Institute of Management, Economics and Strategic Research. He was a Fulbright professor of journalism in Odessa and Lviv, Ukraine. Additionally, Dr. Foster has taught seminars in media management, business journalism and other topics in Ukraine and Kazakhstan, and he has done onsite consulting for independent newspapers in Ukraine, Bosnia and Poland.

38

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Petrochemicals

TISON KEEL JR. Director, Ethylene Oxide and Derivatives, IHS Chemical

Ammonia production booms on cheap natural gas Thanks to the availability of a steady supply of affordable natural gas as a feedstock, the ammonia and fertilizer industries in North America are experiencing a renaissance that has not been witnessed in decades. During the past five years, demand for ammonia grew at an annual average rate of almost 2.5% from 153 million metric tons (MMt) in 2009 to more than 170 MMt in 2013. Demand surges. This is welcome news for both the petro-

chemical and agricultural industries, since more than 80% of ammonia is used in fertilizer and agricultural products essential to expanding food crop production. According to a new report, the IHS Chemical Ammonia Value Chain Special Study, growing incomes and improving diets in developing countries such as Brazil, India and China, combined with significant biofuels production in the US and Brazil, are driving global demand growth for ammonia. The abundant supply of low-cost natural gas feedstocks has revitalized the US ammonia and nitrogen fertilizer industry. Plant operating rates have risen, idle capacity has been restarted, and there is a long list of potential greenfield/brownfield projects being announced. IHS expects completed, large-scale capacity additions by 2018, totaling 5 MMt or more. The sharp rise in North American ammonia production will cause a sizable shift in global trade. At present, the US is the largest ammonia importing country by a wide margin. New, world-scale capacity projects, plus restarts and debottlenecks already underway, will sharply reduce US imports of ammonia and other derivatives. The trends are expected to help farmers reduce their costs for fertilizer. According to Stewart Ramsey, an agricultural economist with the IHS Agricultural Forecasting Service, new ammonia capacity additions should help lower per-bushel fertilizer costs by nearly 20% for wheat, and almost 30% for corn, by 2020. To produce the 2013 corn and wheat crops, Ramsey said, US farmers spent roughly $15 billion (B) and nearly $3 B, respectively, on fertilizer. Fertilizer costs should subside in the next several years. Supply shift. For ammonia, a shift is underway, and supply

considerations will dominate as new, low-cost capacity additions accelerate, outpacing demand growth and altering global trade patterns. Ammonia consumption will continue to grow at more than 2%/yr through the end of the decade, followed by a more modest growth as the high-growth markets reach maturity. Ammonia is a global concern. The ability to help chart the path of a product like ammonia is critical not only to major customers, but also to governments like China that must support

their growing economies and feed their expanding populations, often with less arable land available for food crop production. China is the world’s largest consumer and producer of ammonia, with 2013 production totaling an estimated 57 MMt. This nation produces slightly more than one-third of total global ammonia production. China is relatively poor in natural gas resources, but it possesses a very large fraction of the world’s known, recoverable coal reserves. China has embarked on a program to not only achieve selfsufficiency in fertilizer production and other key chemicals, but to also simultaneously monetize their resources and create an industrial base proximate to the coal mines. The present and future impacts of this effort will likely have huge implications for the entire global petrochemical value chain, and will be tracked carefully. TISON KEEL JR. is the director of ethylene oxide (EO) and derivatives market service for IHS Chemical, where he has worked for five years. He joined Chemical Market Associates, Inc. (now IHS) in 2008, bringing more than 30 years of in-depth industry experience within the EO and glycols product family. As lead of the IHS Chemical Global Ethylene Oxide & Glycol market service, he updates and publishes the IHS Chemical Ethylene Oxide & Glycols World Analysis. Starting in 1975, he began a distinguished career with Union Carbide Corp., then The Dow Chemical Co., following the merger of those two companies in 2001. His product background includes high-level functional experience in product management, sales, marketing, supply chain and customer service. Mr. Keel spent six years in Asia leading the formation and startup of two joint ventures: OPTIMAL Malaysia—an integrated olefins and EO derivatives producer, and Asian Acetyls VAM in Korea. He holds a BS degree in chemistry from Vanderbilt University and an MBA degree in finance/international business from the Stern Business School at New York University. Mr. Keel is lead author of the IHS Chemical Ammonia Value Chain Special Study.

China’s hydrocarbon shift to coal IHS has recently published analyses on China’s efforts to develop large-scale processes for the production of coal-to-olefins, coal-to-methanol, and most recently, coal-to-syngas. These efforts, once proven and able to better address China’s large-scale demand, will likely change the competitive landscape, once again, for many key chemicals and derivatives, and the various markets. Competition between gas-derived chemicals and coalderived chemicals extends far beyond cost and even energy and economic security. The implications will likely be debated for many years to come. Hydrocarbon Processing | MAY 201439

VERONA, ITALY | 24–26 JUNE 2014

Hydrocarbon Processing’s 5th Annual International Refining & Petrochemical Conference We invite you to discover the latest advancements and technology and operations in the refining and petrochemicals industries at Hydrocarbon Processing’s fifth annual International Refining and Petrochemical Conference (IRPC) to be held June 24 – 26 in Verona, Italy. IRPC is a leading-edge technical conference, providing an elite forum within which industry leaders can share knowledge and network. The conference provides both a local and global perspective and will feature more than 72 presentations, numerous networking opportunities and an esteemed group of speakers from 24 different countries and five continents. This year, IRPC will give special focus to the latest advances in biofuels and clean fuels and will feature a tour of Eni’s Venice biorefinery — the first refinery in the world to convert from a conventional plant into a biofuels production plant based on Eni’s patented Ecofining technology. We invite you to be a part of the discussion on the latest advancements in technology, on both a local and global level.

Register Early and Save 2014 Conference Fees

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IRPC 2014 Speakers Include: Biorefinery and simplex refinery: An innovative approach for the future of downstream

Reshaping of refining landscape in Europe

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CEO and President Kuwait Petroleum International

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Refining Track Sean Smyth, Global Licensing Director - Fuels, ExxonMobil Research and Engineering Company Dicho Stratiev, Chief Process Engineer, Lukoil Neftohim Burgas A.S. Sahney, Chief Technical Services Manager, Indian Oil Company Limited, Gujarat Refinery M.I. Levinbuk, Chief Researcher, Topchiev Institute of Petrochemical Synthesis, RAS Michael Silverman, Senior V.P. - Downstream technology & Chief Technology Officer, Ivanhoe Energy

Petrochemicals Track Vishwanth Dasari, Inspection Engineer and Bijay K. Muduli, Inspection Manager, Indian Oil Corporation Limited (IOCL) C.H. Rama Krushna Chary, Environment Engineer, Kuwait Oil Company Moumita Chakrabarti, Business Development Manager, BP Bruce R. Beadle, Engineering Specialist, Saudi Aramco Tuomas Ouni, Expert, Phenol and Hydrocarbon Technologies, Borealis Polymers Oy

Clean Fuels/Biofuels Track Jan Lambrichts, Senior Research Scientist, The Dow Chemical Chebre Meriam, Senior APC Engineer, Total Refining Chemicals Nadim Shakir, Senior Products Engineer, Qatar Petroleum Dr. A. Meenakshisundaram, Chennai Petroleum Corporation Ltd. Juan Manuel Anzaldo Trejo, Process Engineer, Instituto Mexicano del Petróleo

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Gas Processing

ADRIENNE BLUME, MANAGING EDITOR [email protected]

Asian gas market seeks lower pricing, infrastructure expansion: Part 1 The Gastech 2014 Conference and Exhibition, which was held in Seoul, South Korea, from March 24–27, brought together a number of panelists from the buyer and seller sides to share their recommendations for securing Asia’s gas demand. The first panel session of the conference, held on the morning of Monday, March 24, examined gas pricing, infrastructure requirements and market evolution, from a demand-side perspective. Moderated by Nick Milne, first vice president (VP) and LNG specialist at Bank of Tokyo-Mitsubishi UFJ, the panel emphasized the need to restructure LNG pricing mechanisms and enable destination flexibility for export contracts with Asian buyers. Mr. Milne then posed the question: “How do people position for growing gas demand from Asia?” The percentage of Asian national oil companies (NOCs) in global merger and acquisition (M&A) activity is growing and is presently pegged at approximately 20%. Three major themes with regard to meeting the growth in Asian demand, according to Mr. Milne and discussed by the panelists, are the push for restructured gas pricing, the competitiveness of gas versus other fuels (i.e., coal and nuclear power), and the roles of pipeline gas and LNG in longterm demand and pricing dynamics. Securing cheaper gas for Asia. Mr. Milne yielded the podium to Kwon Young-Sik, the executive VP and COO of KOGAS’ Resources Business Division (FIG. 1). Mr. Young-Sik spoke about Asian gas buyers’ strategies for securing cheaper gas. Nearly 70% of global LNG imports are delivered to South Korea, Japan, Taiwan and China; however, high prices make import of the fuel very costly for buyers. To secure cheaper LNG, Mr. Young-Sik said, comprehensive strategies must be built, including the establish-

ment of a gas “portfolio” approach, improving market efficiency and enhancing cooperation among buyers and sellers. A portfolio approach would require the diversification of price formulas and LNG sources, while market efficiency improvements could be secured through linkage to Henry Hub gas prices, increased buyer participation in global LNG project development, and the reduction of shipping costs through destination-free LNG and swap arrangements. The LNG market is systematically inefficient for Asian buyers due to oillinked formulas, which raises shipping costs, Mr. Young-Sik noted. The third strategy for securing cheaper gas is to boost cooperation among buyers through joint purchases to secure a competitive LNG price. To these ends, KOGAS is actively participating in global LNG projects, such as Shell Australia’s Prelude FLNG, the Mozambique Area 4 gas development and LNG Canada. KOGAS was also the first Korean company to secure gas exports from Cheniere Energy’s Sabine Pass project in the US. Diversification key to Asian expansion. The next panelist to speak was

Shigeru Muraki, executive VP and CEO of Tokyo Gas Co. Ltd.’s Energy Solution Division. Mr. Muraki provided the audience with commentary on the new dynamics of the Asian gas market. Diversification was the key word in Mr. Muraki’s speech. New supplies from the US, Canada, Mozambique and East Siberia could provide Asia with alternative import sources, while new pricing mechanisms such as oil-indexed gentle slope, Henry Hub, S-curve, short-term contracts and spot contracts could provide flexibility in terms of import costs. Pipeline connectivity and infrastructure development are other major con-

FIG. 1. KOGAS’ Kwon Young-Sik advocated improved market efficiency and enhanced cooperation to secure cheaper gas for Asia.

cerns for Asian gas buyers. Mr. Muraki cited the development of a north-to-east Asia pipeline, cross-border pipelines from Russia and Central Asia to China, a pipeline from Russia to Japan and South Korea, and interregional pipelines as critical options for the development of gas trade. Mr. Muraki also noted that the development of regional shale gas and methane hydrate reserves could spur increased interregional gas trade. In Japan, LNG has provided a steady source of gas in the wake of nuclear plant shutdowns since 2011. Nuclear plant restarts will cause the high volume of LNG imports to Japan to decrease to around 70 million tons (MMt) through 2020 from the recent high level of approximately 87.5 MMt. However, nuclear capacity will gradually decline again after 2020, leading Japan to import as much as 100 MMt of gas by 2030, Mr. Muraki said. Next month. Part 2 will share perspectives from corporate panelists in Japan and Taiwan, as well as a view from The International Group of LNG Importers. Hydrocarbon Processing | MAY 201443

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/LQGH3URFHVV3ODQWV,QF 6RXWK 1,000 hr) durations is so important to assess the relevance and seriousness of a creep curve. The Larson Miller curves enable gathering within a given range of temperatures the various stress/lifetime obtained by testing. A Larson Miller curve that is more like a line rather

FIG. 8. TEM and SEM observations of multiple shape carbides. A complex structure of Cr carbides growing on tantalum carbides can be observed in b). 1,350

TABLE 1. Possible ways to utilize the advanced 25-35 Nb Ma alloy in reformer furnaces

Maximum temperature, °C

1,300

25-35 Nb MA 1,250

Base case Same Decreased 25-35 Nb-MA dimensions OD

1,200 1,150 1,100 1,050

M23C6 in HP M23C6 in HP-Nb M23C6 in XM

MC in HP

MC in HP-Nb

MC in XM

FIG. 9. Maximum temperature of various carbides determined by thermodynamic calculations.

Increased ID

OD

144.6

144.6

142.2

144.6

ID

121

121

121

122.6

Thickness

11

11

9.8

10.2

Weight

606

606

547

573

Length

13,500

13,500

13,500

13,500

Catalyst volume

100

100

100

103%

Calculated life, hr

100,000

210,300

100,000

100,000

50

50

HP Micro minimum 25/35 Nb-Ma-R minimum HP mod minimum HK-40 minimum

870

890

910

930 950 970 Temperature, °C

990

1,010

1,030

Stress, MPa

Stress, MPa

HP Micro 25/35 Nb-Ma-R HP mod HK-40 HP-40

5 850

Advanced alloy of 25-35 Nb MA

1,050

FIG. 10. Average 100,000-hr creep strength of refractory alloys used for catalyst tubes, from HK40 to an advanced alloy of 25/35 Nb-MA.a

64MAY 2014 | HydrocarbonProcessing.com

5 850

870

890

910

930 950 970 Temperature, °C

990

1,010

1,030

1,050

FIG. 11. Minimum 100,000-hr creep strength of refractory alloys used for catalyst tubes, from HK40 to advanced alloy of 25/35 Nb-MA.a

Maintenance and Reliability than a curve and is “very straight” over a large temperature range is often an indication that this curve is probably vastly extrapolated. The Larson Miller parameter (LMP) creep curve for the advanced alloy of 25-35 Nb-Ma is based on internal creep data obtained from a random sampling of data sets and manufacturer data on different tube thicknesses and conducted by independent laboratories (TNO-NL) within two separate studies for durations from 200 hr to much more than 1,000 hr, as shown in FIG. 12. This curve is conservative and pessimistic on its right side (where collecting data is long and expensive) and shows a drop for high LMP values.

Consequences of improved creep strength. The con-

tinuous improvement of creep properties from HK40 to an advanced alloy of 25-35 Nb-Ma can be used in several ways to optimize furnace design, as summarized in TABLE 1. If the tube dimensions are unchanged, then the furnace lifetime will simply be extended by up to twice the original service life. The payback will be in several years. Furthermore, using extra service life is also a way for the tube to be more robust and able to sustain unpredicted overheating, thus increasing the reliability of the furnace during excursions from design operating conditions. The unexpected overheating does occur, and often. 50

in the high LMP range is limited and safety margins are continuously reduced due to cost optimization, a conservative approach is needed. No matter how detailed and severe the quality controls can be (e.g., eddy current, x-rays, mechanical testing, etc.), no NDT is perfect. In an industry where a clear trend to larger and more concentrated plants exists, a single failure can have severe consequences. Therefore, optimizing the equipment to the ultimate design by making first-hand savings may be a very short-sighted approach. It is actually safer to stick to actual and proven data and to avoid obvious extrapolations. Reliability of key components is necessary for long-term investments and should not be only driven by price.

Stress, MPa

Designing the equipment. As the number of data points

5

25/35 Nb-Ma-R minimum HP Micro average First independent tests, 4 heats Second independent tests, 1 heat, thick tube 31

32

33 34 35 36 LMP = T(K)ⴛ(22.96 + log(Tf)/1,000 with Tf in hours

37

38

FIG. 12. Comparison of independent creep tests with manufacturer’s creep curves for five different heats.

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Maintenance and Reliability Considering the very long run lengths for furnaces, the initial design conditions may be underestimated as compared to

Microalloys have become an industry standard in the supply of reformer tubes. The selection of those alloying elements is vital in mitigating creep resistance. New alloy materials for reformer tubes are gaining momentum. the yield and production rates needed after 5, 10 or 15 years after design. Result: Having a slight over-thickness at the beginning of the furnace service life may be a flexibility advantage over the long term. To take advantage of these improved creep properties, a smaller tube wall thickness can lower the initial equipment cost and/or increase the available catalyst volumes and thus raising plant yield. In addition, to these obvious economic advantages, reducing the tube thickness will significantly reduce the sensitivity to thermal shocks that may arise under abnormal operating conditions. A very detailed study demonstrated that the wall thickness reduction allowed by changing HK40 to 25-35 Nb-MA type led to thermal stress gradients (between

inner and outer diameters) reduced from more than 50 MPa to less than 10 MPa.8 Further improvement is provided by advanced new alloy of 25-35 Nb-MA, which adds reliability and robustness to the furnace. Continuously improving creep properties can offer several options to furnace designers and users, enabling a compromise between investment savings, and improving production and furnace robustness. Bi B C Ce Cr Hf Fe Pb Mn Ni

NOMENCLATURE Bismuth Nb Boron Si Carbon Ta Cerium Sn Chromium Ti Hafnium W Iron V Lead Y Manganese Zr Nickle

Niobium Silicon Tantalum Tin Titanium Tungsten Vanadium Yttrium Zirconium

ACKNOWLEDGMENTS The authors thank H. Van Wortel and H. Van de Veer from TNO for their fruitful discussions. NOTES 25/35 Nb-MA “R” (Manaurite XMR grade), specifically designed for its high creep resistance and therefore dedicated to steam-reformer applications by Manoir Industries. b Thermodynamic calculations were done using ThermoCalc software. c Manoir’s creep curves were done on five different heats. a

LITERATURE CITED Sourmail, T., “Precipitation in creep resistant austenitic steels,” Materials Science and Technology, No. 17, pp. 1–14, 2001. 2 Kaya, A. A., “Microstructure of HK40 alloy after high-temperature service in oxidizing/carburizing environment, II Carburization and carbides transformation,” Materials Characterization, No. 49 pp. 23–34, 2002. 3 Almeida, L. H., et al., “ Microstructural characterization of modified 25Cr-35Ni centrifugally cast steel furnace tubes,” Materials Characterization, No. 49, pp. 219–229, 2003. 4 Cueff, et al., “Influence of yttrium-alloying addition on the oxidation of alumina formers at 1173K,” Oxidation of Metals, pp. 439–455, 2002. 5 Shao, et al., “Effect of cerium addition on oxidation behaviour of 25Cr20Ni alloy under low oxygen partial pressure,” Journal of Rare Earths, no. 30, pp.164– 169, 2012. 6 Chen, et al., “Effect of rare earth element yttrium addition on microstructures and properties of 21Cr-11Ni austenitic stainless steel,” Materials and Design, no. 32, pp. 2206–2212, 2011. 7 Lifshitz, et al., “The kinetics of precipitation from supersaturated solid solutions,” Journal of Physics and Chemistry of Solids, No. 19, pp. 35–50, 1961. 8 Mohri, T., et al., “Application of advanced material for catalyst tubes for steam reformers,” AIChE Ammonia Symposium, October 1992. 1

ANTONIN STECKMEYER is a metallurgical engineer in the R&D department of Manoir Petrochemical and Nuclear division. He is in charge of the development of new alloys, both for enhanced creep and anticoking performances. Dr. Steckmeyer is also in charge of casting and solidification simulations. Before joining Manoir in 2012, he worked previously on nanostructured steels designed for nuclear reactors cladding, for which he obtained a PhD from Ecole des Mines Paris. HUGUES CHASSELIN is the vice president for technical sales and support for Manoir. He has been involved in high-temperature materials. Graduating from the French Foundry Engineering School, he joined Manoir Industries 23 years ago to run the US production at that time. Now back in France, he has spent the last 20 years in manufacturing, sales and technical interface with customers, visiting ethylene and reforming furnaces around the world. As VP for technical support and services, he works with customers to understand their needs and market Manoir’s latest products, technologies and manufacturing plants. He also oversees a team of project managers.

66

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VERONA, ITALY | 24–26 JUNE 2014

Hydrocarbon Processing’s 5th Annual International Refining & Petrochemical Conference As major restructure forces are reshaping the hydrocarbon processing industry (HPI), managers and engineers are actively seeking information and solutions to make their companies more efficient and profitable. Hydrocarbon Processing’s International Refining and Petrochemical Conference provides a one-of-a-kind forum for HPI innovators and practitioners to share knowledge and network. We invite you to take part in the discussion and explore how technological and operating advances can benefit your organization and assets. IRPC emphasizes the industry’s latest technologies and best practices from both local and global perspectives and is attended by senior executives and engineers from leading operators, refineries, petrochemical plants and gas processing plants from around the world.

Register to attend today at HPIRPC.com This year, IRPC will give special focus to the latest advances in clean fuels and biofuels and will feature a tour of Eni’s Venice biorefinery – the first refinery in the world to convert from a conventional plant into a biofuels production plant based on Eni’s patented Ecofining technology.

Hear from Keynote Speakers: Biorefinery and simplex refinery: An innovative approach for the future of downstream

Reshaping of refining landscape in Europe

GIACAMO RISPOLI

CEO and President Kuwait Petroleum International

BAKHEET AL-RASHIDI

Executive Vice President, Research and Development and Projects eni S.p.A

IRPC 2014 SPONSORS:

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AGENDA DAY 1: Tuesday, 24 June 2014 8 a.m.–4 p.m. 5:30–7 p.m.

REFINERY TOUR EARLY REGISTRATION

AGENDA DAY 2: Wednesday, 25 June 2014 8:30–9:15 a.m.

CONTINENTAL BREAKFAST

9:15–9:30 a.m.

OPENING REMARKS: John Royall, President and CEO, Gulf Publishing Company

9:30–10:15 a.m.

KEYNOTE ADDRESS: Biorefinery and simplex refinery: An innovative approach for the future of downstream - Giacamo Rispoli, Executive Vice President, Research and Development and Projects, eni S.p.A

10:15–10:45 a.m.

COFFEE BREAK TRACK 1: REFINING

TRACK 3: CLEAN FUELS/BIOFUELS

Session 2: Process Technology/ Process Optimization Session Chair: Giacomo Fossataro*, General Manager, Walter Tosto S.p.a

Session 3: Biofuels Session Chair: Ajit Sapre*, Group President, Research and Technology, Reliance Technology Group

Revamping FCC units to maximize LCO production and quality - Gautham Krishnaiah, Director- FCC Technology, KBR Technology

BP’s ethanol to ethylene technology provides a high performance alternative pathway to conventional plastics - Moumita Chakrabarti, Business Development Manager, BP

Hydrogen sulphide recovery at ENI Porto Marghera green refinery using UCARSOL™ acid gas enrichment technology Jan Lambrichts, Senior Research Scientist, The Dow Chemical Company

Case study: multi-faceted SRU upgrade - Scott Kafesjian, Director, Sulphur Technologies, Foster Wheeler USA Corporation

Haldor Topsøe exchange reformer offers an efficient reforming process for new plants and for revamp of existing plants - Kristian Lindell, Proposal Manager – HYCO Technology, Haldor Topsøe A/S

Hydroconversion of renewable lipids into biojet and biodiesel - Stephane Fedou, Technology Group Manager Olefins/Alternative Fuels, Axens

11:25–11:45 a.m.

Increasing throughput in existing separators: new high efficiency separator internals can provide higher ROI for refinery facility upgrades - Ankur Jariwala, Sr. Product Manager, Cameron Process Systems, Houston

Optical technologies for industrial gas analysis in the HPI review and trends - Dr. Fabiano de Melas, Global Product Manager – CGA, ABB

Bio-isobutanol: cost effective and robust - Richard Kolodziej, Process Technology Manager, Wood Group Mustang

11:45 a.m.– 12:05 p.m.

Application of MIDWTM technology to enable premium distillate production - Sean Smyth, Global Licensing Director- Fuels, ExxonMobil Research and Engineering Company

Rethinking aromatics recovery through toluene methylation - Charlie Chou, Licensing Manager, GTC Technology US, LLC

Biorefineries: and the winner is? - Jelle Ernst Oude Lenferink, Process Engineering Manager, Fluor

Hydrocracker light naphtha recycle operation Suliman Albassam, Process Engineer, Saudi Aramco

Cognitive automation and advanced analytics for downstream operations - Eric Jan Kwekkeboom, Business Development Manager, Yokogawa Europe Solutions B.V.

Bio-energy booster for fuels blending - Juana Frontela Delgado, Refining R&D Controller, CEPSA - Compañía Española de Petróleos

10:45–11:05 a.m.

11:05–11:25 a.m.

12:05–12:25 p.m. 12:25–1:25 p.m.

LUNCH TRACK 1: REFINING

1:25–1:45 p.m.

2014 IRPC SPEAKERS INCLUDE:

TRACK 2: PETROCHEMICALS

Session 1: Process Technology/Process Optimization Session Chair: Syamal Poddar*, President, Poddar and Associates

TRACK 2: PETROCHEMICALS

TRACK 3: CLEAN FUELS/BIOFUELS

Session 4: Heavy Oil Session Chair: TBD

Session 5: Refinery/Petrochem Integration Session Chair: Eric Benazzi*, Marketing Director, Axens

Session 6: Clean Fuels Session Chair: TBD

The move to higher value transportation fuels from residual fuel oil - Ronald L. Dickenson, President, SFA Pacific

The value of naptha in steam cracking - Duncan Seddon, Director, Duncan Seddon & Associates Pty. Ltd.,

New solutions for clean fuels production, PRIS technology - Oleg Parputc, R&D Director, RRT Global, Inc.

MICHAEL SILVERMAN Senior V.P., Downstream Technology & Chief Technology Officer Ivanhoe Energy

RAMANA MURTHY Specialist, Process Kuwait National Petroleum Company

C.H. RAMA KRUSHNA CHARY Environment Engineer Kuwait Oil Company

CARLO ZAFFARONI Ph.D. P.E., Industrial Water & Process Director, Europe CH2MHILL S.r.l.

FIORENZO GUITINI Downstream Service Engineering Manager GE Oil & Gas

SUDHAKARA BABU MARPUDI Sohar Refinery Oman Refineries and Petroleum Industries Company

BRUCE R. BEADLE Engineering Specialist Saudi Aramco

VERONIQUE REICH Principal Process Engineer Technip E&C Ltd

JUANA FRONTELA DELGADO Refining R&D Controller CEPSA - Compañía Española de Petróleos`

VISHWANTH DASARI Inspection Engineer Indian Oil Corporation Limited (IOCL)

AGENDA DAY 2: Wednesday, 25 June 2014 (Continued) TRACK 2: PETROCHEMICALS

TRACK 3: CLEAN FUELS/BIOFUELS

1:45–2:05 p.m.

Road map for designing a heavy crude refinery: A case study - Ahmad al Majed, Team Leader - Process and Ramana Murthy, Specialist - Process, Kuwait National Petroleum Company

TRACK 1: REFINING

Refinery / ethylene plant integration through refinery offGas (ROG) - Nick Rogers, Ethylene Technology Consultant, and Veronique Reich, Principal Process Engineer, Technip E&C Ltd

Assessment of cost and emissions as a function of abatement options in maritime emission control areas Dr. Haakon Lindstad, Ph. D, MARINTEK, Norwegian Marine technology Research Institute

2:05–2:25 p.m.

The competitiveness of western Canadian oil sands in North American and international markets: opportunities and challenges - Duke Du Plessis, Senior Advisor & Research Manager, Alberta Innovates-Energy and Environment Solutions

Value addition through refinery and petrochemical integration- Vineet Bakshi, Senior Process EngineerStrategy & Business Development and Vinay Gupta, Deputy Process Manager- Strategy & Business Development, Engineers India Limited

Biocrude production from microalgae and characterization of TBP distillates of algal biocrude blend, Dr. A. Meenakshisundaram, Chennai Petroleum Corporation Ltd.

2:25–2:45 p.m.

The future of heavy oil - Michael Silverman, Senior V.P.Downstream Technology & Chief Technology Officer, Ivanhoe Energy

Latest advances and applications of high performance trays in the mass transfer technology for the refining and petrochemical industry - Francesco Pezzotti, Technical Sales Area Manager, Baretti Mefe

Benefits of a FEL based planning on refinery expansion project - Juan Manuel Anzaldo Trejo, Process Engineer, Instituto Mexicano del Petróleo

2:45–3:05 p.m.

Reactivity and stability of vacuum residual oils in their thermal conversion - Dicho Stratiev, Chief Process Engineer, Lukoil Neftohim Burgas

Petrochemicals: An opportunity for refiners Stefano Zerinder, Senior Consultant Global Refining & Petrochemical Feedstocks, ICIS Consulting

3:05–3:35 p.m.

A cloud based tool blend optimizer management and real-time monitoring of the production of bio-fuels - Chebre Meriam, Senior APC Engineer, Total Refining Chemicals

COFFEE BREAK TRACK 1: REFINING

TRACK 2: PETROCHEMICALS

TRACK 3: WATER MANAGEMENT

Session 7: Revamp/Upgrading/Emerging Technology Session Chair: TBD

Session 8: Process Technology Session Chair: Stephany Romanow*, Editor, Hydrocarbon Processing

Session 9: Water Management Session Chair: TBD

3:35–3:55 p.m.

Revamping your crude distillation unit for maximal energy efficiency & uptime - Eva Andersson, Refinery Market Manager, Alfa Laval

Replace heavy reformate clay treaters with a selective hydrogenation unit - Bruce R. Beadle, Engineering Specialist, Saudi Aramco

Treatment and management of wastewater in refineries for a sustainable environment — a QP refinery approach - Nadim Shakir, Senior Products Engineer, Qatar Petroleum

3:55–4:15 p.m.

Optimizing operational parameters around coke drums, based on inputs from health monitoring system - A.S. Sahney, Chief Technical Services Manager, and N. Venkatesh, Indian Oil Corporation, Ltd., Gujarat Refinery

Case Study: Reduction of shutdowns from every 6 months to 4 years through installation of SAF2707 in the overhead condensers - Eduardo Perea, Global Technical MarketingTube, Sandvik Materials Technology

Zero liquid discharge – best practicable environmental option? - Carol Butcher, Principal Consultant Environment and Sustainability, Foster Wheeler UK

MericatTM J: A new kerosene treating technology to meet jet fuel specifications - Karl Bussey, Senior Technical Services Engineer, Merichem Company

Operational excellence opportunities - plant optimization and decision support systems - Vikas Deshmukh, Senior Technical Advisor, KBR Technology

State of the art waste water treatment plant with innovative solutions for BAPCO refinery in Bahrain - Carlo Zaffaroni, Ph.D. P.E., Industrial Water & Process Director – Europe, CH2MHILL S.r.l.

Using membranes to recover valuable hydrocarbons - new applications in refinery processing - Nick Wynn, Chief Operating Officer, Membrane Technology & Research Inc.

SD’s integrated ethanol to EO/ EG process - Sanjeev Goyal, Project Manager, Scientific Design Company, Inc.

Shaping the future of the water industry breakthrough technology in water desalination and waste water treatment - Dr. Emad Aljuraifani, General Manager, Future Resources Co. Ltd

Innovative advancements in delay coking equipment David Anderson, Refinery Market Manager, DeltaValve, a Curtiss-Wright Company

Role assessment of major process parameters impacting PDH economics - Salahudheen Ottayil, Senior Optimization Engineer, National Petrochemical Industrial Company

Water recovery and recycle in the PVC production: a novel approach using membrane technology - Frank Lipnizki, Business Manager, Alfa Laval-Business Centre Membranes

4:15–4:35 p.m.

4:35–4:55 p.m.

4:55–5:15 p.m. 5:15 p.m.

CLOSING REMARKS

2014 IRPC EXHIBITORS INCLUDE:

AGENDA DAY 3: Thursday, 26 June 2014 8:30–9:15 a.m.

CONTINENTAL BREAKFAST

9:15–9:30 a.m.

OPENING REMARKS: Stephany Romanow, Editor, Hydrocarbon Processing

9:30–10:15 a.m.

KEYNOTE ADDRESS: Reshaping of refining landscape in Europe - Bakheet Al-Rashidi, CEO and President, Kuwait Petroleum International

10:15–10:45 a.m.

Eni Green Refinery project in Venice - Claudia Prati, eni S.p.A.

10:45–11 a.m.

COFFEE BREAK TRACK 1: REFINING

TRACK 2: PETROCHEMICALS

Session 10: Optimization/Efficiency Session Chair: Andrea Amoroso*, Vice President, Process Technology, eni S.p.A

Session 11: Maintenance/Reliability/Corrosion Session Chair: David Bridgeman*, Global Licensing Manager, GTC Technology US, LLC

11–11:20 a.m.

Integrating assay knowledge management with process simulation to create a competitive advantage and increase profitability - Joseph McMullen, Simsci Prooduct Marketing, Invensys

Quality team as a support function for maintenance in plant turn-around - Tuomas Ouni, Expert, Phenol and Hydrocarbon Technologies, Borealis Polymers Oy

11:20–11:40 a.m.

Increasing of the gasoline productivity at Azzawia refinery using pyrolysis gasoline Jamal B. Rashed and Ezeddine Muftah, Researcher, Libyan Petroleum Institute (LPI)

Understanding corrosion under insulation (CUI) coatings, reliable and simple, but choose correctly - Miles Buckhurst, Global Concept Director – HPI, Jotun AS.

11:40 a.m.–12 p.m.

Optimizing refinery assets by integrating characterization, optimization and simulation technologies in a common platform shared by planning and scheduling tools - Aurelio Ferrucci, Executive V.P., PROMETHEUS S.r.l.

Causes and prevention of corrosion on the interior surface of metal jacketing used on mechanical insulation - Jim Young, Technical Director, ITW Insulation Systems

12–12:20 p.m.

Refineries need to adapt: imbalances between crude oil quality and refinery configuration offer opportunities to improve refinery profitability - W. Paul Ruwe, Group Manager, and Peter Bartlett, Group Manager, Jacobs Consultancy, Inc.

Stress corrosion cracking in SS 316 steam coil - Vishwanth Dasari and Bijay K. Muduli, Inspection Manager, Indian Oil Corporation Limited (IOCL)

Improved turnaround Management - a sure shot formula for profitability Sudhakara Babu Marpudi, Sohar Refinery, Oman Refineries and Petroleum Industries Company

FCC special valves: best practices to increase performance, reliability and service life - Mauro Natalini, Deputy Manager- Valve Engineering, Remosa Valves

12:20–12:40 p.m.

12:40–1 p.m.

Maximize power efficiency and profitability through medium voltage electric heating technology - Christopher Molnar, Vice President of Industrial Heaters & Systems, Chromalox, Inc.

Energy benchmarking to increase energy efficiency - Mark Eggleston, Phillip Townsend Associates

1–2 p.m.

LUNCH TRACK 1: REFINING

TRACK 2: PETROCHEMICALS

Session 12: Catalysts Session Chair: Doug Kelly*, Vice President, Refining, KBR Technology

Session 13: Equipment/Instrumentation/Management Session Chair: TBD

Increasing profitability via hydroprocessing flexibility and know-how Robert Wade, Staff Engineer, Advanced Refining Technologies

Steam turbines and centrifugal compressors efficiency and reliability improvements in ethylene plant upgrade - Fiorenzo Guitini, Downstream Service Engineering Manager, GE Oil & Gas

Commercial experience of operating FCC unit with low catalyst-to-feed ratio and the reduced REO content in the catalysts - M.I. Levinbuk, Chief Researcher, Topchiev Institute of Petrochemical Synthesis, RAS

Wireless monitoring of rotating equipment using intelligent sensors with mobile capability - Dale Winterhoff, Principal Engineer and Rick Lawson, Director of Product Management, Flowserve Corporation

2:40–3 p.m.

Symphony™, the next generation family of higher performance reforming catalysts Xavier Decoodt, Head of Reforming Hydrogenation – Catalysts and Absorbents, Axens

Condition monitoring of complex petrochemical system through acoustic emission evaluation - Alberto Monici, Electronics Engineer, ETS Sistemi industriali Srl

3–3:20 p.m.

Filtrex s.r.l. ACR filtration technology ensures longer catalyst life and cycle lengths of key refinery process units - Riolo Nicola, Business Director, FILTREX S.r.l.

An overview of energy management system (ISO 50001) with it’s implementation plan C.H. Rama Krushna Chary, Environment Engineer, Kuwait Oil Company

2–2:20 p.m.

2:20–2:40 p.m.

3:20–3:50 p.m.

COFFEE BREAK TRACK 1: REFINING

3:50–4:10 p.m. 4:10–4:30 p.m.

TRACK 2: PETROCHEMICALS

Session 14: Maintenance/Reliability Session Chair: Faisal M. Faqeer*, RT Refinery Engineering Manager, Saudi Aramco

Session 15: Feedstocks Session Chair: TBD

Upgrading a CDU main fractionator with innovative mass transfer components Guiseppe Mosca, Refinery Global Application Manager, Sulzer Chemtech

Go Light: The impact of feedslate shifts on fouling in steam crackers – Jessica M. Hancock, Industry Development Manager-Europe, Russia, Africa, Nalco Champion, an Ecolab Company

Using handheld x-ray fluorescence to predict and prevent sulfidation corrosion failures - Mark Lessard, Thermo Fisher Scientific

Petrochemicals from non-conventional feedstock regarding North American shale gas - Bernhard Kneissel, Global Head- Industrial Chemistry, Stratley AG

4:30 p.m.

CLOSING REMARKS

*2014 Advisory Board Member

IRPC 2014 SPONSORS:

Wireless Internet Sponsor Lead Sponsor

Refining Track Sponsor

Lanyard Sponsor

Speaker Gift Sponsor

Dear Hydrocarbon Processing reader, Meeting the world’s need for refined oil and petrochemical products is a massive undertaking, and one that reaches every corner of the globe. As the hydrocarbon processing industry (HPI) strives to meet that need safely and cost-effectively, it is becoming larger, more international and more technically-advanced than ever before. As a reader of Hydrocarbon Processing, you are well aware of the important work being done each day. Your contribution to the industry, as an innovator and practitioner, is why you should be a part of our upcoming International Refining and Petrochemical Conference (IRPC) to be held June 24–26 in Verona, Italy. Now in its fifth year, IRPC 2014 will include 72 technical presentations, numerous networking opportunities and an esteemed group of speakers representing operators and leading technology providers from 24 different countries. IRPC 2014 attendees will also have the unique opportunity to take a tour of Eni’s Venice biorefinery—the first refinery in the world to convert from a conventional plant into a biofuels production plant based on Eni’s patented Ecofining technology.

Here are a few more reasons why you should make plans to attend IRPC 2014: Take part in tracks on refining, petrochemicals, and for the first time, on clean fuels/biofuels Join international HPI professionals from around the world, representing leading operators, refineries and petrochemical plants, engineering and construction firms, chemical companies, equipment suppliers and service companies Ample networking opportunities between sessions allow you to connect with existing and new business contacts Discover the latest technology and operational advancements in clean fuels, biofuels, energy efficiency and water management Gain local and global perspectives on refining, petrochemicals, catalysts, maintenance and reliability, unconventional feedstocks and project control Hydrocarbon Processing has covered the growth and development of the hydrocarbon processing industry since 1922. We developed the International Refining and Petrochemical Conference to provide a new platform for industry leaders to share knowledge and network. The conference is unique in providing both local and global perspectives and providing a collaborative environment for meaningful dialogue between attendees, speakers and exhibitors. We hope you’ll make your plans to attend IRPC 2014 and be a part of the discussion. Sincerely,

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VERONA, ITALY | 24–26 JUNE 2014

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HERE’S WHAT PAST ATTENDEES HAD TO SAY: “The exhibition was a great framework. There was plenty of time to meet people and discuss. This is exceptional and unique to IRPC.” R&D Project Manager, France (IRPC 2012, Milan) “I attended for the second time, the first one being Rome. Excellent organisation and good team-work. I am looking forward to next one.” Managing Director, Italy (IRPC 2012, Milan) “IRPC conference was a great opportunity to get acquainted better with the leaders of the world petroleum industry.” Process Engineer, Russia (IRPC 2013, New Delhi) “It was excellent conference, with very high level of technical content, relevant to our constantly evolving business.” Senior Technical Director, USA (IRPC 2013, New Delhi)

Register to attend today at HPIRPC.com For Sponsor and Exhibit Opportunities: Lisa Zadok, Event Sales Manager, +1 (713) 525-4632 or [email protected] Speaking Opportunities/General Inquiries: Melissa Smith, Events Director, +1 (713) 520-4475 or [email protected]

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Maintenance and Reliability J. THARAKAN and M. ANISUZZAMAN, Suncor Energy Inc., Calgary, Canada

Evaluate piping for displacement-controlled loading In a Canadian case study, new piping under construction suffered some settlement in the underground portion, as evidenced by soil movement and slight deflection of the aboveground section of the piping. One of the flange joints on the line was broken to assess the amount of strain in the joint. The joint sprung open with a wide gap that was far in excess of acceptable flange alignment tolerances. This situation warranted an engineering assessment to evaluate the risk. The piping design details are as follows: • Design code: Canadian Standards Association (CSA) Z662 • Design pressure: 500 psig • Design temperature: 140°F • Original minimum design metal temperature (MDMT): –49°F • Material specification for the pipe: API X52 pipe (yield stress: 52,000 psi) • Pipe size: 16-inch (in.) outside diameter (OD) × 0.375-in. thickness • No post-weld heat treatment. Piping and flange integrity concerns. The aboveground piping with the opened flange joint is shown in FIG. 1. Measured vs. allowable alignment tolerance at this flange is presented in TABLE 1. Bolting misaligned flanges together introduces residual loads and moments into the piping system. In this case study, flange leakage was recognized as a great risk, and so the engineering assessment was limited to aboveground piping with flange joints. Hydrotesting was considered an adequate check for the underground piping. To evaluate the stresses in the piping and to assess the forces at the flange, the piping was modeled using proprietary stressanalysis software. If the aboveground piping is treated as two sections, A and B, then the total flange gap of 2.1 in. should be the sum of the deflections at the end flanges of A and B. The deflections will be inversely proportional to the stiffness of the pipe sections A and B:

(DA + DB ) = 2.1 in., and (DA ÷ DB ) = (KB ÷ KA )

Several load cases were analyzed using stress-analysis software: 1. WNC + D1: Installation case (weight with no contents and with displacement) 2. W + D1 + T1 + P1: Maximum operating temperature case with displacement 3. W + D1 + T3 + P1: Minimum operating temperature case with displacement (for brittle fracture calculation) 4. W + D1 + T4 + P1: Minimum operating temperature case with displacement (for brittle fracture calculation) 5. Expansion case: (W + D1 + T1 + P1) − (W+ P1). In these load cases, T1 = 140°F, T3 = −49°F and T4 = −40°F. An installation temperature of 14°F was used for the assessment. The additional stresses introduced in the piping by externally applied forces, used in aligning the flanges, are secondary stresses. CSA Z662 uses Eq. 2 for estimating operating stress: σ = [PD ÷ (4t) + MA ÷ Z + i × MC ÷ Z]

(2)

where: P = Pressure i = Stress intensification factor (SIF) MA = Moments due to primary loads (sustained loads) TABLE 1. Measured vs. allowable alignment tolerance at opened flange joint in aboveground piping Item

ASME PCC-1 tolerance, in.

Measured tolerance, in.

Gap, max./min.

0.03125

0.85

Max. lateral offset at flange OD

0.0625

0.96

Spacing between the flanges

0.25

2.1 (max. gap used)

(1)

where DA and DB are the displacements, and KA and KB represent the stiffness measurements. DA and DB were computed using Eq. 1, and the displacement stress at both A and B were evaluated. Section B, shown in FIG. 2, was found to have maximum stresses. For this reason, detailed analysis was restricted to this section.

FIG. 1. Underground/aboveground transition section. Hydrocarbon Processing | MAY 201467

Maintenance and Reliability MC = Moments due to secondary loads (displacementcontrolled loading) D = Pipe outside diameter t = Pipe thickness Z = Section modulus. When SIF is equated to unity, the peak stress component will be removed, and the resulting stresses are primary and secondary stresses.

If resulting compressive strains due to primary and secondary stresses are less than the compressive strain capacity of the pipes, then there is no risk of buckling. Among the loading scenarios, the installation case produces the highest compressive stress of 37,085 psi (bending stress at node 70 with SIF = 1). Compressive strain = compressive stress ÷ modulus of elasticity, and is shown in Eq. 3:

Failure analysis. There are several possible reasons for piping

The ultimate compressive strain (Eq. C-13 in CSA Z662) is:

failure, and a failure analysis must be performed for each case. Plastic collapse. The aboveground piping did not reveal any visible deformation after the flange assembly. However, there could be residual stresses in the line resulting from displacement-controlled loading. These stresses are secondary stresses. Due to their self-limiting nature, secondary stresses cannot cause a plastic collapse. Pipe buckling. Bending causes tensile stresses at the outer curvature, and compressive stresses at the inner curvature. Only compressive stresses have a tendency to cause buckling.

FIG. 2. Piping section B.

Failure assessment diagram (FAD): DPHI = 90°

1.3

(0.16, 1.05)

Toughness ratio, Kr

0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.1

0.2

0.3

0.4

0.5

The allowable compressive strain is Фec × ⑀c (Eq. C-12 in CSA Z662), where Фec is the resistance factor for compressive strain and is equal to 0.8. The allowable compressive strain is Фec × ⑀c, or 0.8 × 0.0092 = 0.0074 = 0.74%. The calculated compressive strain of 0.13% is less than the allowable compressive strain of 0.74%. Therefore, buckling is unlikely. Fatigue failure. Only cyclic loads contribute to fatigue. The displacement applied to align the flange is not cyclic in nature; therefore, no specific fatigue evaluation is required. The code expansion case is primarily used as a check against fatigue failure: • Expansion stress SE = 22,400 psi • Code allowable stress SA = 37,489 psi • Since SE < SA, it passes the design. Brittle fracture. This evaluation is carried out using proprietary engineering assessment software, as per API 579-1/ ASME FFS-1.2 Brittle fracture assessment requires an estimation of the stress intensity factor driving the crack. The primary and secondary stresses have different impacts on the stress intensity factor. For this reason, these components should be individually estimated. The operating stress is calculated in Eq. 5: (5)

Therefore, the operating stress at −49°F = 49,941 psi. [PD ÷ (4t) + M A ÷ Z] is sustained stress, which is the primary stress. The primary stress equals 8,060 psi. The secondary stress component is obtained by subtracting the primary stress from the operating stress; i.e., 49,941 − 8,060 = 41,881 psi. The residual stress at the weld is also a secondary stress, which is separately estimated by the engineering assessment software using rules in API 579-1, Appendix E. Since the pipe welds are not heat treated, weld residual stresses are as high as yield strength. The fracture toughness required for the assessment is estimated from Charpy impact test results and the yield strength of the material. At −49°F, the material met a minimum Charpy V-notch number of 15 ft-lb, and the minimum specified yield strength σy = 52,000 psi. Lower-bound fracture toughness was calculated using the Welding Research Council 265 correlation:

1.1

0.0 0.0

(3)

⑀c = 0.5 × (t ÷ D) − 0.0025 + 3,000 × [(Pi − Pe) × D ÷ 2tE)]2 = 0.5 × (0.375 ÷ 16) − 0.0025 + 0 = 0.0092 (4)

σ = [PD ÷ (4t) + MA ÷ Z + MC ÷ Z], when SIF = 1

1.2

1.0

⑀cf = σ ÷ E = 37,085 ÷ 28,000,000 = 0.0013 = 0.13%

0.6 0.7 Load ratio, Lr

0.8

0.9

1.0

FIG. 3. Failure assessment diagram with (Lr, Kr) at −49°F.

68MAY 2014 | HydrocarbonProcessing.com

1.1

1.2

1.3

Klc = (2 σy) √ (CVN ÷ σy − 0.01) = 2 × 52 √ (15 ÷ 52 − 0.01) = 45 ksi √in. where Klc = fracture toughness.

(6)

Maintenance and Reliability A crack-like flaw was assumed, as per the rules in ASME Section 8, Division 2/API 579-1 for MDMT determination using a fracture mechanics approach. The crack location, orientation and size are as follows: • Location: A surface-breaking flaw originating from the OD surface • Orientation: Parallel to the circumferential weld • Flaw depth: 0.09375 in. (flaw depth is 25% of the thickness) • Flaw length 2C: 0.5625 in. (six times the depth). Brittle fracture assessment requires a failure assessment diagram (FAD), which depicts the interaction between two failure modes, namely plastic collapse (represented by Lr) and brittle fracture (represented by Kr). If (Lr, Kr) falls below the FAD, it passes assessment. Running engineering-assessment software for an assessment temperature of −49°F yielded a (Lr, Kr) that fell above the FAD (FIG. 3). A value of Kr > 1 clearly indicated a risk of brittle fracture. The exercise was repeated with an assessment temperature of −40°F, with primary and secondary stresses of 8,060 psi and 41,261 psi, respectively. The fracture toughness at −40°F was calculated using Eqs. 7–10: Klc = 33.2 + 2.806 exp × [0.02 × (T − Tref + 100)] Tref = −28.7°F when solved using Klc = 45 ksi √in. for T = −49°F T = −40°F and Tref = −28.7°F

(7) (8) (9)

Klc = 49.7 ksi√in.

(10)

The fracture mechanics assessment resulted in (Lr, Kr) = (0.16, 0.88), which fell below the FAD. Therefore, −40°F is acceptable as the MDMT. Local failure. When tensile strain exceeds allowable limits, and it manifests as a rupture, local failure occurs. CSA Z662 establishes strain limits per principles of fracture mechanics, which is a rigorous procedure. Instead of utilizing the limits outlined in CSA Z662, local failure was ruled out using alternative reasoning. CSA Z662 allows an installation strain of 2.5% (primary and secondary strains). The primary and secondary tensile stresses are the highest for the operating case at −40°F, which is 49,321 psi. This translates to a strain of just 0.18%. Flange leakage. Several methods exist for calculating the risk

of flange leakage. Equivalent pressure method. The axial force and moment at the flange at operating conditions are converted to an equivalent pressure in this method. Stress-analysis software performs this calculation, and its computation is shown in Eq. 11: Equivalent pressure Pe = (16M ÷ 3.14G 3) + (4Fa ÷ 3.14G 2) + P

(11)

where M is the resultant moment in in.-lb, Fa is the axial force in lb, P is the internal pressure and G is the effective gasket diameter. Therefore:

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Hydrocarbon Processing | MAY 201469

Maintenance and Reliability Pe = 16 × 173,674 × 12 ÷ (3.14 × 17.443) + 4 × 23,463 ÷ (3.14 × 17.442) + 500 = 2,600 psi

(12)

There are several possible reasons for piping failure, and a failure analysis must be performed for each case. This result is higher than the 716 psig allowed at the design temperature of 140°F for a Class 300 flange. Therefore, the equivalent pressure method indicates a risk of flange leakage. ASME B31.8 flange leakage calculation. In this calculation, the allowable moment for flange leakage is ML = (C ÷ 4) × (SbAb − PAp). The Class 300, 16-in. flange has 20 bolts of size 1¼ in. The tensile area of the bolt is 1 in. In this calculation: • Ab = Total area of flange bolts, in.2 = 20 × 1 in.2 = 20 in.2 • Ap = Area to outside of gasket contact = π ÷ 4 × (18.25)2 = 261.5 in.2 • C = Bolt circle, in. = 21.25 in. • P = Internal pressure = 500 psi • Bolt stress Sb = 50,000 × 0.7 = 35,000 psi, where 50,000 psi is the initial bolt stress, and the factor 0.7 is used to account for a joint relaxation of 30%. Therefore, ML = (21.25 ÷ 4) × (35,000 × 20 – 500 × 261.5) = 3,024,140 in.-lb = 252,012 ft-lb. The maximum bending moment in the flange from the stress-analysis software’s operating case is 173,674 ft-lb. This is less than the allowable flange moment of 252,012 ft-lb. Therefore, this method predicts that flange leakage is unlikely. Modified flange leakage calculation. Since two common methods for flange leakage predicted contradicting results, an attempt was made to develop an alternate flange leakage calculation. This calculation is a modification of the ASME B31.8 leakage equation integrating principles from ASME PCC-1. When the external moment is less than ML, the gasket seating stress will be adequate. The modified equation is shown in Eq. 13:

The bending moment in the flange equals 173,674 ft-lb, which is 3% larger than calculated ML , indicating a slight risk of flange leakage. The leakage risk can be minimized by retorquing the flanges to a bolt stress of 50,000 psi. Bolt and flange stress limits. External alignment devices, such as come-alongs, will be used to align the flanges. When the alignment devices are removed after tightening the nuts, some changes in the bolt loads may occur, although they will not be substantial.3, 4 Based on finite-element analysis results,4 it is known that external moments have maximum influence on the longitudinal hub stress. The gap between mating flanges was measured after releasing the come-alongs to rule out flange rotation that might result from hub stress, if excessive. Results. The analyses showed that plastic collapse, buckling, local failure and fatigue failure of the piping are unlikely. A brittle fracture assessment at an MDMT of −49°F failed, but it passed for −40°F. The line must be rerated for an MDMT of −40°F. Also, the modified flange leakage calculation is accepted as the final criteria for flange integrity. The flange leakage can be addressed by retorquing the flanges to a bolt stress of 50,000 psi. If flange alignment tolerance exceeds limits, it should be corrected. When a deviation is accepted, an engineering analysis should be performed to identify the possible risks and mitigations. In this example, joint integrity was established by retorquing. This was proven by a hydrotest. Prior to the assessment, flange integrity was treated as the only major concern. However, the assessment revealed that brittle fracture is an equally important concern. Like flange integrity, brittle fracture is influenced by residual tensile stress that results from forces and moments applied in aligning the flanges. The modified flange leakage appears to reasonably predict joint integrity for this case study. The calculations may be useful for assessments of other flange joints in the presence of externally applied forces and moments. LITERATURE CITED Canadian Standards Association, Z662-11, Oil and Gas Pipeline Systems, 6th Ed., 2011. 2 American Petroleum Institute 579-1/ASME FFS-1, Fitness-for-Service, 2nd Ed., June 2007. 3 American Society of Mechanical Engineers, Standards and Certification, “PCC-12010: Guidelines for pressure boundary bolted flange joint assembly,” 2010. 4 Tagaki, Y., H. Torii, T. Sawa and Y. Omiya, “Effect of external bending moment on sealing performance of pipe flange connection,” ASME 2010 Pressure Vessels and Piping Division/K-PVP Conference, Bellevue, Washington, July 2010. 1

ML = (C ÷ 4) × (SbAb – Fa – Hp − A G PG )

(13)

where: Gasket area = A G = 0.785 × (Do2 − Di 2) = 0.785 × (18.252 − 16.632) = 44.36 in.2 Total bolting force = Sb × Ab = 35,000 psi × 20 = 35,000 × 20 = 700,000 lb Hydrostatic force = Hp = 0.785 G 2 × P = 0.785 × 17.442 × 500 = 119,380 lb Axial force in the flange = Fa = 23,463 lb (from operating case) PG = 4,000 psi, or the minimum recommended operating gasket seating stress for a spiral-wound gasket. (Note: This stress is larger than the gasket factor multiplied by the design pressure, which is used for the flange design.) Gasket reaction = A G PG = 44.36 × 4,000 = 177,440 lb. Therefore: ML = (21.25 ÷ 4) × (700,000 − 23,463 − 119,380 − 177,440) ÷ 12 = 168,104 in.-lb 70MAY 2014 | HydrocarbonProcessing.com

(14)

JOHN THARAKAN is a static equipment specialist at Suncor Energy Inc.’s Maintenance and Reliability group in Canada. He has an MS degree in mechanical engineering design and more than 30 years of experience in the oil industry. Mr. Tharakan develops best practices for reliability improvement and performs failure analyses and fitnessfor-service evaluations on in-service equipment. MUHAMMAD ANISUZZAMAN is a mechanical engineer at Suncor Energy Services Inc. in Canada. He holds an MS degree in mechanical engineering from McGill University in Montreal, Canada. Mr. Anisuzzaman’s research interests include fracture mechanics and static and dynamic stress analyses of piping and mechanical systems.

Process Design J. RENFRO, Honeywell Process Solutions, Houston, Texas; G. STEPHENSON, Honeywell Process Solutions, London, Ontario, Canada; E. MARQUES-RIQUELME and C. VANDU, Shell Global Solutions International BV, The Hague, The Netherlands

Use dynamic models when designing high-pressure vessels By definition, a pressure vessel is a closed container that is designed to hold gases and/or liquids at pressures substantially different from ambient conditions. They are used in many applications such as oil and gas production, crude oil refineries and petrochemical plants. Pressure vessels are also used as part of the process or as storage vessels for gases such as ammonia, chlorine, propane, butane and liquefied petroleum gas. More importantly, pressure vessels must operate safely within a set of process conditions as defined by the “design pressure” and “design temperature.” A pressure vessel that is inadequately designed to handle a high pressure constitutes a significant safety hazard. Accidents and failures. Disturbances, accidents and malfunctions can cause deviations in operating conditions for a pressure vessel that are different from the safe operating window. For example, high pressures and temperatures can result from exposure to a fire. Since their invention during the industrial revolution, many fatal accidents have been attributed to pressure vessels. Consequently, pressure vessel design, manufacture and operation are regulated by engineering authorities and backed by legislation.

PROTECTION SYSTEMS A common method of protecting process equipment against excessively high pressure or temperature is the emergency depressurization (also known as a blowdown) by means of relief devices such as relief valves and orifices, rupture disks and safety valves. Other depressurization equipment include separation vessels, heat exchangers, distillation columns and compressors. Emergency depressuring removes the potentially dangerous contents of the process equipment and transfers them to a safe and lower-pressure location. It also decreases the force exerted by the fluid on the walls of equipment by reducing the pressure quickly and diminishes the risk of event escalation due to a fire or a leak of an explosive or toxic gas. During depressurization in a typical two-phase separator, the vessel’s inlets and outlets (both gas and liquid) are closed by using isolation valves. The depressurization valve is opened, and the gas is disposed of via a restriction orifice or fixed choke into the flare (or vent) system. Instead of using a restriction orifice

to fix the flowrate, some installations use depressurization valves with a known flow coefficient. However, the blowdown process is a hazardous operation due to the very low temperatures generated by the fluid within the vessel during rapid depressurization. Heat transfer by the fluid within the vessel reduces the temperature of the vessel wall. If the temperature of the vessel wall falls below the ductile-brittle transition temperature of the construction material, brittle fracture of the vessel wall can occur.1 The shock experienced by a thick-walled vessel due to the combined stresses from rapid temperature and pressure changes arises from non-uniform temperature distribution in the vessel wall, which results in differential expansion and contraction. Such pressurized thermal shocks can lead to embrittlement of the metal wall and, in turn, result in fatigue failure of the vessel.2 A depressurization utility, built around a detailed model of a pressure vessel, can be used to simulate emergency plant depressurization. The simulation can predict the depressurization behavior of process equipment with enough accuracy to make better design decisions such as: • At what rate must gas be released from each equipment item to meet the required depressurization times? • What is the required total flare capacity? • What is the lowest metal temperature experienced in each equipment item and in the flare system? • Which low-temperature materials are required? • What size restriction orifice or other flowrate-controlling device and flare connections are required for depressurization in each section of the plant? Models and results. There are many versatile and user-

friendly depressuring utilities available. However, their predictions are conservative due to simplifications made in the mathematic models. The business impact from conservative predictions is that new plants are over designed with stainless steel (SS), and existing plants must be modified against high costs and deferred production. If SS is selected where carbon steel (CS) would have been adequate, equipment costs could be twice as high or more.3 Hydrocarbon Processing | MAY 201471

Process Design Accurate dynamic depressurization calculations are required to ensure the selection of the most cost-effective materials for safe and reliable operating services. For existing facilities, reassessment of the temperature during depressuring can lead to changes in operating conditions or changes in process equipment to ensure safe operation. There are many process safety requirements that must be considered when designing new process equipment and units or assessing the operation of existing assets. One of these requirements is avoiding brittle fracture of the metallic materials used in process equipment. Having reliable and consistent predictions of fluid and minimum wall temperatures during depressurization is fundamental to demonstrating compliance with this requirement. This article discusses the use of a rigorous non-equilibrium vessel model containing detailed heat

conduction calculations for the vessel wall and insulation to give accurate time-dependent trajectories of vessel fluid and wall conditions during a dynamic depressurization operation.

NON-EQUILIBRIUM VESSEL MODEL A discussion of a non-equilibrium vessel model is available in the literature, but it lacks specific mathematical detail.1 A newer model uses this approach as a foundation, but it is enhanced by rigorously handling three-phase (gas, liquid and water) systems to provide a wide variety of thermodynamic models. It incorporates better correlations for heat-transfer coefficients and rigorous formulas for volumes, surfaces and interfacial areas. Example: A vessel. The unit operation model for the vessel applies three equilibrium zones roughly corresponding to the vapor, liquid and aqueous holdups. This approach enables the model to represent non-equilibrium behavior that is common during depressuring. FIG. 1 illustrates a vessel with two zones. Droplets forming in the vapor zone move dynamically to the liquid and aqueous zones. Likewise, bubbles forming in the liquid and aqueous zones move dynamically to the vapor zone. Each zone incorporates heat transfer with the vessel wall, adjacent zones and the environment through heat conduction in the vessel wall and encasing insulation. The heat-transfer coefficient correlations take into account the phases and conditions of the fluids.4, 5 To ensure that the volumes, surface areas and interfacial areas used in the unit operation simulation are accurate, the model incorporates rigorous formulas for these quantities for vertically and horizontally oriented cylindrical vessels having any torispherical (dished) head style. Vessel geometry calculations. These calculations are incorporated into the model to address all styles of torispherical heads. For, example, torispherical heads are characterized by two dimensionless parameters: the dish radius and knuckle radius factors, which are defined as:

fd = Rd ⁄ D ≥ 0.5 fk = Rk ⁄ D ≤ 0.5

FIG. 1. Unit operation model of a vessel with two zones.

Where D is the inside diameter of the cylinder of the vessel; R d is the inside radius of the dish; and Rk is the inside radius of the knuckle.6 FIG. 2 shows a cross-section of a torispherical head. The head is formed by rotating the cross-section about its central axis.

Rd Knuckle

Rk

Dish

FIG. 2. Cross-section of a torispherical head.

72MAY 2014 | HydrocarbonProcessing.com

FIG. 3. Vessel orientations and nozzle locations.

Process Design Values of the dish radius and knuckle radius factors are well known for many standard torispherical head styles. However, some standard head styles, such as the Standard F&D and Shallow F&D head styles, have a fixed knuckle radius. In this instance, the knuckle radius factor cannot be determined until the diameter of the vessel is specified. Custom-head types can be modeled as long as fd and fk can be calculated. Vessel orientation and outlet calculations. The vessel

model allows the configuration of either a vertically or horizontally oriented vessel, as well as different locations of the depressurization outlet. The depressurization outlet is defined by a nozzle, which is configured through specification of the nozzle diameter and center height from the bottom of the vessel. FIG. 3 shows the different vessel orientations and depressurization nozzle locations that are supported. The depressurization nozzle can be at the top or bottom or on the side of the vessel. The depressurization nozzle allows accurate modeling of fluid removal from the vessel. The overall composition in the nozzle is determined by mixing outflows from the zones in the vessel. The outflow for a zone is the fraction of the nozzle cross-sectional area covered by the fluid in the zone times the total outflow, which is established by the restriction orifice connected to the depressuring nozzle. Restriction orifice model. The restriction orifice model

provides a pressure-flow relationship that is valid for choked and non-choked flow and fluids at the inlet that are single or multiphase. The flow-pressure relationship is derived starting from a steady-state momentum balance, resulting in a general expression for the mass flux, G, given as: G(P)=Cd g(v, Pi , Po , Pc ) where: Pi = Inlet pressure Po = Outlet pressure Pc = Critical pressure v = Molar volume The critical pressure is the pressure associated with the maximum mass flux. The computed discharge coefficient, Cd is a function of the constant discharge coefficient and the inlet phase fractions, φI: Cd = Cd0 h(φI ) This form allows for an accurate representation of liquid, vapor and multiphase flows. Fire calculations. A vessel exposed to a fire can experience overpressure due to the vapor generation from boiling of the liquid contents or decomposition reactions. It can also cause overheating of the vessel wall, thus reducing the wall material strength. The heat transfer model incorporates a number of options to simulate depressurization when a vessel is exposed to an open-pool fire. Two of these options are based on ANSI/API Standard 521 (2007). The API 521 option is the method from API 521 wherein the wetted area is a constant. The API 521 enhanced option dynamically calculates the wetted surface area as the phase condition of the fluid within the vessel changes. A more rigorous option is also provided for modeling heat transfer Select 169 at www.HydrocarbonProcessing.com/RS

73

Process Design from a fire through radiation impingement on the outer surface of the vessel and heat conduction through the vessel wall. TABLE 1. Spadeadam experiment S12 Item

Value

CH4

66.5 mol%

C2H6

3.5 mol%

C3H8

30 mol%

Temperature

20°C

Pressure

120 bar

Diameter

1.13 m

Tan-tan height

2.25 m

Orientation

Vertical

Head type

2:1 semi-elliptical

Wall thickness

50 mm

Orifice diameter

10 mm

Back pressure

1.013 bar

External temperature

20°C

Vessel initialization conditions. Initialization of the fluid in the vessel is based on specifications provided for the initial temperature and pressure of the vessel and the total composition, which can be handled in two ways. First, the overall composition can be flashed at a specified temperature and pressure. The resulting phase compositions are used to initialize the compositions of the corresponding zones of the vessel. When the flash predicts that liquid is present, then the initial holdup of liquid must be independently specified. Second, the specified overall composition of the vessel can be the initial composition of the vessel. In this instance, the liquid holdup in the vessel is completely determined by the thermodynamic relationships and cannot be independently specified. The initial temperature profile through the vessel wall and insulation can have a significant impact on the predictions made by the dynamic model. Consider, for example, initializing the wall and insulation temperature profile to the initial temperature of the fluid holdup in the vessel. When this temperature is greater than the environment temperature, the energy content in the vessel wall and insulation is overestimated. Similarly, when this temperature is less than the environment

140

25 Blowdown utility prediction Experimental values

120

5 Temperature, °C

Pressure, bar

100 80 60

-5

-15

40

-25

20 0

-35 0

500

Time, sec

1,000

1,500

FIG. 4. Pressure profile for Spadeadam experiment S12.

500

Time, sec

1,000

1,500

20

Experimental values – liquid zone Blowdown utility prediction – liquid zone

15

15 10 5 Temperature,°C

5 Temperature, °C

0

FIG. 6. Vapor-zone temperature profile for Spadeadam experiment S12.

25

-5

0 -5

-10

-15

-15 Blowdown utility prediction – vapor zone Experimental values – liquid zone Experimental values – vapor zone Blowdown utility prediction – liquid zone

-20

-25 -35

Blowdown utility prediction – vapor zone Experimental values, low Experimental values, high

15

-25

0

500

Time, sec

1,000

1,500

FIG. 5. Liquid-zone temperature profile for Spadeadam experiment S12.

74MAY 2014 | HydrocarbonProcessing.com

-30

0

500

Time, sec

1,000

FIG. 7. Wall-temperature profiles for Spadeadam experiment S12.

1,500

Benefit From Our Expertise

Process Design temperature, the energy content in the vessel wall and insulation is underestimated. In either case, the predictions of the temperature profile in the vessel wall and insulation and conditions of the fluid holdup will be attenuated during depressuring. Although not strictly correct, a steady-state wall initialization method can provide the most realistic initialization of the temperature profile. With this method, the initial temperature profile in the vessel wall and insulation is calculated by solving the steady-state heat conduction equation with the convective boundary condition applied at the inner surface of the wall and the outer surfaces of the insulation.

MODEL IMPLEMENTATION The dynamic vessel model calculations described here are incorporated into a new dynamic depressurization simulation utility; it was developed to overcome serious deficiencies identified in earlier existing tools, such as:a • Numerical stability. Some tools can stall during calculations, especially for depressurization cases in which the fluid is narrow boiling, the conditions within the vessel are close to the critical conditions of the fluid, or abrupt phase changes occur during depressurization. • Systems with a water phase. Although theoretically some tools can model a water phase, in practice, the solution of three-phase systems presents many numerical challenges. • Limited number and type of components • Limited selection of thermodynamic methods • Limited capability to set the style of the heads of the vessel • Calculation of the initial conditions is not rigorous. The model was implemented using an equation oriented (EO) simultaneous formulation solution to handle the complexity of interactions of the different model mechanisms. Using an EO simultaneous solution formulation allows extension to future optimal design problem formulations in an efficient way.

Series 3730 and 3731 Positioners „Convenient operation on site or by process control system (HART®, PROFIBUS-PA or FOUNDATION™ fieldbus) „Rugged mounting kits for linear and rotary actuators „Suitable for use in safety-instrumented systems (SIL 3 according to IEC 61508) „Integrated valve diagnostics for control

Model validation. The presented model was tested against a

and on/off valves (e.g. partial stroke testing)

large number of vessel depressurization experiments from the Spadeadam tests.7 These experiments covered a wide range of compositions, top and bottom blowdown, vessel orientations and orifice sizes. TABLE 1 summarizes the input data for Spadeadam experiment S12.7 This experiment was configured and executed with the rigorous dynamic model.a The Spadeadam experiment S12 demonstrates retrograde condensation, in which condensate forms even though the pressure is dropping due to depressurization. The results are shown in FIGS. 4–7. As illustrated in FIG. 4, good agreement is demonstrated between the experimental pressure profile and the predicted pressure. FIGS. 5 and 6 show the experimental data for the liquid and vapor temperature regions of the vessel compared with the model predictions. The predicted temperature profiles match the experimental data, and they clearly show that the vessel conditions are not at equilibrium. FIG. 7 shows the experimental wall temperatures in the vapor and liquid regions of the vessel compared with the model predictions for the same locations. Again, the model predictions agree quite well with the experimental data.

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A01147EN

Better design tools for pressurized vessels. A detailed non-equilibrium vessel model was developed, incorporating

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Process Design a dynamic depressuring as part of the simulator. This added flexibility addresses the value in the selection of construction materials for vessels as well as orifice sizing. It overcomes serious deficiencies identified in earlier commercially available tools. The model can provide a high degree of solution accuracy and is robust for three-phase systems. The model consistently predicts liquid formation when it occurs experimentally and demonstrates stable solution behavior in systems with many components. The utility offers a large number of accurate thermodynamic models and can be used to model vessels with any torispherical head style. It also performs rigorous calculation of initial phase equilibrium and vessel conditions. a

NOTES The dynamic vessel model calculations described previously have been incorporated in a new dynamic depressurization utility of the UniSim Design process simulator, named the Blowdown Utility.

LITERATURE CITED Complete literature cited is available at HydrocarbonProcessing.com. JEFF RENFRO is an engineering fellow of Honeywell’s Automation and Control Solutions business. At Honeywell, he has worked with advanced process control, MES and simulation groups as a solution architect and consultant. Dr. Renfro is a member of the UniSim Design development team. He has also worked for Shell Development Co., Dynamic Matrix Control Corp., Dynamic Optimization Technology and Products, and PAS. During his career, he has supported the OPERA, DMO and NOVA optimization and modeling systems, and served as both a consultant and implementer for their online applications. Dr. Renfro holds a BS degree in chemical engineering from the University of Texas and a PhD in chemical engineering from the University of Houston.

GRANT STEPHENSON is an engineering fellow of Honeywell’s Automation Control Solutions business. In his current role, he serves as the global process simulation architect for Honeywell Process Solutions. Based in London, Ontario, Canada, he has worked in the field of process simulation for more than 35 years, with particular interest in dynamic simulation, equation-oriented modeling and simultaneous solution of flowsheet models, and the application of modeling and optimization to plant operations. Mr. Stephenson is the originator of the dynamic simulation engine of the Shadow Plant dynamic simulator and is a pioneer of the hybrid solution architecture and its application to large-scale dynamic simulation. Mr. Stephenson has held positions with DuPont Canada, Atomic Energy of Canada, the University of Western Ontario (SACDA) and Honeywell. He holds an MSc degree in applied mathematics from the University of Western Ontario. ESTEBAN MARQUES-RIQUELME is a senior application developer for process engineering applications in Shell Global Solutions International B.V. In his current role, Dr. Marques-Riquelme provides technical consulting services to build steadystate and dynamic models with several commercial flowsheeters and leads software development projects in process engineering. Throughout his career at Shell, he has held several positions in the statistical modeling and distillation disciplines. Before joining Shell, Dr. Marques-Riquelme worked as principal researcher for PEQUIVEN. In this position, he was responsible for R&D projects aiming at the optimization of polymer plants, the development of new products, and process modeling. He holds a PhD in chemical engineering from the University of South Florida, and an MA degree in applied mathematics from the University of Georgia. CHIPPLA VANDU is a concept engineer with Shell Global Solutions International B.V. At present, he works in front-end project development as a process integrator, while also providing process engineering services. In the course of his career with Shell, Dr. Vandu worked as a research technologist, developing simulation models for gas-to-liquids plants and later as a process engineer involved in the design and development of upstream facilities. He also served as a focal point for emergency depressuring, consulting to various projects and operational facilities. Dr. Vandu holds an MSc degree in chemical engineering from the University of Twente and a PhD in chemical engineering from the University of Amsterdam.

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76MAY 2014 | HydrocarbonProcessing.com

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Heat Exchanger and Tray Tower Specialist

Refining Developments J. SEXTON, J. HIGHFIELD and N. LARSEN, Marathon Petroleum Company, LP, Catlettsburg, Kentucky; and S. ISMAIL and D. NEUMAN, BASF Corp., Florham Park, New Jersey

Innovative catalyst solution mitigates FCC operational issue Marathon Petroleum Co.’s (MPC’s) Catlettsburg fluid catalytic cracking unit (FCCU) experienced a catalyst circulation constraint due to partial blockage of an intra-regenerator standpipe. The unit was initially debottlenecked by introducing torch oil, along with increased catalyst addition, to maintain unit activity. The refinery then introduced a high-activity co-catalyst into the FCCU. 1 The co-catalyst solution allowed removing the torch oil while maintaining catalyst activity, thus optimizing the FCCU’s profitability within the catalyst circulation limit. The cost of the co-catalyst is minor, while the direct measured value creation at the Catlettsburg refinery was over $1/bbl. Background. The Catlettsburg FCCU was originally commis-

sioned in 1983 as the world’s first reduced crude conversion (RCC) process unit.2 The process unit had a nominal capacity of 43,000 bpd (43 Mbpd). The reactor/riser system operated at low pressure to minimize the hydrocarbon partial pressures and to promote full and rapid vaporization of the resid feedstock. A unique feature of the design was a two-stage regenerator with a common flue-gas header. The two-stage design operated in partial-burn mode, with a typical carbon dioxide (CO2 )/ carbon monoxide (CO) ratio of 4. The regenerator used two catalyst coolers that generated 450-psig steam for heat-balance management. The regenerator flue gas was processed by limestone fluidized bed CO boilers, followed by a pair of baghouses for particulate capture. The regenerator pressure was controlled through a pair of flue-gas slide valves. The RCC unit was converted to an FCCU in 2003 as part of an overall refinery re-positioning project. By feeding hydrotreated vacuum gasoil (VGO), the result was a nominal 95Mbpd FCC capacity. The unit pressure was increased, and the two-stage regenerator was converted to full-burn operation. The catalyst coolers were decommissioned with one converted to an intra-regeneration standpipe to facilitate improved catalyst distribution. All of the existing equipment was reused with the exception of a new main air blower. FIG. 1 shows the present regenerator configuration. Catalyst exiting the riser is directed via the catalyst stripper to the upper section of the regenerator. In this section, the catalyst is burned relatively clean, with over 90% reduction in catalytic coke, which is deposited on the catalyst during the cracking process

in the riser. The remaining coke on the catalyst is burned in the lower, hotter section of the regenerator. The catalyst is then transferred from the upper regenerator to the lower regenerator via two standpipes. The catalyst leaves the bottom of the lower regenerator and is sent to the riser for the next cracking cycle. Situation. Upon re-starting the unit, following an unplanned

refinery shutdown due to a power failure, the unit experienced a catalyst flow restriction in one of the intra-regeneration standpipes. The reduced catalyst flow to the lower section compromised the heat balance, which was brought into an operable range by injecting torch oil. The FCCU was allowed to resume operations at the desired feedrate. The high localized temperature generated by the torch oil combustion was detrimental to

FIG. 1. A schematic of the two-stage regenerator; the standpipe on the back end was partially blocked. Hydrocarbon Processing | MAY 201477

Refining Developments TABLE 1. Comparison of total catalyst and heating costs during the three cases Case number

1

2

3

Low ROT steady state

Torch oil emergency

Co-catalyst under control

Combined feedrate, bpd

Base

Base

Base

API gravity, °API

Base

Base

Base

Feed temperature, °F

Base

Base

Base

Operational mode Riser/reactor operation

Riser outlet temperature, °F

Base

Base

Base

C/O ratio, wt/wt

Base

Base – 2.10

Base – 0.66

Base

Base + 91

Base + 22

Base (Fresh cat only)

2.3* Base (Fresh cat only)

1.5* Base (1:1 ratio)

Zero

High

Zero

Base

Base + $1.20

Base + $0.10

Activity, FACT%

Base

Base + 1.0

Base + 1.0

Nickel, ppmw

Base

Base – 33

Base – 21

Vanadium, ppmw

Base

Base – 336

Base – 210

Base

Base – 1.40

Base + 0.35

Base

Base

Base

Regenerator conditions Regen bed temperature, °F Fresh catalyst and torch oil Fresh cat + co-catalyst makeup, tpd Torch oil costs Total cost of heating the unit, $/bbl Equilibrium catalyst

Conversion Standard fresh feed conversion, vol% Cutpoint temperature, °F

4/1/12

Co-catalyst. The co-catalyst selected provides high activ-

Co-catalyst converter

8/1/12

12/1/12

FCC repairs

Steady state

Controlled shutdown

Power failure

Conversion, vol%, converter marker, wt%

Steady state

Torch oil

4/1/13

FIG. 2. Actual operating data at the Catlettsburg refinery during the three cases.

catalyst activity. Consequently, catalyst addition was increased to maintain catalytic activity. Because the unit processes very clean feed, the metal deposition on the catalyst is low, and the activity of its equilibrium catalyst (e-cat) is typically well maintained. Under normal steady-state operations, this unit uses very low levels of fresh catalyst. With the injection of torch oil, catalyst deactivation accelerated, and the catalyst addition rate more than doubled the typical usage to sustain activity at a desired level. MPC worked with its catalyst supplier to identify possible options to optimize the FCCU’s profitability. A co-catalyst was quickly identified as a viable solution for Catlettsburg.1 78MAY 2014 | HydrocarbonProcessing.com

ity and porosity with a large total surface area at 410 m2/g. It has a high Z/M ratio with maximum rare earth on the zeolite, thus the catalyst is stable even at high regenerator temperatures. The matrix provides a tailored porosity to allow the diffusion of heavy hydrocarbons into the particle, resulting in selective cracking. The co-catalyst is designed to fundamentally change unit performance faster than what can be achieved via a base catalyst change-out and, to a greater extent, than conventional operational changes. The flexibility provided by co-catalysts allows refiners to quickly respond to changes in operational issues, take advantage of changing economics, address feedstock changes, or simply improve the conversion of the existing base catalyst to maximize profitability. The use of a co-catalyst as a torch-oil replacement strategy at Catlettsburg was the first application of its kind. MPC understood that the co-catalysts’ high activity would provide consistent additional Δ coke, based on previous experiences. A risk assessment determined that there was little downside exposure by using the co-catalyst system. Results. The FCCU at Catlettsburg has a large catalyst inventory compared to other units with similar feedrates. Therefore, the co-catalyst was used at the high end of the usage rates. MPC chose to utilize the co-catalyst at a 1:1 ratio with the existing fresh catalyst formulation. Notwithstanding the high ratio of co-catalyst to fresh catalyst, the actual addition of the co-catalyst to the unit reached 30% of the inventory just before the planned shutdown to repair the unit. The co-cata-

Refining Developments TABLE 2. Comparison of operating conditions during the three cases Case number

1

2

3

Low ROT steady state

Torch oil emergency

Co–catalyst under control

Combined feedrate, bpd

Base

Base

Base

API gravity, °API

Base

Base

Base

Feed temperature, °F

Base

Base

Base

Operational mode Riser/reactor operation

Riser outlet temperature, °F

Base

Base

Base

C/O ratio, wt/wt

Base

Base – 2.1

Base – 0.66

Regenerator conditions Regen pressure, psig

Base

Base

Base

Regen bed temperature, °F

Base

Base + 91

Base + 22

Total air rate (dry), MSCFll

Base

Base + 423

Base + 28

Flue gas CO2, vol%

Base

Base + 0.2

Base + 0.1

Flue gas CO, vol%

Base

Base

Base

Flue gas O2, vol%

Base

Base + 0.01

Base

Fresh catalyst and torch oil Surface area

Base

Base

Base + 19

Base (Fresh cat only)

2.3 * Base (Fresh cat only)

1.5 * Base (1:1 ratio)

Base

Base + $1.20

Base + $0.10

Activity, FACT%

Base

Base +1.0

Base + 1.0

Nickel, ppmw

Base

Base – 33

Base – 21

Vanadium, ppmw

Base

Base – 336

Base – 210

CRC, wt%

Base

Base

Base

ZSM-5 additive content, wt%

Base

Base

Base

Rare-earth oxides, wt%

Base

Base

Base

Base

Base – 1.34

Base + 0.35

Base

Base – 0.10

Base + 0.17

Fresh cat + co-catalyst makeup, tpd Total cost of heating the unit, $/bbl Equilibrium catalyst

Conversion Standard fresh feed conversion, vol% +

C3 Liquid, vol%

lyst was introduced to the FCCU in the third week of August 2012, and, as shown in FIG. 2, conversion began to recover. During the torch oil injection period, even at increased catalyst addition rates, the conversion dropped substantially by about 3 vol%. Soon after the incident on the standpipes, the refinery’s production plan changed due to market demands, and the riser outlet temperature (ROT) was reduced to maximize light cycle oil (LCO) production. This move further exacerbated the situation, as a lower ROT means lower catalytic-coke generation and, therefore, lower regenerator temperature. During this time, the refinery experienced three economic burdens placed on the FCCU: • The increased operating cost of expensive torch oil • The value creation loss through the conversion drop • The increased catalyst usage to maintain process activity. The blockage in the interstage standpipe substantially reduced catalyst flow from the cooler section to the hotter section of the regenerator. This, in turn, compromised the catalyst circulation from the regenerator to the reactor. To maintain the regenerator temperature, a combination of high preheat, torch

oil and lower feedrate stabilized the FCCU operation but at a lower catalyst-to-oil (C/O) ratio. The FCC simulations, based on steady-state conditions, are used to eliminate the effects of extraneous variables in the evaluation.3 It is well known that catalytic conversion is the most profitable conversion process, as it increases the total liquid yield of high-valued products. This is also valid for the co-catalyst, as it has the highest activity per unit of catalytic coke make. As summarized in TABLE 1, the C/O ratio during the torch oil campaign dropped 25%. As expected, there was a corresponding decrease in conversion loss, as oil feed did not “see” sufficient catalyst for cracking to occur. When comparing the torch oil, Case 2, with the co-catalyst, Case 3, it is apparent that the C/O ratio with co-catalyst increased 23% over the torch oil period. The increase in C/O accompanied with co-catalyst’s higher activity made it possible for the conversion to increase 1.75 vol% above the torch oil (Case 2) or 0.35 vol% above the Base Case. Co-catalyst not only increased volume conversion, but, more importantly, the high activity of the product generated Hydrocarbon Processing | MAY 201479

Refining Developments TABLE 3. Comparison of yield slates during the three cases Case number Operational mode Unit net profit, $/bbl

1

2

3

Low ROT steady state

Torch oil emergency

Co–catalyst under control

Base

Base – $0.83

Base – $0.52

Riser/reactor operation Combined feedrate, bpd

Base

Base

Base

Riser outlet temperature, °F

Base

Base

Base

C/O ratio, wt/wt

Base

Base – 2.1

Base – 0.66

Base (Fresh cat only)

2.3 * Base (Fresh cat only)

1.5 * Base (1:1 ratio)

Base

Base + $1.20

Base + $0.10

Fresh catalyst Fresh cat + co-catalyst makeup, tpd Total cost of heating the unit, $/bbl Equilibrium catalyst Activity, FACT%

Base

Base +1.0

Base + 1.0

Nickel, ppmw

Base

Base – 33

Base – 21

Vanadium, ppmw

Base

Base – 336

Base – 210

CRC, wt%

Base

Base

Base

ZSM–5 additive content, wt%

Base

Base

Base

Rare-earth oxides, wt%

Base

Base

Base

Dry gas (H2 + H2S + C1 + C2 + C2=), vol%

Base

Base + 0.52

Base + 0.03

Propane, vol%

Base

Base + 0.01

Base + 0.16

Propylene, vol%

Base

Base – 0.26

Base + 0.03

n–Butane, vol%

Base

Base – 0.07

Base – 0.02

Isobutane, vol%

Base

Base – 0.45

Base + 0.33

Total butenes, vol%

Base

Base – 0.04

Base – 0.11

Total C3 + C4, vol%

Base

Base – 0.10

Base +0.61

C5+ gasoline (450°F cutpoint), vol%

Base

Base – 0.64

Base – 0.09

LCO (450°F to 680°F), vol%

Base

Base + 1.00

Base – 0.50

Decant (680°F +), vol%

Base

Base + 0.34

Base + 0.15

Base

Base – 0.10

Base + 0.17

Volume percent basis

+

C3 liquid, vol%

Operating data

Process check

Process analysis Optimizing operation

Final report

plier with operating data and economics of the Catlettsburg refinery. This partCatalyst company Catalyst company Catalyst company Catalyst company nership and sharing of data creates an analysis utilizes state-of-art checks for accuracy publishes a quarterly tools for comparison opportunity for the catalyst company to and consistency of data • Ecat data report with findings to Refinery provides • Fines analysis and simulation • Mass balance closure ensure operations operating data provide technical support reports that • Scrubber water FCC simulation models • Heat balance and profitability samples Comprehensive detail an ongoing systematic evaluation of • H2 balance targets are on track • Feed analysis benchmarking the FCCU. The reports are a framework for conversations regarding the matching FIG. 3. Information flow to support refinery operations to create maximum value. of an optimal catalyst solution to meet the changing needs of the refinery. FIG. 3 gives a graphical summary of the work flow or activities involved in sufficient catalytic coke that the refinery could reduce the torch ensuring that quality discussions are possible. oil injection rate. The transition from torch oil to co-catalyst MPC’s Catlettsburg refinery personnel worked with the catconverter was rapid. By the end of September, the torch oil inalyst company to evaluate the benefits of co-catalyst vs. torchjection was reduced to virtually zero. Additionally, total catalyst oil injection. An FCC simulation using a commercially available additions (base catalyst plus co-catalyst) were reduced by over FCC model was done.4 Using the data from a period in which 30%. Finally, application of the co-catalyst provided operating flexibility and allowed MPC to schedule a controlled shutdown. the refinery was running well under steady-state conditions, a Base Case model was constructed. It is well known that there are many interacting variables affecting the performance of the Post-audit results. As part of its relationship with its catalyst FCCU. An analysis was undertaken to answer questions such as supplier, MPC Catlettsburg regularly provided the catalyst sup80MAY 2014 | HydrocarbonProcessing.com

Refining Developments to harvest a higher selectivity of desired products. Dry gas was the impact of co-catalyst on the constant feed, ROT and other significantly lower by 0.5 vol%, while propylene and butylene operating conditions. All comparisons were done on the basis yields matched or exceeded the Base Case. The gap created of constant ROT and matched the actual operating conditions in gasoline yield, between Cases 1 and 2, with torch oil, was such as regenerator temperature, C/O ratio, and the yield slate. closed when the co-catalyst replaced the torch oil in Case 3. Case 1 or steady state is the Base Case, as shown in TABLE 2. Decant oil (bottoms) was also reduced. However, LCO yield Case 2, denoted by the torch-oil case, simulated the operatwas lower because of the high activity of the cracking of the ing conditions when the refinery was experiencing the probprimary intermediates into gasoline and light olefin products. lems when one of the interstage standpipes between the two From TABLE 3, the unit net profit decrease with the cosections of the regenerator was partially blocked. In this case, the sustained unit operation was achieved by injecting torch catalyst was $0.31 better than the case with torch oil. Again, oil and increasing catalyst addition. An empirical method was the simulation model does not take into account the costs for agreed upon to simulate the torch oil injection, and it was utilized to match the actual catalyst-addition rates and refinery operating conditions. The empirical Conv3 approach was a heuristic method to simulate lowering of catalyst activity by artiConv4 ficially increasing the sodium in the feed to match the activity. As torch oil was not a regular feature of the operation, it was Conv5 not included in the economics calculaRemaining Wall Thickness tion performed by the simulation model. Conv6 Finally, the co-catalyst, or Case 3, was a simulation where there was no Conv7 torch oil in the unit and the FCCU was running smoothly with the base catalyst and co-catalyst alone. Conv8 From the simulation output of TABLE 2, the major constraint is the heat balance management. Initially, this necessitated using torch oil to overcome the constraint. But, the torch oil also severely deactivated the FCC catalyst and required increasing the catalyst-addition rate to maintain the equilibrium Transfer the risk of unplanned downtime, loss of activity of the circulating catalyst. To maintain the equilibrium activity production or a catastrophic failure in your fired heaters. at the desired level, the refinery initially Quest Integrity’s Furnace Tube Inspection System (FTISTM) is the globally proven used increased catalyst during the torchtechnology that delivers 100% coverage of your serpentine coils. Combined with oil period. Then, when the co-catalyst our LifeQuestTM Heater software to provide fitness for-service and remaining life was introduced, conditions changed. compliant with the API-579 standard, Quest Integrity delivers a solution that helps The volume of torch oil was reduced transfer your integrity and maintenance risk into reliability. initially and finally eliminated while still s0ITTINGINTERIOROREXTERIOROFPIPE maintaining the equilibrium activity. The dense-bed regenerator in Case s#ORROSIONINTERIOROREXTERIOROFPIPE 3 is about 70°F lower than Case 2 as op s%ROSIONANDmOWASSISTEDWEAR erations were optimized to increase the s$ENTINGANDOVALITY catalyst circulation rates closer to the restricted limit. The unit ran smoothly at s"ULGINGANDSWELLING C/O that was approximately 25% higher s#OKEANDSCALEBUILD UP than Case 2. The end result during the Get the information you need to confidently co-catalyst campaign was a liquid volume make decisions on your critical assets. increase of 0.3 vol% higher than Case 2. To learn more, watch the FTIS animation At the same time, liquid volume exat the link below. pansion improved and the yield slate improved as well. The activity of the www.QuestIntegrity.com/FTIS A TEAM Industrial Services Company co-catalyst was able to generate sufficient catalytic coke to enable removing the torch oil, and the refinery was able

Transfer more than heat.

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81

Refining Developments torch oil into its economic valuation, which nonetheless, is still a real cost and valued at over $1.20/bbl. Lessons learned. As a result of the partial blockage of the interstage standpipes, the FCC unit was seriously challenged in circulating catalyst between the regenerator and the reactor. While the partial plug could only be remedied by a shutdown, the most economical option was to search for ways to keep the FCCU in operation and to take a planned shutdown when it best suited the refinery’s schedule. Surveying the field of options, the best possible solution was boosting activity with a highly selective co-catalyst capable of providing the heat to sustain the regenerator, while at the same time providing excellent product selectivity. The flexibility provided by the co-catalyst system allowed MPC Catlettsburg refinery to quickly respond to changes in operational issues. The reduction in operating cost and improved yields provided MPC well over $1/bbl in benefits. In addition, the co-catalyst positively affected the yield slate, but the greatest benefit to the refinery was that it allowed the refinery management to bring the unit under control and to take a planned shutdown at a time of their own choosing. NOTES BASF’s high-activity Converter. 2 The RCC process was jointly developed by UOP and Ashland. 3 The tables presented in this study are based on KBC Profimatics runs. 4 KBC’s FCC-SIM simulation model was used. 1

JEFFREY SEXTON is the refining technology manager for Marathon Petroleum Co., located in Findlay, Ohio. He directs the efforts of 22 process-subject-matter experts to provide technical and operational expertise and to support Marathon’s downstream organization. He previously worked for UOP in a variety of FCC assignments and has worked on over 40 different FCC units around the world. Mr. Sexton was previously the cat-cracking subject-matter expert for Marathon responsible for FCC technical and operating performance. He has authored over 25 technical papers, holds multiple patents and made several presentations at the NPRA (now AFPM) and other industry forums. Mr. Sexton is currently the chairman of the US EPA Consent Decree FCC Technical Team and PSRI Technical Advisory Committee. He holds a BS degree in chemical engineering from Rose-Hulman Institute of Technology. NIKOLAS LARSEN is a cat-cracking subject-matter expert for Marathon Petroleum Co., located in Findlay, Ohio. As a corporate technologist, he provides technical/operational expertise and support for Marathon’s eight FCC units. Mr. Larsen has also held a variety of other technical and supervisory positions within Marathon at different locations. He holds a BS degree in chemical engineering from the University of Notre Dame. JOHNNY HIGHFIELD, JR. is the operations coordinator at Marathon Petroleum Co.’s (MPC) Catlettsburg, Kentucky refinery. In this position, he coordinates plantwide operations activities including policies, procedures and training. Mr. Highfield serves as the operations sulfur recovery advisory group leader for MPC’s seven refineries. He has 17 years of experience in a variety of technical and operations positions at the Catlettsburg refinery and has one pending patent. Mr. Highfield holds a BS degree in chemical engineering from the University of Kentucky. SOLLY ISMAIL is the FCC modeling and additives technical service specialist for BASF located in Iselin, New Jersey. Before joining BASF, he worked at major South African refineries where he received numerous awards. Mr. Ismail holds an MS degree from Lehigh University and an MBA from the University of South Africa. DANIEL NEUMAN is a senior account manager for BASF located in Owings Mills, Maryland. He has considerable experience in FCC technology and earned BS and MS degrees in chemical engineering from Tufts University in Medford, Massachusetts. He is the holder of several patents, and has authored many papers for the refining catalysts industry.

LIVE WEBCAST: Wednesday, May 28, 2014 | 10 a.m. CST Achieving FCC Technical Service Excellence The Fluidized Catalytic Cracking Unit (FCCU) performance is an integral element of success for refiners. FCCU Operation needs to be optimized routinely while also being reliable. Refiners enjoy their greatest chance of meeting all targets when optimized, reliable operation is practiced, meaning: • Safety and Environmental goals more likely to be met • Operating and maintenance budgets respected, and • Maximum rate of return for the refinery achieved

Speaker:

Speaker:

ALEXIS SHACKLEFORD

CJ FARLEY

Technical Marketing Specialist BASF, Refining Catalyst

FCC Technology Consultant, Vice President of Technology Astron International, Inc

Moderator: STEPHANY ROMANOW Editor Hydrocarbon Processing

82MAY 2014 | HydrocarbonProcessing.com

BASF has a robust technical service portfolio to help our customers achieve this optimized, reliable state. Our service platform hinges upon a good working relationship with the refinery, unit data analysis, specialized BASF laboratory analyses, refinery FCCU modeling, FCCU benchmarking, and statistical analysis of FCCU operations. All of these are delivered on a timely basis to the customer so that proper action can be considered and taken. One of the most critical deliverables in this service platform is proper selection of catalysts and feedstocks to give optimized, reliable operation. In this webinar, Alexis Shackleford, Technical Marketing Specialist, and CJ Farley, FCC Technology Consultant, will present several case studies illustrating the value robust technical service partnerships bring to the refinery.

Register at: HydrocarbonProcessing.com

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TERMINALS AND STORAGE

USE INNOVATIVE SOLUTIONS TO RETURN STORAGE TANKS BACK TO SERVICE FASTER J. HAIR, The Sherwin-Williams Co., Cleveland, Ohio

High-solids epoxy linings for the petrochemical terminal and pipeline market are gathering high interest as the need to efficiently return storage tanks back to service becomes more prevalent. Some coating manufacturers are now offering tanklining products that make it possible to return tanks to service the same day or overnight. Result: Minimizing lost revenue due to downtime for terminal companies. Prior to specifying these materials, it is crucial to understand all of the considerations that affect the outcome of such projects. Each partner—the owner, painting contractor and coating manufacturer—has decisions to make in planning for a short-timeframe project. Any deviation from that plan—such as a schedule-conflict, safety or equipment issue—can have an immediate impact on the project’s progress. Gaps can essen-

tially render a fast return-to-service (RTS) coating to nothing more than a standard RTS coating. Under present market conditions, terminal operators and tank owners must balance issues with regard to contango crude market conditions, congested operations schedules, capital project schedules and unforeseen repairs. In certain parts of the world, extremes in seasonal weather patterns are also factors in specifying the right tank lining for a project. Schedules. Most manufacturers can supply linings with standard 5- to 7-day cure times that fit the need for a typical onschedule tank project. However, the window for curing, in many situations, is becoming tighter. Fortunately, advances in tank-lining chemistry have allowed manufacturers to produce

FIG. 1. Aboveground storage tanks must be serviced to maintain the reliability of the tank and inhibit corrosion; all efforts support minimizing leak incidents. A 250,000-bbl floating-roof crude oil storage tank in Cushing, Oklahoma. Source: Sherwin-Williams Protective and Marine Coatings. HYDROCARBON PROCESSING | MAY 2014 | TERMINALS AND STORAGE

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TERMINALS AND STORAGE

materials that will cure to service in 8 to 24 hours depending on temperature and humidity. Newer tank-lining materials can also handle a broader spectrum of various cargos within the terminal and pipeline market segment. Commodities within this market segment include ambient temperature crude oil, gasoline, jet fuel, diesel fuel, kerosine and ethanol. Tank-lining materials that can handle immersion in most of these commodities are sometimes referred to as universal or “swing” service tank linings, as defined by API 652—Lining of Aboveground Petroleum Storage Bottoms. Before fast-RTS linings are selected for a project, several considerations should be evaluated to ensure that the investment in these materials will provide the expected results. Owner considerations. Operations schedules are the predominant factor for owners when considering fast-RTS materials. Due to shipping schedules and commitments, storage tanks may be needed back in service immediately to meet client demands. In addition, there can be economic implications, such as capitalizing on contango crude market pricing, where higher profits accrue if oil is sold later rather than sooner and available storage tanks become high-priority assets. Owners must understand how the tank design can impact project costs in these situations, especially in cold temperatures. For example, a cone-roof tank without an internal floating roof is more costly to heat in the winter. In such a case, when outside temperatures are approaching freezing or below, provisions must be made for extensive high-performance heat and dehumidification to complete projects. The risks without this include formation of invisible ice on the tank substrate, and difficulty maintaining properly operating abrasive blasting and spray application equipment. Due to the expense of heat and dehumidification, owners are often receptive to the idea of fast-RTS tank-lining materials. When comparing costs, they will be far more concerned with the cost of heating a tank than they are with the price of the coating. There are high-solids products for crude oil and ethanol storage that can be holiday tested in approximately four hours and returned to immersion service in eight hours at 77°F. They can be applied at temperatures as low as 35°F, and, in rehabilitation projects, in a single coat up to 50 mil of dry-film thickness (DFT). This is a game-changer option for owners used to traditional standard cure linings that can take weeks to put tanks back into service. This also has an impact on the cost of onsite inspectors, who will be able to oversee repairs and final inspections in a much shorter timeframe. Another thing to keep in mind is the condition of the tank bottoms, i.e., whether the substrates are heavily pitted or new. Heavily pitted substrates will require an additional level of detail when applying lining material, to properly fill all pitted areas prior to applying the finish coat. This is where engaging knowledgeable contractors and coating manufacturers comes into play. Painting contractor considerations. Contractors usually are

most concerned with the time of year when the project will be carried out, and with the properties of the tank linings that will work best under those conditions. During hot weather, coatings with shorter pot life can present challenges. If the substrate is pitted, it will be necessary to T–86

TERMINALS AND STORAGE | MAY 2014 | HydrocarbonProcessing.com

backroll or squeegee the material to properly fill all pitted areas. The hotter the temperature, the shorter the pot life of the coating materials, and the less time available to work these materials into pitted substrates. Cold weather will require the heating of the tank and observing minimum temperature requirements throughout the project. Such actions lead to additional equipment, man-hours and safety precautions. For pitted tank bottoms, some suitable materials are selfpriming. Most contractors prefer to use one product if possible. This eliminates the need to clean out their plural-component equipment rigs prior to applying an additional coat, as well as reducing total project duration. Plural-component equipment is becoming more common in contractor service offerings, but it requires an onsite foreman and crew trained in the distinctive application techniques involved for each coating product. When trained, contractor field employees often prefer to apply these materials, if given the option. Coating manufacturer considerations. Working directly with

a coating manufacturer to establish onsite technical support for a project is always recommended, especially because having immediate assistance with unforeseen equipment and application issues can prevent lengthy delays in work progress. The coating technical advisor’s interest extends to these questions: • Are qualified contractors in place for plural-component equipment applications? • What is the condition of the tank bottom (pitted vs. non-pitted)? • Are the lining materials properly specified, especially for expected weather conditions and for the tank commodity? For example, in hot weather (> 90°F), the substantially shorter pot life of fast-RTS materials can be a risk factor with heavily pitted tank bottoms. Their use can result in pitted substrates/holes being bridged, resulting in a tank lining with extensive holidays.1 In this situation, some standard lining materials may be the better choice, as they will cure quickly enough while also providing the necessary longer pot life and easier workability for the pitted substrates. Trends. Within the oil and gas market segment, it is vitally

important to stay up to speed on the latest trends in protective coatings that can extend asset life as well as offer other attributes. Terminal and pipeline owners should be aware that updating their specifications with fast-RTS materials offers significant economic benefits, provided that other considerations have been weighed. 1

NOTES An important evaluation of bottom linings after application to aboveground storage tanks (AST) is to conduct discontinuity (holiday) testing per NACE RPO188. Linings are principally applied to ASTs to prevent internal corrosion that may be severe. Therefore, any holidays must be detected and repaired prior to the newly lined tank being returned to service.

JUSTIN HAIR is an oil and gas business development manager with The SherwinWilliams Co. Prior to joining Sherwin-Williams in 2007, he held managerial positions at HMT, Inc. and Specialized Industrial Service, Inc. Mr. Hair is NACE CIP Level 3 and SSPC C-11 certified. He holds a BS degree in business administration from Missouri Southern State University, and also achieved the Pipeline Integrity Corrosion Assessment certification from the University of Oklahoma.

JUNE

2014 2014 KEYNOTE SPEAKER ADAM STELTZNER Lead Landing Engineer of NASA’s Mars Science Laboratory Curiosity Rover Project As chief engineer and development manager for the Mars Science Laboratory focused on the entry, descent and landing phase, Adam Steltzner’s job was to ensure that the NASA Mars Curiosity rover landed safely. His group spent nearly 10 years designing, building, testing, and tweaking the process that would slow the intricately designed, 2,000-pound rover from a speed of nearly 15,000 miles per hour and deliver it safely to the planet’s surface. During his presentation, he will share his enthusiasm for science and planetary exploration and discuss how audacious goals, unbridled thinking and breakthrough innovation can make the impossible possible. | Image Courtesy of NASA/JPL-Caltech

10 conference presentations will be conducted in Spanish

Develop your technical expertise in terminal operations by attending focused presentations and workshops. CO NF ERENCE S ESS IO NS INCLUD E:

Arc Flash Hazard Prevention and Compliance with the 2012 NFPA 70E Standards for Electrical Safety Tools and Techniques for Minimizing Mistakes and Improving Compliance in Terminal Operations New Oil Distribution Patterns and Their Impact on Terminals Market Trends in Recent Terminal Sales and Expansion Projects Considerations for Implementing and Enforcing Document Retention Policies Emergency Planning, Response & Restoration: What Every Terminal Should Know

INTERNATIONAL OPERATING CONFERENCE & TRADE SHOW

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For more information, contact: Lee Nichols, Director, Data Division, at [email protected] or +1 (713) 525-4626

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Published since 1922, Hydrocarbon Processing provides operational and technical information to improve plant reliability, profitability, safety and end-product quality. The editors of Hydrocarbon Processing bring you first-hand knowledge on the latest advances in technologies and technical articles to help you do your job more effectively.

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SMART SOLUTIONS ACROSS THE PROCESS PLANT LIFE CYCLE With an expansive range of technology, EPC capabilities, storage solutions and aftermarket services, CB&I is uniquely positioned to support our customers in the hydrocarbon processing industry. As a trusted partner, we work strategically with you to ensure your venture’s success at every level. We understand your business and the challenges you face. Our business model, range of capabilities and flexibility allow us to provide value-added services across the entire life cycle of a project — delivering consistent results anywhere in the world. Complete. Smart. Flexible. Global. With a 125-year track record of innovation and success. Contact us to discuss how to maximize the value of your next capital project. PROCESS PLANNING AND DEVELOPMENT LICENSED TECHNOLOGY AND CATALYSTS FULL-SCOPE EPFC SERVICES AMBIENT AND LOW-TEMP STORAGE SOLUTIONS AFTERMARKET SERVICES

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CB&I

CB&I PROVIDES SMART SOLUTIONS IN TANK CONSTRUCTION AROUND THE WORLD CB&I is the most complete energy infrastructure focused company in the world and a major provider of government services. Drawing upon 125 years of experience and the expertise of approximately 55,000 employees, CB&I provides reliable solutions while maintaining a relentless focus on safety and an uncompromising standard of quality. CB&I combines proven process technology with global capabilities in engineering, procurement and construction to deliver comprehensive solutions to customers in the energy and natural resource industries. With premier process technology, proven EPC expertise, and unrivaled storage tank experience, CB&I executes projects from concept to completion. With over 46,000 tanks built in more than 100 countries, CB&I has accumulated more storage design and construction experience than any other organization in the world. In addition to being a leader in engineering, procurement, fabrication and construction of storage tanks, we have also designed and built more than 100 storage terminals. We have the capability to design and install pipelines for these facilities, as well as other ancillary equipment. Many customers draw upon this knowledge and extensive construction experience early in a project’s development, enabling us to provide project-specific solutions that deliver maximum long-term value, lower up-front costs, and shorter schedules. Safety is a core value at CB&I, and we are proud to have one of the best safety records in the industry. Throughout our organization, every

employee worldwide is committed to safe work practices. Our award winning safety program promotes a culture of involvement and dedication with a goal of zero incidents for everyone involved in our projects.

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Explore the Latest Trends and Technology at GasPro North America

September 10–11, 2014 Houston, Texas

Natural Gas is changing the energy landscape in North America and throughout the world. Hydrocarbon Processing and Gas Processing are pleased to present the inaugural GasPro North America, which will focus on natural gas technologies and markets in North America. It is the first event of its kind to be held annually in the United States. The 2014 conference program will focus on gas supply, procurement, purchasing, transportation, trading, distribution, operations, safety and the environment, regulatory affairs, technology development, business analysis and more. Specific topics to be discussed include: NGL/LNG, Dehydration, Stranded Gas/Sour Gas, Compressors/Equipment and Separation.

Join us and Hear from Executives at: • Qatar Petroleum

• Aspen Technology, Inc

• Valerus

• Johnson Matthey

• URS Corporation

• ABU QIR Fertilizers Company

• Linde Process Plants, Inc

• Flowserve Corporation

• S-Con, Inc

• Clariant Corporation

• SpectraSensors, Inc

• Hytech

• Sime

• Michell Instruments Inc

• National R-D institute for Cryogenics and Isotopic Technologies

• and more

Three Ways to Participate: 1. Register Early & Save: Take advantage of early bird rates at GasProcessingConference.com.

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INDUSTRY LEADER IN CELLULAR GLASS TECHNOLOGY Since 1937, Pittsburgh Corning FOAMGLAS® Insulation has been the leader in cellular glass technology. FOAMGLAS® insulation is a lightweight, rigid material used on a wide variety of industrial and commercial applications with outstanding long-term results. Its all-glass closed-cell structure provides physical properties ideal for piping and equipment above and below ground, indoors or out, at operating temperatures from –450°F to +900°F. FOAMGLAS® Insulation has 0.00 permeability rating, making it resistant to water in liquid or vapor form. The material does not contain HCFC, CFC or toxic blowing agents and does not contain crystalline silica. FOAMGLAS® insulation is non-combustible and will not wick flammable liquids and has superior compressive strength. FOAMGLAS® insulation also has long-term dimensional stability as glass does not shrink or swell. It remains stable; therefore there is no warping or buckling. This provides minimum stress to the insulation system, joints and coverings at extreme temperature changes. With its FOAMGLAS® Insulation, Pittsburgh Corning has earned a reputation for developing high performance, premium quality, environmentally sustainable insulation materials and systems.

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WE’RE IN IT FOR THE LONG RUN. For over 50 years, FOAMGLAS ® insulation has been used to insulate countless lineal feet of hydrocarbon processing and LNG pipe around the world. Pittsburgh Corning’s original cellular glass technology provides consistent long-term thermal performance and superior compressive strength. These unique qualities make FOAMGLAS® insulation the preferred choice of engineers worldwide.

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Creating Client VALUE is our Business

Safety M. SAWYER, Apex Safety Consultants, Houston, Texas

Minimize false assurances in hazard analyses Hazard analysis is a powerful and highly effective tool for identifying and evaluating potential hazards and control measures (FIG. 1). Its versatility provides an economical and insightful assessment of potential hazards at multiple stages in the lifespan of a project. When used correctly, it is also an effective method of identifying potential job hazards involving maintenance and operational tasks. Yet, caution should be exercised. It may not provide the level of risk reduction or control perceived or anticipated. Aspects that are uncharacteristic to most hazard analyses, such as uncertainty assessments and inclusion of guide terms outside of the normal process parameters, should be considered for supplemental purposes. Although atypical of hazard analyses, these concepts can enhance the quality of the analysis and increase confidence in the results. There are several hazard analysis techniques that have been developed and practiced over the past 30-plus years, and each has its benefits as well as limitations. The Center for Chemical Process Safety (CCPS) acknowledged hazard analysis as having a number of theoretical and practical limitations in its hazard evaluation procedures.1 The issue of hazard analysis having limitations is not a new concept, as noted by CCPS’s 1992 guide document. Trevor Kletz often spoke of organizations having no memory.2 To borrow from Dr. Kletz’s insight, it may also be said that hazard analyses have no memory: similar omissions, misstatements, errors and oversights can be found in most analyses, especially those conducted within the same organization. In 1992, the US Occupational Safety and Health Administration (OSHA) adopted a chemical process safety management standard as mandated by the Clean Air Act Amendments (CAAA) of 1990.

Along with other requirements, the standard included a provision for workplace hazard analysis. More specifically, Section 304 of the CAAA requires employers to “perform a workplace hazard assessment, including, as appropriate, identification of potential sources of accidental releases, an identification of any previous release within the facility, which had a likely potential for catastrophic consequences in the workplace, estimation of workplace effects of a range of releases, estimation of the health and safety effects of such range on employees.”3 The OSHA requirement for hazard analysis is much more explicit; it says that “the process hazard analysis shall be appropriate to the complexity of the process and shall identify, evaluate and control hazards involved in the process.”4 Although explicit, OSHA’s hazard analysis requirement encompasses an extensive effort in order to fully comply with its intent. Process consideration. First, the analy-

sis methodology must be appropriately matched with the complexity of the process under study. This initial step is where HAZOP study What if/checklist FMEA/FMECA Fault-tree analysis Combination, etc.

Determine appropriate equivalent methodology

many analysis techniques and processes are inappropriately matched and the quality of the analysis suffers. One example is “what-if/checklist” type formats that are used to analyze highly hazardous and complex processes. Processes that should require special consideration when selecting an analysis methodology include: • Continuous vs. batch • Maintenance intensive • Highly congested units • Heavily task-oriented operations • Sparsely staffed units • Processes with unique siting issues. When selecting the analysis methodology, remember that the use of multiple techniques may be beneficial in both the analysis time and quality of the study. It is highly recommended that the final methodology technique selection(s) be challenged. Then a justification in the form of a detailed technical basis should be documented and approved by the corporate safety representative prior to study commencement. The primary objective and a detailed scope outlining study limitations and assumptions should also be included in the technical basis. This will be advantageous in assessing the uncertainty associated with the analysis. Detailed technical basis Safety review

Identify Evaluate Analyze hazards of the process

Control

Uncertainty assessment Hazard analysis report

Disseminate Results of hazard analysis to all affected workers (employees and contractors)

FIG. 1. Inductive hazard analysis. Hydrocarbon Processing | MAY 201495

Safety Analysts typically associate uncertainty with probabilistic risk assessments. An uncertainty evaluation should be included in the hazard analysis report to provide an effect estimation regarding data and technique variations on overall risk. Identify and control. The second part of

the hazard analysis requirement is the most challenging: identify, evaluate and control hazards involved in the process. Even the

96

most seasoned hazard analysis facilitator will admit that the selection of the appropriate technique is important, but that it’s only the beginning of an arduous process. Step 1 is to identify potential hazards involved in the process, system or task under study. Depending upon the analysis methodology, most studies readily identify the basic process or workplace hazards. For example, during a hazard and operability study (HAZOP), most basic pro-

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cess parameter issues are identified, such as no flow, high temperature or low pressure. This step’s critical aspect is conducting a thorough identification of potential hazards. Typically, hazard analysis studies neglect to identify potential hazards like deferred and/or repetitive maintenance; faults detected during inspection and testing; and deferred inspections. TABLE 1 provides a limited list of some potential hazards that may be overlooked during the hazard analysis. Hazard analysis teams can use this list (TABLE 1) as a starting point to initiate brainstorming of additional issues that should be included in their analysis. After a hazard is identified, the next step is to evaluate the hazard. A pre-determined risk-ranking matrix with probability and severity definitions is typically used to assess risk, both before and after safeguards. Just as with the initial hazard identification, errors and omissions at this stage can also affect the study’s quality. The most common error found with predetermined risk-ranking matrixes is that organizations neglect to update the matrix definitions based on experienced incidents and near misses. This allows the matrix to quickly become stagnant and not representative of the organization’s actual operational risk. Some of the more common deficiencies discovered during hazard analyses evaluation are: • Incorrect scenarios such as assuming that unit/equipment is operational when it is out of service • Failure to identify changed operating parameters • Failure to identify re-rating of vessels, equipment • Including out-of-service safety devices/systems as safeguards • Over reliance on operator intervention to mitigate emergencies • Failure to thoroughly assess maintenance-intensive tasks • Include inspections and tests as safeguards when inspections/ tests had been deferred • Failure to assess issues surrounding contractor/operational staff ratios • Under-estimation of hazard occurrence (probability) • Under-estimation of hazard severity • Limited guide words/terms • Incomplete hazard scenarios

Safety • Confusion between hazard and consequence • Confusion between safeguard and safety instrumented system • Failure to understand the process/ system/tasks involved The listed items may be attributed to factors like facilitator inexperience, conducting the analysis too fast and inappropriate skill and knowledge base of team members. The job safety analysis/job hazard analysis ( JSA/JHA) is a widely used variation of hazard analysis that is common for operational and maintenance tasks. The most common and critical mistake with JSA/JHA is its reliance on a predetermined checklist of generalized hazards, which impedes the typical hazard analysis brainstorming. This analysis is extremely critical to ensuring personnel safety while conducting operational and maintenance tasks. Yet, it is often perceived as just a paperwork exercise with little to no actual contemplation of potential hazards relevant to the task or maintenance activity to be undertaken. Investigation into numerous incidents involving completed JSA/JHAs revealed gaps such as the occurring hazard were known but not identified in the analysis or the hazard control measure was not appropriate. For example, in an

incident resulting in a fatality during a tank-cleaning task, the JSA listed the tank contents incorrectly. In another incident, the JSA neglected to identify a pipeline’s flammable residue prior to conducting hot work. In another incident, the JSA neglected to identify changes to the task scope. After incidents where a JSA/JHA was conducted and the affected workers were interviewed, most acknowledged little to no actual awareness or understanding of the process hazards involved in the task. This remained true for hazards identified on the JSA/JHA and for those not identified. Investigations into work incidents often revealed that, while companies relied upon the JSA/JHA to provide workers with an understanding of the risk, most analyses equated to nothing more than a predetermined checklist of sparsely related work hazards. Other considerations. There are sev-

eral other inductive hazard analysis variations not discussed in this article. All have similar strengths and limitations. Incorporation of the issues noted above will begin to bridge the gap and increase confidence in hazard analysis studies. However, there are also other measures that can be implemented into a hazard analysis program to increase its effectiveness.

TABLE 1. Examples of potential hazards

BORSIG

SERVICES for Pressure Vessels and Heat Exchangers Power Plants incl. Project Engineering Ball Valves and Valves

Overdue or deferred process safety management (PSM) audit findings and action items Operating excursions (operations outside of safe upper and lower limits)

Plants and Pipes

Delays in completing management of change (MOC) Systems operating without defined operating parameters Deferred preventive maintenance activities

Compressors, Fans and Blowers

Overdue/deferred inspections (vessels, relief valves, instrumentation) Bypassed/out-of-service critical instruments, alarms

Membrane Technology

Blocked relief valves Frequency of leaks Frequency of rotating equipment failures Overdue operating procedure reviews

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Incomplete or out-of-date process safety information Isolation philosophy for emergencies Out-of-service equipment Incomplete or inadequate overpressure design basis

BORSIG GmbH Phone: ++49 (30) 4301-01 Fax: ++49 (30) 4301-2236 E-mail: [email protected]

Operating-envelope changes Reduction of operational and/or maintenance staff

Egellsstrasse 21 D-13507 Berlin/Germany

Increases in operational and/or maintenance tasks per shift Equipment failures incorrectly documented as routine maintenance Select 174 at www.HydrocarbonProcessing.com/RS

Safety Additional measures that have proven successful in elevating hazard analysis results include: 1. Development of an experience-based evergreen hazard database to supplement the study. One example is a hazard database of anhydrous ammonia refrigeration system data gathered from operational experience, maintenance work orders, refrigeration suppliers and similar systems.5

2. In all hazard analyses, the skill and composition of the team are critical factors in a successful study. Team members should be carefully selected based upon skill, experience level, process/system under study and formal hazard analysis training. 3. The hazard analysis team usually comprises 5 to 10 individuals representing different disciplines. The team represents only a fraction of

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the workers at a facility. Unless the facility develops and implements a hazard analysis dissemination plan, the hazard analysis information developed in the study will likely never get to the workers who need the information. Without disseminating the hazard information to all affected workers and ensuring their understanding of the hazards and the appropriate safeguards, the effort spent on the hazard analysis is futile. Although hazard analysis is a powerful analytical tool, there are numerous pathways to introduce errors and omissions that can degrade the quality of the hazard analysis. Hazard analysis is a critical part of any safety management program and organizations should carefully consider how to obtain the most benefit from the analysis. A culture that considers hazard analysis as a paperwork exercise necessary only to avoid OSHA citations will fail to achieve any real risk-reduction measures. Be successful. No single study or meth-

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MIKE SAWYER, PE, CSP, is a consulting engineer at Apex Safety Consultants in Houston, Texas. He has led and participated on various safety engineering projects over the past 31 years. In addition, he has facilitated numerous hazard and risk assessment studies throughout the world.

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LITERATURE CITED Center for Chemical Process Safety, Guidelines for Hazard Evaluation Procedures, 2nd Edition, American Institute of Chemical Engineers, New York, 1992. 2 Kletz, T., Lessons From Disaster, How Organizations Have No Memory and Accidents Recur, Institute of Chemical Engineers, Warwickshire, UK, 1993. 3 CAA Section 304, 42 U.S.C. 7604. 4 29 CFR 1910.119(e)(1). 5 Bruen, L. and M. Sawyer, “Refrigeration System exHAZOP,” MKO Process Safety Center Symposium, 2010. 1

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odology is guaranteed to capture all potential hazards. However, the greatest probability of success can be orchestrated by using an adequately diversified and multi-disciplined team; sufficient prestudy research of relevant process issues; a pre-study walk-through of the unit(s); and an experienced facilitator. Conducting a hazard analysis should be a company-wide undertaking with continued emphasis on the quality of the study to ensure that the analysis is appropriate to the complexity of the process; that hazards are identified, evaluated and controlled; and that all affected workers have been informed about the hazards and control measures relevant to their jobs.

Select 175 at www.HydrocarbonProcessing.com/RS 4/15/2014 4:17:17 PM

Environment D. CONNAUGHTON, Parker Hannifin, Haverhill, Massachusetts

What every refiner should know about nitrogen generation and delivery Nitrogen (N2 ) is often used in refineries to blanket tanks and reduce the chance of fire or explosion. This gas is the second highest volume chemical produced in the world by pound, just behind sulfuric acid and ahead of ethylene. Thus, N2 accounts for a considerable amount of energy used in the chemical/petrochemical industry. New low-energy, on-demand N2 production methods are becoming more common; all are in an effort to reduce the industry’s carbon footprint. Most N2 is produced by the cryogenic fractional distillation of liquefied air in large commercial air separation plants (FIG. 1). Cryogenic distillation accounts for about 70% of total N2 production. The commercial method for air separation can be attributed to the German scientist Carl von Linde, who developed the process over 120 years ago. The process. N2 production involves withdrawing air from the atmosphere using a compressor. The compressed air is then pretreated to remove oil vapor, carbon dioxide (CO2 ) and water (H2 O) vapor. The removal of CO2 and H2 O vapor is crucial, as these compounds can freeze and plug the cryogenic equipment. The treated air is then compressed, passed through a heat exchanger, expanded through a valve and returned to the compressor inlet. On each compression expansion cycle, the temperature drops. This process is called Joule-Thomson expansion. The liquefied air is then separated into N2 , oxygen (O2 ) and argon by fractional distillation. The purified N2 is pressurized and stored in bottles as a gas or directly stored in dewars as a liquid. These vessels are transported to and from the end user’s plant. Cryogenic plants are also built on or near an end user’s site, with the N2 being delivered via pipeline. Although this method provides a low-cost reliable supply for large industrial users, it is not appropriate for smaller-volume users because of the high capital and power costs. Generating N2 using the fractional distillation of air is energy-intensive because the process entails condensing ambient air into liquid air by cyclic cooling and compression of the gas. Additionally, after N2 gas is separated from the air, more energy is needed to further purify the gas and fill the appropriate container. Further, fractional distillation of air is normally performed continuously on a large scale, resulting in hundreds or thousands of tons of greenhouse gases (GHG) created per day. N2 transport via delivery tankers from a fractional distillation facility to and from an end user’s plant consumes substantial energy and significantly contributes to the amount of CO2

in the atmosphere. Obviously, the amount of energy required to transport the N2 depends on the distance between the facility and the end user, but trucking N2 clearly has a negative environmental impact. For example, a tractor trailer traveling around 100,000 miles per year generates about 360,000 lbs of CO2 during that time. On-demand generation. Recently, alternative methods for on-demand N2 generation have been put into practice. They include pressure-swing adsorption (PSA) and membrane system technologies. The choice of generator largely depends on the purity of N2 needed. Typically, applications such as fire prevention require N2 at 95% to 98% purity and can use membrane generators to meet this goal. Other applications—like blanketing O-sensitive compounds, specialty chemicals and pharmaceutical processing—need a high-purity stream and require the use of PSA generators. PSA technology separates N2 from O2 based on the preferential adsorption and desorption of O2 and other contaminants on a carbon molecular sieve (CMS). The system passes pressurized air through a vessel packed with CMS that adsorbs O2 and allows the N2 to pass through the vessel. Once the CMS is saturated with O2 , the vessel pressure is lowered, which causes contaminants such as O2 , CO2 and H2 O vapor to be released to the atmosphere. CMS has a high degree of microporosity, making it highly suitable for O2 adsorption. To obtain a continuHeat exchanger-incoming air cooled by product gases

Filter

Nitrogen

Cooling

Air

Other gases

Compressor Zeolite molecule sieve

Expansion turbine

Oxygen Cleaning and cooling

Liquefying

Distillation

FIG. 1. Shown here as a single-stage process, the compression and expansion that occur in fractional distillation are actually repeated over and over again. Source: University of York, UK. Hydrocarbon Processing | MAY 201499

Environment ous flow of N2 and maximize system utility, the system uses two vessels connected in parallel. One vessel provides N2 while the other vessel is being regenerated. Generating N2 using a hollow-fiber membrane system involves using an air compressor that withdraws air from the atmosphere and passes it through a high-efficiency coalescing filter to remove H2 O vapor and particulates. The clean, dry air then passes through a carbon scrubber to remove any hydrocar-

bon vapors before entering the system’s separation module. The compressed air travels through the hollow fibers in the membrane (FIG. 2), separating out any remaining O2 and H2 O vapor. The N2 -enriched gas stream passes through another filter to ensure the delivery of pure, sterile N2 . Energy usage. PSA and membrane systems require only enough energy to power the compressor that supplies air to the system and, in the case of PSA systems, power to operate a timer and valving. By eliminating the need for an outside facility to generate N2 , store it and truck it to a user’s site, the entire carbon footprint required to create and supply N2 to a plant is reduced. Gas industry sources indicate that an air-separation plant uses 1,976 kJ of electricity/kg of N2 at 99.9% purities. On-demand N2 generation helps reduce GHG generation. Compared to thirdparty supplied bulk N2 , generating 99.9% N2 in-house on-demand with a PSA system uses 28% less energy. At a purity of 98%, the energy required for in-house N2 consumes 62% less energy, and therefore, produces less GHG. Sustainable and efficient. Generating N2 on-demand is a sus-

tainable and energy-efficient approach. It uses significantly less energy than fractional distillation. FIG. 2. Air passes through the hollow fibers inside the membrane module to separate the O2 and any remaining H2O vapor from the N2-enriched gas stream.

DAVID CONNAUGHTON is an expert in nitrogen generators. He holds a BS degree in chemistry and an MS degree in chemical engineering from Tufts University. Mr. Connaughton’s 30-year career spans roles in product development, technical support, product sales and marketing.

LIVE WEBCAST: JUNE 17, 2014 | 10 a.m. CST Do’s and Don’ts of Pressure Design in Piping Codes SPEAKER:

SPEAKER:

Josh Gilad

Stuart Watson

Mechanical Instructor/ Consultant

Discipline Manager, Mechanical Engineering Network

John M. Campbell | PetroSkills

John M. Campbell | PetroSkills

In this webinar we take multiple case scenarios to compare the mechanical design for wall thickness across the industry major piping codes ASME B31.3, B31.4 and B31.8. In this way we develop a stronger understanding of allowable stresses, installation environment, corrosion allowances and where manufacturing tolerances affect the minimum wall thickness. Case studies are based on the same pressure, temperature and nominal diameter, but considering conventional Grade B SMLS vs ERW and materials to high yield materials.

Register at: HydrocarbonProcessing.com MODERATOR:

Adrienne Blume Managing Editor Hydrocarbon Processing

100MAY 2014 | HydrocarbonProcessing.com

HELEN MECHE, ASSOCIATE EDITOR [email protected]

Events

MAY American Chemistry Council (ACC) Responsible Care Conference & Exhibition, May 4–7, InterContinental Hotel Miami, Miami, Fla. P: +1 (202) 249-6121 [email protected] www.americanchemistry.com International Society of Automation (ISA) 59th Annual Analysis Division Symposium, May 4–8, Crown Plaza, Baton Rouge, La. P: +1 (919) 549-8411 info@isa,org www.isa.org Offshore Technology Conference (OTC), May 5–8, Reliant Center, Houston, Texas P. +1 (972) 952-9494 F. +1 (713) 779-4216 [email protected] www.otcnet.org/2014 Institution of Chemical Engineers (IChemE), Hazards 24, May 7–9, Edinburgh International Conference Centre, Edinburgh, UK P: +44 (0) 1788 578214 [email protected] www.icheme.org Abu Dhabi International Downstream Exhibition & Conference 2014, May 11–13, Abu Dhabi, UAE P: +971 4 435 6101 maxwell.thompson@ clarioneventsme.com www.wraconferences.com Institution of Mechanical Engineers (iMechE), 11th International Conference on Turbochargers and Turbocharging, May 13–14, British Museum, London, UK P: +44 020 7973 1297 [email protected] www.imeche.org International School of Hydrocarbon Measurement (ISHM), 2014 School and Exhibition, May 13–15, Cox Communications Center, Oklahoma City, Okla. P: +1 (405) 325-6034 [email protected] www.ishm.info

AFPM National Occupational and Process Safety Conference and Exhibition, May 14–15, Grand Hyatt, San Antonio, Texas (See box for contact information)

10th World LNG Series: Americas Summit, Jun. 2–5, San Antonio, Texas P: +44 20 7978 0061 [email protected] lngamericas.cwclng.com

dmg events, 3rd Annual Asia Pacific Small and Mid Scale LNG Forum, May 14–16, Pan Pacific Hotel, Singapore, P: + 44 (0) 203 6152 850 [email protected] www.apaclng.com

World Refining Association (WRA) Global Petrochemicals Conference, Jun. 3–5, Berlin, Germany P: +44 (0) 207 384 8000 F: +44 (0) 207 384 8007 marketing@theenergyexchange. co.uk, www.wraconferences.com

ERTC Energy Efficiency Conference, May 15, Brussels, Belgium P: +44 (0) 207 484 9700 [email protected] events.gtforum.com/ energy-efficiency American Petroleum Institute (API) Spring Refining and Equipment Standards Meeting, May 19–22, Buena Vista Palace Hotel, Orlando, Fla. P: 1+ (202) 682-8000 [email protected] www.api.org 14th World XTL Summit, May 19–21, Royal Garden Hotel, London, UK P: +44 20 7978 0029 [email protected] www.cwcxtl.com AFPM Reliability and Maintenance Conference and Exhibition, May 20–23, Convention Center, San Antonio, Texas (See box for contact information)

JUNE International Liquid Terminal Association’s (ILTA’S) 34th Annual International Operating Conference and Trade Show, Jun. 2–4, Hilton Americas–Houston and George R. Brown Convention Center, Houston, Texas P: +1 (703)875–2011 [email protected], www.ilta.org ACC Annual Meeting, Jun. 2–4, The Broadmoor, Colorado Springs, Colo. P: +1 (202) 249-6121 [email protected] www.americanchemistry.com

JULY

American Society of Mechanical Engineers (ASME) Annual Meeting, Jun. 6–11, Portland, Oreg. P: +1 (973) 882-1170 [email protected] www.asmeconferences.org American Society of Safety Engineers (ASSE) Safety 2014 Professional Development Conference & Exposition, Jun. 8–11, Orange County Convention Center, West Building, Orlando, Fla. P: + 1 847-699-2929 [email protected] www.safety2014.org Global Petroleum Show, Jun. 10–12, Stampede Park, Calgary, Alta., Canada P: +1 (403) 209-3555 F: +1 (403) 245-8649 [email protected] www.globalpetroleumshow.com dmg events, Global Energy Career Expo Calgary, Jun. 11–12, Calgary Telus Convention Center, Calgary, Alta., Canada P: +1 (403) 209 3551 [email protected] globalenergycareerexpo.com ASME Turbo Expo, Jun. 16–20, CCD Congress Center, Düsseldorf, Germany P: +1 (973) 882-1170 [email protected] www.asmeconferences.org NRC/ASME Pump and Valve Symposium, Jun. 22–27, Bethesda North Marriott Hotel and Conference Center, North Bethesda, Md. P: +1 (973) 882-1170 [email protected] www.asmeconferences.org

Gulf Publishing Company Events, Hydrocarbon Processing’s International Refining and Petrochemical Conference (IRPC), Jun. 24–26, Verona, Italy www.HPIRPC.com (See box for contact information)

Gulf Publishing Company Events, GTL Technology Forum, Jul. 30–31, Norris Conference Centers– CityCentre, Houston, Texas www.GTLTechForum.com (See box for contact information)

AUGUST AFPM Cat Cracker Seminar, Aug. 19–20, Royal Sonesta Houston, Houston, Texas (See box for contact information) National Association of Corrosion Engineers (NACE), Central Area Conference, Aug. 25–27, Renaissance Tulsa Hotel and Convention Center, Tulsa, Okla. P: +1 281-228-6223, or +1 800-797-6223 F: +1 281-228-6300 [email protected] www.nace.org/events China International Petrochemical Technology and Equipment Exhibition (cippe), Aug. 26–28, Shanghai New International Expo Center, Shanghai, China P: +86-10-58236555/58236588 F: +86-10-58236567 [email protected] sh.cippe.com.cn/2014/en/ Hydrocarbon Processing/ Gulf Publishing Company Events P: + 1 (713) 529-4301 F: + 1 (713) 520-4433 [email protected] [email protected] American Fuel and Petrochemical Manufacturers (AFPM) P: +1 (202) 457-0480 F: +1 (202) 457-0486 [email protected] www.afpm.org/Conferences

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