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MAY 2016 | HydrocarbonProcessing.com

MAINTENANCE AND RELIABILITY

Prevent equipment failures with improved asset management and lubrication maintainability

PROCESS ENGINEERING AND OPTIMIZATION Produce bio-gasoil via catalytic coprocessing of bio-oil and diesel in a conventional hydrotreater

ENVIRONMENT AND SAFETY Potential impacts on process safety from lifting of US crude export ban

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Select 91 at www.HydrocarbonProcessing.com/RS

MAY 2016 | Volume 95 Number 5 HydrocarbonProcessing.com

12

T-79

38 SPECIAL REPORT: MAINTENANCE AND RELIABILITY 39 Take steps to achieve lubrication maintainability







12

Business Trends



23

Industry Metrics



25

Global Project Data



87 Innovations



M. Barnes

43 Apply a short-term, high-temperature carbon steel solution to piping systems



M. Chowdry and V. Tiwari

47 Failure prevention—The ultimate asset management strategy



B. Snider

PROCESS ENGINEERING AND OPTIMIZATION 53 Small-scale coal-to-chemicals can revitalize India’s petrochemicals industry, economy—Part 2

M. Marve, S. Sakthivel and P. V. Paluskar

59 Catalytic coprocessing of used cooking oil with straight-run gasoil in a hydrotreating pilot plant

H. de Paz Carmona, A. Brito Alayón, M. Romero Vázquez, J. Frontela Delgado and J. J. Macías Hernández

HEAT TRANSFER 67 Use computational fluid dynamic analysis to revamp fired heaters

process safety management K. Molly

TERMINALS AND STORAGE—SUPPLEMENT T-80 Optimize tank farm operations, safety and profitability

4

D. Rueda-Rojas

Cover Image: The Epsilon 3XLE benchtop energy-dispersive X-ray fluorescence spectrometer enables ultra-light element analysis for the petrochemical industry.

Industry Perspectives

90 Marketplace

92



93 Events

Advertiser Index

94 People

COLUMNS 9 President’s Letter

A new day for you, a new day for us





11

Editorial Comment Maintenance spending to jump in 2016 as refiners catch up with turnarounds

27 Reliability

Principles are more important than strategies

A. Chilka and A. Garg

ENVIRONMENT AND SAFETY 75 Lifting of US crude export ban will impact

DEPARTMENTS





31

Automation Strategies The “big picture” on ExxonMobil’s open system initiative

33 Petrochemicals

Fluctuations in GCC ethylene production encourage refinerypetrochemicals integration



37

Engineering Case Histories Case 90: Precautions when working near equipment

www.HydrocarbonProcessing.com

Industry Perspectives Is 2016 the peak for the revival in US gasoline demand? Over the past year, strong gasoline demand, particularly in the US, has been the saving grace for much of the downstream industry. The crash in oil prices has made prices for oil-derived fuels, like gasoline, significantly lower, which has spurred an upswing in consumer demand. While US refiners have generally seen lower year-on-year profits owing to the weaker pricing environment, the uptick in gasoline demand has kept margins relatively healthy. In fact, the high gasoline demand has even contributed to a small rally in upstream crude prices. However, questions remain as to whether this model is sustainable. Analyst sees recovery as temporary. Linda Giesecke, director of research for the Americas refining industry at consultancy Wood Mackenzie, believes 2016 is likely the peak for domestic gasoline use. She delivered her outlook in March at the Annual Meeting of the American Fuel & Petrochemical Manufacturers (AFPM). “Despite low fuel prices and the recent upward trend, we see this as a temporary recovery in demand,” Giesecke said. “In our view, the peak in gasoline demand is real.” Reasons for future decline. Giesecke expects US gasoline

demand to decrease starting in 2017, driven by sluggish GDP growth, rising fuel prices and continued improvements in the miles-per-gallon fuel efficiency of light vehicles, thereby requiring reduced overall volumes of gasoline. Over the longer term, those trends could pick up even more, she said—citing a worsening US trade deficit, a more gradual increase in the working-age population and aggressive government mandates, such as the CAFE standards, dictating further fuel efficiency improvements. Overall, Giesecke expects the fuel efficiency of vehicles to rise by 2%/yr over the long term. As a result, the focus for refiners in the years ahead could shift from overall production volumes to advancements in cleaner technologies. “Automakers will rely on a more rapid adoption of advanced gasoline technology and the use of lighter materials to meet these targets,” Giesecke said.

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CIRCULATION / +1 (713) 520-4440 / [email protected] Manager, Circulation

Alice Murrell

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. Hydrocarbon Processing’s Full Data Access subscription plan is priced at $1,695. This plan provides full access to all information and data Hydrocarbon Processing has to offer. It includes a print or digital version of the magazine, as well as full access to all posted articles (current and archived), process handbooks, the HPI Market Data book, Construction Boxscore Database project updates and more. Because Hydrocarbon Processing is edited specifically to be of greatest value to people working in this specialized business, subscriptions are restricted to those engaged in the hydrocarbon processing industry, or service and supply company personnel connected thereto. Hydrocarbon Processing is indexed by Applied Science & Technology Index, by Chemical Abstracts and by Engineering Index Inc. Microfilm copies available through University Microfilms, International, Ann Arbor, Mich. The full text of Hydrocarbon Processing is also available in electronic versions of the Business Periodicals Index.

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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 © 2016 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.

View from the industry. Recent data from the US Energy

Information Administration (EIA) showed US gasoline demand falling in January for the first time in 14 months. It is unclear, however, whether this was a one-off event due to poor weather conditions, or the start of a prolonged slowdown. To weigh in, we encourage readers to visit HydrocarbonProcessing.com and vote in our latest poll on whether 2016 is indeed the peak year for US gasoline demand.

4 MAY 2016 | HydrocarbonProcessing.com

President/CEO Vice President, Downstream and Midstream Vice President Vice President, Production Business Finance Manager Publication Agreement Number 40034765

John Royall Bret Ronk Ron Higgins Sheryl Stone Pamela Harvey Printed in USA

Other Gulf Publishing Company titles include: Gas Processing, Petroleum Economist and World Oil.

HITTING TOP QUARTILE MEANS Reclaiming the dead money buried in your operation

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6–8 June 2016 | Milan Marriott Hotel–Milan, Italy | HPIRPC.com Keynote Speaker: Juliette De Maupeou TOTAL SA Pankaj H. Desai Shell Global Solutions

Carlos Fernando Machado Petrobras

Arnold Kleine Büning BayernOil

Shailendra Mohite Kuwait Petroleum International Yulan Gao Fushun Research Institute of Petroleum & Petrochemicals SINOPEC Anurag Sharma Indian Oil Corp.

Dr. Arun Shukla Oil & Natural Gas Corp. Ltd. (ONGC)

Exploring Innovation in the Downstream Register for IRPC and get the latest updates and trends shaping the refining and petrochemical industry The seventh annual International Refining and Petrochemical Conference (IRPC) will be held 6–8 June 2016 in Milan, Italy. IRPC provides a high-level technical forum where key players in the global petrochemical and refinery sector will meet to share knowledge and learn about best practices and the latest technology advancements being used to improve maintenance and reliability, maximize efficiencies, increase profitability, optimize processes, minimize emissions, treat wastewater, meet clean fuel specifications and much more.

If you haven’t already made plans to attend, here are just a few reasons to join us: 1. Receive Valuable Insight from Real-World Examples + Case Histories from: • BayernOil (the BayernOil Neustadt Refinery) • Vega (eni’s Slurry Technology Hydrocracker) • Petrobras • Shell Global Solutions • Total • CH2MHILL (Award-winning Bapco Wastewater Treatment Plant) • Engineers India Ltd. 2. Get answers to questions like: • How long will low crude prices last? • Will the crude slate become lighter and sweeter due to US tight oil? • Will diesel ever return to being the premium fuel (on a crack-spread basis)? • What’s the value of petrochemical integration? • How can the Internet of Things (IOT) be used to operate nearer constraints, improve maintenance and reduce the cost of shutdowns? • How can automation and advanced process control successfully address the challenges for sustainable energy efficiency?

HPIRPC.com 3. Explore Innovative Technology and Learn About: • New ideas to save energy • Creative ways to increase capacity or improve product quality • How to get the best economic performance from existing and future compressors • Actionable insights for plant monitoring and control, with data-driven optimization cutting across silos and positively impacting KPIs like plant reliability, capacity utilization and operational costs • Refinery and petrochemical integration opportunities and drivers • How to increase productivity, efficiency and profitability in the FEED process • How to optimize wastewater treatment • How to identify discrepancies between expected and actual performance and fix issues before they escalate out of proportion, thereby avoiding unplanned shutdowns, risks and safety incidents • The scope of air emissions compliance solutions and options in several important applications • And much more! 4. Network with the Industry’s Top Players: Conference speakers, sponsors and delegates represent the hydrocarbon processing industry’s leading operator and service companies. Throughout the event, you’ll have numerous opportunities to network with professionals from around the world, who represent: Total, Shell, BayernOil, eni, Kuwait Petroleum International, Petrobras, Indian Oil Corp., SINOPEC, PDVSA–Intevep, Oil & Natural Gas Corp. Ltd. (ONGC), Sasol, OMV Refining & Marketing, Sandvik, KBR, Schneider Electric, Axens, and more. 5. Tour the SOLD OUT Exhibit Floor: Learn about the latest innovative solutions from conference sponsors and exhibitors. Build relationships with new vendors and connect face-to-face with existing suppliers. 6. Participate in Exclusive IRPC Activities: • eni’s Sannazzaro de’Burgondi Refinery Tour: IRPC delegates have the opportunity to register for this free, exclusive tour sponsored by eni on 6 June 2016. Seating for the tour is limited and is available on a first-come, first-served basis. To register for the tour, make sure to check the box next to the tour during registration. • HPI Top Project Awards Luncheon: Now in its second year, Hydrocarbon Processing’s HPI Top Project Awards recognize those projects that will have the highest impact to the global or regional downstream industry. The 2015 winners will be formally recognized and presented with their trophies during this special awards luncheon held on 7 June. It is free to attend, but seating is very limited and you must RSVP. To RSVP for the luncheon, check the box next to the HPI Top Project Awards Luncheon during registration. Available on a first-come, first-served basis.

>> Register Online at HPIRPC.com and SAVE 15% with code: HPMay For questions, to register offline or to sponsor/exhibit: Contact Melissa Smith, Events Director, at [email protected] or +1 (713) 520-4475 Sponsors:

Exhibitors:

Select 69 at www.HydrocarbonProcessing.com/RS

P. O. Box 2608, Houston, Texas 77252-2608, USA|Phone: +1 (713) 529-4301|GulfPub.com

A new day for you, a new day for us Dear Reader, The last thing you need right now is another dreary recitation of industry statistics that show how hard hit the global oil and gas industry has been in the last 18 months. So, I will spare you the gory details. The fact is that, over the past two decades, new technologies have produced gluts of both oil and natural gas. With global oil production reaching nearly 94 MMbpd in 2016, the term “peak oil” has a whole new meaning. For the downstream industry, this has led to abundant and relatively inexpensive feedstocks for the refining, petrochemical, and gas processing/LNG industries. Recently, we have seen a time of dislocation in the industry. This includes vast layoffs in the upstream sector, as well as the reduction of capital investments and abrupt changes in global production and consumption patterns. But, out of this time of change comes many opportunities. For the industry, it means that we will emerge leaner, meaner and more profitable. To lower costs, operators will adapt new technologies to make crude oil and natural gas processing much more efficient, safe and clean. This includes the widespread application of data analytics, which is new and very exciting. From low-sulfur transportation fuels to power generation and plastics, these innovations will provide the world with the highest-quality products. For Gulf Publishing Company, publisher of Hydrocarbon Processing, we have had the opportunity to buy the company from the previous owners. During our 100th anniversary year, we are now an independent company with headquarters in Houston and offices in Houston and London. Our global media brands cover the entire market: Petroleum Economist for industry business and strategy, World Oil for the upstream, Hydrocarbon Processing serving the downstream and Gas Processing in the midstream. Hydrocarbon Processing is well-known for its annual HPI Market Data book, which provides major trends in downstream project activity and spending in every region of the world for the coming year. Hydrocarbon Processing is also well-known for the Construction Boxscore Database, which tracks and provides detailed information on thousands of downstream projects around the world. Over the years, our editors’ forecasts have proved to be very accurate in projecting downstream investment. As you know, a lot of forecasters have not fared well over the last few years. Nevertheless, we at the new Gulf Publishing Company make these forecasts, which you can count on: 1. Global demand for transportation fuels, natural gas and petrochemicals will continue to increase. In turn, the industry will continue to process hydrocarbons in ever more efficient and safe ways. 2. New technologies and processes will be developed and applied to increase efficiencies, as well as produce high-quality products. 3. Hydrocarbon Processing will serve the industry for decades to come. We will continue to provide the latest advances in technology and best practices, as well as lead the industry in providing executive, engineering and operating management with information to help oil and gas industry professionals do their jobs better. So, dear reader, I thank you for your devotion to Hydrocarbon Processing. As I travel around the world, it is gratifying to hear from readers about the publication, the website and our newsletters, and how the information is interesting and, more importantly, beneficial in their work. I also thank all of the advertisers who support this publication. During our 100th anniversary year, I invite you to dive deeper into Hydrocarbon Processing and HydrocarbonProcessing.com, and to let us know what you think. We highly value your feedback. After all, our objective has been, and will continue to be, to help you do your job better.

John Royall President/Chief Executive Officer Gulf Publishing Company Hydrocarbon Processing | MAY 20169

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Editorial Comment

ADRIENNE BLUME, EXECUTIVE EDITOR [email protected]

Maintenance spending to jump in 2016 as refiners catch up with turnarounds Maintenance expenditures are a proactive expense to maintain equipment and processing units. They play a pivotal role in maintaining plant efficiency and sound unit operation, maximizing facility profits and preventing accidents and breakdowns. It is estimated that over 40% of a budget that is allotted for facility and unit maintenance is spent on equipment and materials. Equipment and infrastructure spending represent large portions of a facility’s capital budget (FIG. 1). These include the costs for planned and unplanned plant turnarounds, retrofits and upgrades. Companies must also set aside funds for the costs associated with adhering and complying with increasingly stringent environmental and safety requirements. Key factors influencing the selection and specification of equipment include engineering, licensing requirements and processing unit needs. Approximately 60% of a plant’s remaining maintenance budget is spent on the labor costs for these vital activities.

to five years as refiners in the US prepare to meet new Environmental Protection Agency (EPA) regulations, and as they export more oil products. Gasoline prices are likely to remain low as long as crude prices are suppressed, which will spur fuel consumption and encourage refiners to invest in gasoline-related projects, particularly for reforming and alkylation units. Gasoline projects will also be motivated by upcoming EPA rules on naphtha content, octane loss and Corporate Average Fuel Economy (CAFE) standards. A significant portion of refinery budgets will be spent on projects to adhere to Tier 3 fuel regulations, which will begin in 2017 for larger refineries. Combined, these factors are likely to invite a flurry of revamp, upgrade and construction projects at North American refineries through the remainder of the decade. 8%

Higher maintenance expenditures forecast in 2016. Maintaining the re-

liability and availability of refineries as they take advantage of higher margins, as seen in the US and elsewhere during this time of low crude oil prices, is imperative. In mid-2015, US refinery utilization rates were in the mid-90% range, compared to the low-80% range in 2013 and 2014. In the US and Canada, 2016 maintenance spending is forecast to be approximately $1.3 B. The number of scheduled refinery turnarounds in North America is anticipated to rise this year after declining sharply in 2015, as refiners delayed maintenance shutdowns to capitalize on abundant quantities of low-priced feedstock. Despite low crude oil prices, however, analysts expect refinery capital expenditures to increase over the next three

4%

5%

26%

9% 10% 38%

Major process equipment (pumps, pressure vessels, heat exchangers, etc.) Infrastructure (erection of equipment, piping, etc.) Building construction Engineering services Piping and valves Process instrumentation Electrical (switchgear, cable, etc.) FIG. 1. Equipment and infrastructure spending represent a large portion of a facility’s capital budget. Source: Hydrocarbon Processing’s HPI Market Data 2016.

INSIDE THIS ISSUE

12 Business trends.

Hydrocarbon Processing concludes its two-part series on the global petrochemical industry. Part 2 of this series provides new project developments and regional outlooks for Asia-Pacific, Canada, Europe and Latin America.

38 Special report.

Since equipment failures can result in expensive unit or total plant shutdowns, as well as in 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. Maintenance and reliability programs also create value. In the modern HPI, they should not be viewed as services, but rather as equal partners of operations in the creation of business value.

53 Process engineering.

This conclusion of a twopart series analyzes and explores the economic viability of coal-based chemicals production in India, including key production development hurdles.

67 Heat transfer.

Computational fluid dynamic modeling has been applied to address issues like high tube metal temperatures and reduction in tube metal temperatures using patented inclined firing technology. The working philosophy is to first build a CFD model, for which results can be validated against field measurements and observations. Once a validated CFD model is achieved, various design modifications are evaluated to select the most feasible design option. Hydrocarbon Processing | MAY 2016 11

| Business Trends The global petrochemical sector will continue to see strong capacity growth through the end of the decade. However, the global petrochemical landscape varies significantly between regions. Part 1 of this series provided an overview on the present state of the petrochemical industry, a breakdown of new and active petrochemical project numbers, as well as major trends in Africa, the Middle East and the US. In Part 2 of this series, major petrochemical trends and projects in Asia-Pacific, Canada, Europe and Latin America are discussed. Photo courtesy of LyondellBasell.

LEE NICHOLS, EDITOR/ASSOCIATE PUBLISHER [email protected]

Business Trends Global petrochemical overview—Part 2 Through 2016, the global petrochemical outlook varies significantly between regions. Part 1 of this series provided an overview on the present state of the petrochemical industry, a breakdown on new and active petrochemical construction project numbers by region, as well as major petrochemical construction trends in Africa, the Middle East and the US. Part 2 examines the petrochemical landscape in Asia-Pacific, Canada, Europe and Latin America. Part 1. To summarize Part 1, many new pet-

rochemical construction projects remain in the works, despite the drop in oil prices. The most significant expansions will be in developing countries in the Asia-Pacific and Middle East regions. These regions are investing heavily in petrochemical production units to supply increasing demand and to diversify product portfolios. Some of the strongest growth is seen in the US, where cheap natural gas is fueling more than $135 B in new petrochemical capacity. Meanwhile, a decline in the oil-to-gas spread is making even oil-based naphtha crackers in regions such as Western Europe and Northeast Asia more viable than they have been in years. Ethane cracking operations in the Middle East and the US still maintain a price advantage against cracking naphtha, but the gap has shrunk considerably. This has provided naphtha cracking operations with fresh life, as feedstock costs have dropped dramatically over the past 18 months. New petrochemical project announcements have declined over the past three years, from nearly 170 in 2014 to just over 100 in 2016. This represents a 38% decrease in new petrochemical announcements globally during this period. Although new project numbers are down, the world has witnessed over 400 new petrochemical projects announced within that same time frame. This represents a total capital expenditure of more than $80 B.

Asia-Pacific. The region has seen a slowdown in new project announcements over the past few years. Regardless, the region continues to dominate in total active construction projects in all sectors of the downstream industry. This includes new petrochemical capacity, as well. Over the past year, the Asia-Pacific region has led in new petrochemical project announcements (FIG. 1), followed closely by the US. China continues to invest heavily in chemical production capacity. According to Hydrocarbon Processing’s Construction Boxscore Database, total capital expenditures for announced petrochemical projects in China have eclipsed $50 B through 2020. This includes the construction and expansion of new petrochemical facilities, such as China National Offshore Oil Corp. (CNOOC) and Shell’s Nanhai expansion project; Fujian Petrochemical Co.’s Fujian petrochemical complex; and SP Olefins’ Taixing ethylene facility (China’s first gas-cracking ethylene plant); as well as alternative/unconventional supply routes, such as coal-to-olefins (CTO), methanolto-olefins (MTO) and propane dehydrogenation (PDH) projects. However, these plants were conceived and built during a time of high crude oil prices. Now that oil prices have fallen dramatically, MTO and PDH plants are facing fierce competition from naphtha-based petrochemical production. Regardless, China’s MTO capacity is set to increase from approximately 1 MMtpy in 2014 to over 6 MMtpy by 2017. The country has also begun operations on over 4 MMtpy of CTO plants, with an additional 6 MMtpy to 7 MMtpy going online by 2018. PDH plant construction is even more robust, with approximately 14 new PDH units planned or under construction. These units represent over 10 MMtpy of additional propylene capacity. Although China is the largest consumer of plastics in the Asia-Pacific region, the fastest demand growth is seen in India. According to Vikram Sampat, vice president

and head of aromatics for Reliance Industries, India’s petrochemical growth will average between 8%/yr and 10%/yr through the end of the decade. With such immense demand growth, additional petrochemical capacity has been announced throughout the country. India plans to add over 3 MMtpy of new ethylene capacity by 2020. This would raise the country’s domestic ethylene capacity to just over 7 MMtpy. Total capacity could increase even higher by the early 2020s, should Hindustan Petroleum Corp. Ltd. and GAIL greenlight their $5-B greenfield petrochemical complex in Andhra Pradesh. Additionally, Indian Oil Co. has announced over $5 B in new petrochemical investments through 2022. This includes additional polypropylene capacity at Paradeep and the Baroni refinery, and an expansion of its Panipat cracker to 1.3 MMtpy by 2020. The country is also increasing polyethylene terephthalate and purified terephthalic acid capacity, as well as other downstream petrochemical derivatives. This increase includes the construction of billion-dollar fertilizer projects. Even with the additional petrochemical capacity scheduled to be commissioned, India will still need to rely on imports to satisfy demand. With the surge in demand for petrochemicals and refined fuels, along with the possibility of a major 40 35

Petrochemical projects

30 25 20 15 10 5 0 Africa

Asia- Canada Europe Latin Middle Pacific America East

US

FIG. 1. New petrochemical projects by region, 2016. Source: Hydrocarbon Processing’s Construction Boxscore Database. Hydrocarbon Processing | MAY 2016 13

Business Trends construction boom, it seems that India has become the new China—at least for the foreseeable future. In Malaysia, work continues on the ambitious Refinery and Petrochemical Integrated Development (RAPID) project. The project, which is Phase 2 of the Pengerang Integrated Petroleum Complex project, will include a 300-Mbpd refinery, a petrochemical complex with a combined capacity of 7.7 MMtpy of various products, and an LNG regasification terminal. RAPID is estimated to cost $16 B, while the associated facilities will cost more than $11 B. Major contracts have already been awarded and operations are expected to begin by late 2019. South Korea is investing in its downstream sector, with a focus on petrochemical and refining expansion projects. One of the most notable projects is S-Oil’s Residue Upgrading Complex Project (RUCP). The project is part of the company’s strategic growth initiative, which includes refining and petrochemical integration. The RUCP will convert heavy fuel oil into high value-added gasoline and olefins. The project consists of the simultaneous construction of the RUCP and an olefin complex. The two projects will act as an integrated complex. The RUCP will supply its production as feedstock to the olefins plant. The two projects are expected to be completed in 1H 2018. In 4Q 2014, SK Gas broke ground on an $830-MM PDH unit in Ulsan. The 600-Mtpy unit is being built by project partners SK Advanced (a subsidiary of SK Gas), Kuwait Petrochemical Industries Co. and Saudi Arabia-based Advanced Petrochemical Co. Commercial operations are expected to begin in 1H 2016. Additional South Korean petrochemical projects include Hyundai Chemicals’

Daesan petrochemical complex expansion to produce 1 MMtpy of mixed xylenes, and Korea Petrochemical Industry Co.’s (KPIC) Onsan Naphtha Cracking Center (NCC) expansion in Ulsan. KPIC plans to nearly double ethylene production at the NCC, from 470 Mtpy to 800 Mtpy. Operations are expected to begin in 1H 2017. Once completed, KPIC’s ethylene production market share in South Korea will increase from 6% to 10%. Vietnam is investing heavily in refining capacity to eliminate a domestic shortage of refined fuels. The country is developing several large-scale projects. The majority of these new refineries will incorporate petrochemical units. The $9-B Nghi Son refinery and petrochemical complex will be Vietnam’s second domestic refinery. The 200-Mbpd refinery will integrate aromatics and polypropylene facilities. Operations are scheduled to begin by 2018. Nearly $35 B of additional refining capacity is planned in the country, but work on these facilities has been moving slowly. These plants will also integrate multiple petrochemical units. The $3.2-B Vung Ro refinery and petrochemical complex will produce benzene, toluene, mixed xylenes and polypropylene, but the project is not on schedule to meet its 2017 startup date. The $22-B Nhon Hoi refinery and petrochemical project’s scope included nearly 5 MMtpy of olefins, polyolefins and aromatics production, but has been delayed indefinitely. In early 2016, Qatar Petroleum pulled out of the $4.5-B Long Son petrochemical complex project. The project partners will postpone the project until a new partner is chosen. Canada. The majority of new capital

investment in Canada’s petrochemical

sector is focused on adding derivative capacity to maximize existing crackers. The most notable petrochemical projects in the region are located in Alberta. These include Nova Chemicals PE1 facility in Joffre and Williams Energy Canada’s new PDH plant in Redwater. The PE1 project is part of Nova Chemicals’ NOVA 2020 growth strategy, which includes major projects at the company’s Joffre and Corunna sites. At the time of this publication, the $1-B PE1 project was nearly 80% complete. The project will expand the Joffre site’s polyethylene facility by adding a third polyethylene reactor, which will produce between 475 Mtpy and 550 Mtpy of linear low-density polyethylene. This represents a 40% increase in the site’s polyethylene capacity. Startup is expected to take place in 4Q 2016. Nearly 150 mi north of Joffre, Williams is planning to build a 525-Mtpy PDH plant. The project, located at Williams’ Redwater complex in Alberta, will be the first of its kind in Canada. The PDH plant will process offgas, a byproduct of the oil sands upgrading process, into polymer-grade propylene. If completed, the project is expected to begin operations by 2020. These two projects are examples of Alberta’s efforts to incentivize petrochemical producers to create a petrochemical industry in the province. Alberta has announced financial incentives worth over $350 MM to operators for the construction of petrochemical plants that utilize methane or propane feedstocks. The Alberta government hopes that the new incentives will help spur the development of new petrochemical capacity in the region. Time will tell if these new incentives will achieve the province’s goals of increasing new downstream investments.

21% Western Europe

21% Western Europe

79% Eastern Europe

38% Russia 21% Other Eastern Europe 20% CIS

FIG. 2. Total active petrochemical project market share comparison and breakout between Eastern and Western Europe. Source: Hydrocarbon Processing’s Construction Boxscore Database.

14 MAY 2016 | HydrocarbonProcessing.com

Business Trends Europe. Active petrochemical project construction in Europe is led by petrochemical capacity additions in Eastern Europe. As shown in FIG. 2, Eastern Europe controls nearly 80% of active petrochemical project construction in the region. This is lead primarily by projects in Russia and the Commonwealth of Independent States (CIS). The CIS has seen some of its ambitious petrochemical plans halted, however. This includes capital-intensive projects such as KPI’s Atyrau gas-to-chemicals complex in Atyrau, Kazakhstan; and SOCAR’s petrochemical complex near Baku, Azerbaijan, which was part of the country’s OGPC mega-project. SOCAR has announced that it will instead spend approximately $1.3 B to upgrade the existing refinery and petrochemical complex, as well as continue work on the Sumgait petrochemical plant revamp located north of Baku. Regardless, the CIS is progressing with multiple projects to increase petrochemical production capacity. This includes the Kiyanly petrochemicals complex and Garabogaz fertilizer plant in Turkmenistan, the Ustyurt gas chemicals plant in Uzbekistan (completed in late 2015), as well as additional ammonia-urea plant projects in Azerbaijan, Turkmenistan and Uzbekistan. In total, over $7 B will be invested to increase petrochemical capacity in the CIS by 2019. The bulk of petrochemical capital expenditure in the region is located in Russia. Russian chemical company Sibur has set its sights on completing the ZapSibNeftekhim petrochemical complex (ZapSib-2) project. The project, located 3 km north of Sibur’s polymer site in Tobolsk, was greenlighted in early 2015. The project will consist of a 1.5-MMtpy ethane cracker and ethylene derivative plants. Once completed, the complex will be the largest polymer production site in Russia. Rosneft subsidiary Far East Petrochemical Co. (FEPCO) is planning to build the largest integrated refining and petrochemical complex in the country’s Far Eastern Federal District near the city of Nakhodka. The complex will consist of a 12-MMtpy refinery, which will supply feedstock to the grassroots petrochemical complex. Once completed in the early 2020s, the facility will supply the local market in the Russian Far East, as well as utilize its proximity to Asian markets to satisfy demand for petrochemicals.

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Business Trends According to the European Chemical Industry Council (CEFIC), EU chemical output in 2015 was nearly flat, registering only a 0.3% growth year-over-year. The CEFIC has forecasted a modest 1% growth in European chemical production in 2016. EU petrochemical producers witnessed good margins at the start of 2016 due to strong demand for ethylene derivatives, supply constraints and low feedstock prices. These trends have kept

EU petrochemical capacity utilization above 80% for the past six months, but the long-term forecast for EU’s petrochemical industry is wrought with challenges. This includes stiff global competition, and energy and regulatory costs. Latin America. Both Central and South America saw tremendous growth over the past decade. From 2004–2015, the growth in Latin America’s middle class was instru-

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mental to the region’s increased demand for refined fuels. Multiple forecasts show that the region will see a nominal increase in demand through the rest of the decade. Latin American countries have been hit hard by the drop in oil prices, especially the countries that depend heavily on oil export revenues. The drop in revenues has left little money to fund capacity expansions in the refining and petrochemical industries. In the short term, these countries would rather satisfy demand through imports than invest in major expansions or grassroots facilities, which can be multibillion-dollar endeavors. This trend does not mean that the region is void of petrochemical projects. One of the most ambitious projects in the region has just begun production. The $5.2-B Etileno XXI project, a finalist for Hydrocarbon Processing’s 2015 Top Project award, represented the first major private sector petrochemical project in Mexico in 20 years. The greenfield complex, located in Nanchital near Coatzacoalcos, Veracruz, Mexico, was developed by Braskem Idesa and features a 1-MMtpy ethane cracker, two high-density polyethylene plants (750 Mtpy), one low-density polyethylene plant (300 Mtpy), and storage, waste treatment and utility facilities. The facility began operations in March 2016, and will be instrumental in meeting the increasing demand for polyethylene in Mexico. A glaring gap exists between Mexico’s potential for polyethylene production and its inability to meet surging demand. Approximately 65% of polyethylene demand is satisfied through imports, and the gap continues to grow each year. The Etileno XXI project is forecast to replace $2 B of polyethylene imports used as a feedstock for the agricultural, automotive, construction and consumer industries. Trinidad and Tobago is the world’s largest exporter of ammonia and the secondlargest exporter of methanol. The country has 11 ammonia plants and seven methanol plants. The country is investing $1 B in the construction of a new methanol and dimethyl ether (DME) production complex. The project is being developed by a consortium consisting of Mitsubishi Gas Chemical, Mitsubishi Corp. and Mitsubishi Heavy Industries, along with Massy Holdings and state-owned National Gas Co. of Trinidad and Tobago. The project was greenlighted in September 2015 after additional financing was secured. The fa-

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Business Trends cility will be located in La Brea and have a total capacity of 1 MMtpy of methanol and 20 Mtpy of DME. The plant is expected to begin operations by 1Q 2019. Further south, Brazil’s petrochemical future looks bleak. Refining and petrochemical expansion plans have been severely cut back due to cost overruns, downstream revenue losses, massive debt, economic weakness and government corruption scandals. According to the Brazilian Chemical In-

dustry Association (ABIGUIM), demand for chemical products in Brazil has decreased nearly 8% over the past year. This represents the largest decline in 25 years. The drop in crude oil prices has decreased naphtha feedstock prices, but this has done little to spur new investment. In Peru, there is continued support for a greenfield petrochemical complex to be located in the country’s southern region. The $3.5-B Arequipa petrochemical proj-

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ect would process natural gas feedstock piped from the Camisea gas fields located in central Peru. The project would be supplied with feedstock from the $5-B natural gas pipeline presently being built by Odebrecht. If built, the petrochemical complex will produce approximately 1.2 MMtpy of polyethylene. Finally, Bolivia is the key natural gas supplier in the region. Domestic natural gas production reached 21.4 Bcmy in 2014, according to BP’s Statistical Review of World Energy 2015. Production is more than enough to satisfy domestic demand, making exports a national priority. The increased production of domestic natural gas is fueling the country’s ambitious plans to substantially increase petrochemical capacity. Bolivia’s national oil and gas company, YPFB, has instituted a new expansion program to become self-sufficient in valueadded hydrocarbon products by 2022. The country is nearly completed with Phase 1 of the strategic national plan. The nearly $2-B plan (Phase 1) included the: • Rio Grande liquid separation plant—completed in 2014 • Valle Hermoso refinery expansion—completed in 2014 • Rio Grande LNG plant— completed in 2015 • Gran Chaco liquid separation plant—completed in 2015 • Bulo ammonia-urea plant— under construction, completion set for 3Q 2016. The Bulo ammonia-urea plant will be Bolivia’s first petrochemical complex. The plant will produce over 420 Mtpy of ammonia and 645 Mtpy of urea. These supplies are destined for the domestic market. Operations are expected to begin in July 2016. Both the Rio Grande and Gran Chaco liquid separation plants are crucial to provide feedstock to the country’s petrochemical chain. The Gran Chaco separation plant will be the main supplier to the country’s proposed $1.7-B Gran Chaco petrochemical plant. The complex will contain propylene/polypropylene plants, as well as an ethylene/polyethylene complex. If built, the propylene/polypropylene facilities are likely to begin operations in the early 2020s, with the ethylene/ polyethylene plants to begin construction shortly thereafter. Additional petrochemical projects, which are presently being evaluated for their feasibility, have been announced in Bolivia.

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GasProcessingConference.com

AMERICAS

September 13–14, 2016 Norris Conference Centers – CityCentre Houston, Texas

Where the Upstream, Midstream and Downstream Gas Processing Experts Meet Super Early Bird Registration Now Open: Register for just $400 The shale gas boom has established the US as the world’s leading gas producer and is responsible for billions of dollars of investments in the US gas processing industry. To address the need for information in this rapidly expanding market, Hydrocarbon Processing and Gas Processing are pleased to announce the second GasPro Americas (GasPro), which will be held September 13–14, 2016, in Houston, Texas. GasPro 2016 will cover the gas processing industry from upstream to downstream. Confirmed participants include gas processing experts from: Chevron Energy Technology Company; Greyrock Energy; Wood Mackenzie; AspenTech; Atlas Copco; Bechtel Corporation, USA; Black & Veatch; Chart Energy & Chemicals; Deloitte; Emerson; Haldor Topsoe, Inc; DNV GL; Nexo Solutions; Optimized Gas Treating, Inc; SNC Lavalin; and many others to be announced. The multi-track conference program features sessions on: • The State of Natural Gas • IOT and the Future of Big Data in the Americas for the Natural Gas Industry • Condensate Removal • NGL Recovery • Water Treatment • Fractionation • HSE • LNG/FLNG • Gas Treating • Liquefaction/Regasification • Separation/Dehydration • Metering/Custody • Flaring/Emissions • Alternative Applications • Cryogenics: Rejection – Ethane, • Policy: The Importance of Methane, Nitrogen Legislative and Regulatory Compliance – Managing Risk • Syngas Production and Utilization at the Plant Level • The Future of LNG in America The preliminary agenda will be released soon. Stay tuned to GasProcessingConference.com for more information. Questions about speaking/sponsoring/exhibiting: Contact Melissa Smith, Events Director, at [email protected] or +1 (713) 520-4475.

Supported by:

GPA Midstream has been engaged in shaping the midstream sector of the US energy industry since 1921: setting and adopting standards for natural gas liquids; developing simple and reproducible test methods to define the industry’s raw materials and products; managing a cooperative research program that is used worldwide; providing a voice for our industry on Capitol Hill; being the go-to resource for a multitude of technical reports and publications; and so much more. More than 1,000 volunteers from member companies worldwide are engaged in GPA Midstream efforts. The volunteer support speaks well of the commitment that the industry brings to the organization. GPA Midstream represents about 100 corporate members of all sizes, and members account for more than 90 percent of the natural gas liquids produced in the United States.

VIPs Attend Free! Employees of Owner/Operator companies involved in Gas Processing are eligible to attend this event at NO COST. To see if you qualify for a free pass, contact Melissa Smith, Events Director, at [email protected] or +1 (713) 520-4475

Program Content is Geared Towards: Expert Technical Presentations Include:

Advances in cross-linked polyimide hollow fiber membranes for CO2 removal from natural gas Shabbir Husain Senior Process Engineer Chevron Energy Technology Company

Novel break-through technologies to process optimization Esben Lauge Sorensen Syngas Technology Specialist Haldor Topsoe, Inc

Turbo expanders in NGL recovery Joseph Lillard Engineering Product Manager Atlas Copco

Fundamentals of kettle boiler hydraulic design Laura Aiken Project Engineer Bechtel Corporation, USA

Exhibitors:

Those who are involved in natural gas • Gathering • Processing • Compression • Storage • Treating • Marketing As well as those involved in natural gas liquids • Fractionation • Storage • Transportation • Marketing Individuals involved in the following roles will benefit by attending: • CEOs • Directors • COOs • Executive Directors • CTOs • Country Managers • Presidents • Regional Managers • VPs • Project Managers • SVPs • Chief Engineers • Managing Directors • Technical Directors • Managers

New Exhibit / Sponsorship Opportunities Available To discuss how you can showcase your company brand and schedule appointments with key players in the industry before, during and after the event, contact Melissa Smith.

Exciting New Features Include: • VIP luncheon networking opportunities • Adding collateral to the VIP gift bag • Attendee list pre-conference for appointment scheduling • And more

Register Early + Save $200 Visit GasProcessingConference.com to register online. To Register Offline: Contact Melissa Smith, Events Director, at +1 (713) 520-4475 or [email protected] Admission Rates: (Based upon single attendance. Prices are in USD.)

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MIKE RHODES, MANAGING EDITOR [email protected]

Industry Metrics

15 10

7

April-16

Mar.-16

Feb.-16

Jan.-16

Dec.-15

Nov.-15

Oct.-15

Sept.-15

Aug.-15

July-15

June-15

May-15

Mar.-16

Feb.-16

Jan.-16

Dec.-15

Nov.-15

Sept.-15

Oct.-15

Mar.-16

Feb.-16

Jan.-16

Dec.-15

Nov.-15

Oct.-15

Mar.-16

Feb.-16

Jan.-16

Dec.-15

Nov.-15

Oct.-15

Sept.-15

Aug.-15

July-15

June-15

May-15

April-15

Mar.-15 Cracking spread, US$/bbl

Mar.-16

Feb.-16

Jan.-16

Dec.-15

Nov.-15

Oct.-15

Sept.-15

Aug.-15

July-15

20 10 0

Mar.-16

Feb.-16

Jan.-16

Dec.-15

Nov.-15

Oct.-15

Sept.-15

Gasoil Fuel oil

Aug.-15

Prem. gasoline Jet/kero

July-15

Mar.-15

-10 -20

June-15

Cracking spread, US$/bbl

30

Dubai Urals April-15

Mar.-15

Gasoil Fuel oil

Singapore cracking spread vs. Oman, 2015–2016*

Brent dated vs. sour grades (Urals and Dubai) spread, 2015–2016* Light sweet/medium sour crude spread, US$/bbl

Prem. gasoline Jet/kero

-10 -20

Source: EIA Short-Term Energy Outlook, April 2016.

8 6 4 2 0 -2 -4

0

June-15

2017-Q1

10

May-15

2016-Q1

30 20

May-15

2015-Q1

40

Mar.-15

2014-Q1

Stock change and balance, MMbpd

Supply and demand, MMbpd

6 5 4 3 2 1 0 -1 -2 -3

Forecast

Stock change and balance World supply World demand

Prem. gasoline Jet/kero Diesel Fuel oil

Rotterdam cracking spread vs. Brent, 2015–2016*

World liquid fuel supply and demand, MMbpd

2013-Q1

Sept.-15

60 50 40 30 20 10 0 -10 -20

Cracking spread, US$/bbl

Oil prices, $/bbl

120 110 100 90 80 70 60 Brent Blend 50 W. Texas Inter. 40 Dubai Fateh 30 Source: DOE 20 M A M J J A S O N D J F M A M J J A S O N D J F M 2014 2015 2016

2012-Q1

Japan Singapore

US Gulf cracking spread vs. WTI, 2015–2016*

Selected world oil prices, $/bbl

100 98 96 94 92 90 88 86 84 82 2011-Q1

Aug.-15

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

July-15

60

June-15

M A M J J A S O N D J F M A M J J A S O N D J F M 2014 2015 2016

US EU 16

70

April-15

0

80

April-15

20

2 1 0

May-15

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

April-15

3

40

90

Mar.-15

4

Utilization rates, %

60

100

Gas prices, $/Mcf

5

Aug.-15

Global refining utilization rates, 2015–2016*

6

80

July-15

US gas production (Bcfd) and prices ($/Mcf)

June-15

Mar.-15

April-15

0

100 Production, Bcfd

WTI, US Gulf Brent, Rotterdam Oman, Singapore

5

May-15

An expanded version of Industry Metrics can be found online at HydrocarbonProcessing.com.

Global refining margins, 2015–2016* 20

Margins, US$/bbl

US refinery margins recovered as product markets were supported by strong domestic gasoline demand and temporarily tight sentiment fueled by the switch to summer-grade gasoline. In Europe, the lack of gasoline and fuel oil export opportunities caused margins to continue falling. Asian margins saw a slight recovery on the back of stronger regional demand and the onset of refinery maintenance.

* Material published permission of the OPEC Secretariat; copyright 2016; all rights reserved; OPEC Monthly Oil Market Report, April 2016. Hydrocarbon Processing | MAY 2016 23

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LEE NICHOLS, EDITOR/ASSOCIATE PUBLISHER [email protected]

Global Project Data According to Hydrocarbon Processing’s Construction Boxscore Database, nearly 300 new downstream projects have been announced around the globe over the past year. The Asia-Pacific region maintains the greatest number of new downstream project announcements, with nearly 33% of new project announcements since May 2015. The US is a close second, with approximately 28%

3

2

25

3

Canada 26

of new announced downstream capacity additions within that same time frame. Both regions are continuing their downstream capacity buildout. The US is maximizing cheap, readily available natural gas feedstocks to fuel its petrochemical and LNG industries, and the Asia-Pacific region is building new capacity to satisfy demand for transportation fuels, petrochemicals and power generation.

21

31

6 22

Europe US

9

7 8 6 7

6 4

Refining Petrochemical Gas processing/LNG

32

5

Middle East 3

37 23

Africa Asia-Pacific

Latin America

New petrochemical project announcements by region and sector, May 2015–present 30 24

26

25

27 22 17

18

20

8% Africa 15% US

27

26 18

18

21

Mar.- April- May- June- July- Aug.- Sept.- Oct.- Nov.- Dec.- Jan.- Feb.- Mar.- April15 15 15 15 15 15 15 15 15 15 16 16 16 16

Boxscore new project announcements, February 2015–present

30% Asia-Pacific 21% Middle East 3% Canada 13% Europe 10% Latin America Market share breakdown of active downstream projects by region

Detailed and up-to-date information for active construction projects in the refining, gas processing and petrochemical industries across the globe | ConstructionBoxscore.com Hydrocarbon Processing | MAY 2016 25

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Reliability

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

Principles are more important than strategies A number of US oil refineries have recently asked the question, “When should an equipment repair be classified as rework?” At one major facility, if a pump or motor is taken to the shop for repairs and the asset is thereafter returned to service, a 45-day observation period commences. By that facility’s definition, a “good repair” is proven if, after recommissioning, an asset runs for at least 45 days without mechanical problems. If issues develop on Day 1 through Day 44, then the equipment is taken back to the shop, and the second repair is classified as rework. Since rework does not count as a failure, their statistics look good: Eight 44-day runs might equate to eight repair events, but they would be counted as only one failure. A refinery with fewer failures achieves approving key performance indicator numbers (KPIs) and moves up in surveys conducted as for-profit services by process consulting and benchmarking firms. Since the entire 45-day observation strategy seems to violate the principle of common sense, a reliability staffer at this major refinery had a few questions. In an e-mail, the staffer asked: “I cannot find a rational basis behind the 45 days; why not 45 minutes? If it runs 45 days but develops a mechanical issue that requires it to again be taken to the shop, even for the same issue that caused it to require a repair in the first instance, then we simply identify it as a second repair.” A second repair for what, however? Normal wear? End of life? This 45-day criterion seems to have been pulled out of thin air, so to speak. Which begs the question: Are there any standards, best practices or practical guidelines that help determine what is considered rework? How did you address this issue in your consulting assignments over the past decades? What best-of-class performers do. In the 1960s and 1970s, before the invention

of fancy footwork with KPIs, the answer was quite simple: After shop work had been done at a true best-practices plant (BPP), the machine was reinstalled, started up and remained online for at least a full month. BPPs never use the term “spare”; they simply have “A” pumps and “B” pumps. After running for two full days without defect, a repair event file at these BPPs was closed. Failures on or after Day 3 were considered new, and a different event file was opened. Failure on Day 3 would have automatically meant two failures in any running 12-month period. Two-in-12 would require placement of the machine on the “bad actor list”—the roughly 7% of process pumps that failed with excessive frequency. More importantly, the obviously ailing “bad actors” at BPPs were no longer given the standard repair or “get-it-done” treatment of the maintenance department. A computerized maintenance management system (CMMS) assigned these repeatedly failing machines to the jurisdiction of the plant’s reliability group. The reliability group was then tasked with finding the true root causes of repeat failures. They had to determine what needed to be done to avoid these events from recurring. Science-based explanations and engineered solutions replaced the usual quickly-voiced, unsubstantiated opinions and trial-and-error approaches. Written work processes and procedures were compiled for, and pursued, on bad actors at these BPPs. From that time on, the failure frequencies at such facilities quickly disappeared into the general average failure population. No new initiatives needed. It seems that the staffer’s managers were seeking progress by coming up with new initiatives or new ways to tackle reliability issues. Why should that be necessary? The staffer’s facility has the same machines, and his plant is processing the same fluids as others, including many best-of-class (BOC) performers.

It may be of interest to note the reasons why these BOCs are continually near the top in ranking surveys conducted by professional benchmarking firms. BOCs never compromise principles; instead, they adjust their strategies to capitalize on technology advancements. In the staffer’s case, common sense should tell us that copying the equipment upgrade steps and work processes diligently implemented by BOCs would move his refinery closer to becoming a BPP. The staffer’s analysis is compelling. When we pointed out the old experiences listed previously, the staffer sent us an immediate and very perceptive reply. Here it is, condensed into four points: • The problem has been a progressive one. Plants often degenerate to the point of losing the ability to understand the difference between principles and strategies. Coupled with a working environment where every manager rises to a certain point of incompetence, workers can end up on a train that does not know where it came from, where it is going or how it is going to get there. • Principles are foundational, tried and tested approaches that have proven successful and should be maintained at all costs. If not maintained and managed, however, they can drift away. In an environment of not knowing what works or why it works, there exists a temptation to fix recurring problems with the next “new thing” in the hope that, eventually, something will work. • A real hesitation seems to exist to look outside the reliability group for ideas and strategies that have been proven successful. In other words, there is reluctance to reach outside the “family” for help and guidance Hydrocarbon Processing | MAY 2016 27

Reliability with rotating equipment reliability. This can lead to the “inbreeding” of ideas and practices. • The single greatest frustration to be found here is the aversion to taking the time to read and study various journals, books and technical papers on subjects relating to reliability. Such studies would keep people informed on what BOC companies are doing and

how they got there. Reading would impart knowledge of what works, what does not work and which underlying principles prevail. The staffer’s up-to-date feedback validated things we now observe with alarming frequency. Some reliability-focused organizations used to be strong and wellled. Regrettably, tangible reliability performance is declining in some organizations. Problems are ignored and unfounded op-

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timism fills the void. Hopefully, the staffer will soon be placed in a position where he can do what BPPs did years ago. Reliability principles simplified. We

hear and read much about reliability principles; however, when everything is said and done, more will have been said than done. That is because many reliability managers are influenced by “edicts from above,” or by PowerPoint presentations full of consultant-conceived generalities. While all of these generalities may be true, not one of the generalities is a tangible alternative to in-depth knowledge. Telling that to a manager is usually a career-limiting move; it is much safer to stick with consultant-conceived generalities. The notion that a contractor can always be hired for the job is deeply flawed. However, a contractor can be hired to carry out the procedural details that have been stipulated by a well-taught reliability professional. This reliability professional is an individual who has been nurtured and groomed for many years. If your company did not do this nurturing, grooming and rewarding, it is unlikely that another company will have done it for you. Here’s an example: the industry’s understanding of best practices regarding bearing cooling and lubricant application for centrifugal process pumps is far from uniform. Optimized lube selection, cooling, application and contamination avoidance affect energy efficiency and contribute significantly to extending pump mean time between failures. Show me the contractor who shows you these and 200 other details, and I will show you a billing rate that throws this knowledgeable contractor out of contention. 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 650 publications, among them 19 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.

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Automation Strategies

PAUL MILLER, SENIOR EDITOR/ANALYST ARC Advisory Group

The “big picture” on ExxonMobil’s open system initiative Several noteworthy presentations were given at ARC’s 20th Annual ARC Industry Forum in Orlando, Florida in February. One presentation, in particular, stimulated considerable discussion among process control system end users and suppliers alike: Don Bartusiak’s keynote presentation on ExxonMobil’s vision for a totally new, open, standards-based process automation platform. For those readers who do not know Dr. Bartusiak, he is the chief engineer for process control at ExxonMobil (Downstream) Research & Engineering. “I would like to present the big picture here,” Dr. Bartusiak began. “The problem we are trying to solve is, ‘How can we take the cost out of our process control projects for both system replacements and greenfield projects?’” What’s wrong with the status quo? “So, what is wrong with

the status quo?” he asked rhetorically. “In a nutshell, it is too expensive for us to upgrade our process control systems, and we are just not getting enough value from them. Most of the recent enhancements we have made were for Level 3 applications that reside above the control systems.” Dr. Bartusiak also noted that a significant percentage of ExxonMobil Refining and Chemical’s control systems will face obsolescence over the next decade. Getting right to the point, he said, “So, why not simply replace these systems with a state-of-the-art distributed control system (DCS)?” He gave five reasons: • The high cost of “technology refresh” limits access to leading-edge performance • Integrating third-party components is too expensive • Limited liquidity exists in the application market, along with a lack of sophisticated development tools • Solutions come bundled vs. best-in-class • Rather than being built-in and intrinsic, the current security model is bolted on.

A new approach. To find solutions, Dr. Bartusiak explained, “We saw opportunities for improvement through open architectures and virtualization—not just for engineering, but also to provide new ways for process control. We saw a constructive revolution taking place in the defense avionics industry by transitioning from a proprietary ‘stovepipe’ model to an open and interoperable, standards-based system architecture. We saw the Internet of Things (IoT) and wireless capabilities changing management expectations, with questions such as, ‘Why do we even need control systems anymore?’ We are seeing new solutions for the security challenge from innovators.” He presented his organization’s vision for standards-based, open, secure and interoperable control systems that:

• Promote innovation and value creation • Effortlessly integrate best-in-class components • Afford access to leading-edge capability and performance • Preserve the asset owner’s application software • Significantly lower the cost of future replacement • Employ an adaptive intrinsic security model. Dr. Bartusiak emphasized that this vision for open automation was applicable for both brownfield and greenfield facilities; would involve no compromises in safety, security or availability; and, most importantly, would help meet the goal of creating a commercially available system that would be applicable to all current DCS markets. Why Lockheed Martin? Next, Dr. Bartusiak addressed the obvious question of why ExxonMobil decided to work with Lockheed Martin to supplement its internal resources for this critically important initiative. Lockheed Martin is a founding member of the Open Group Future Airborne Capability Environment (FACE) Consortium, a joint government-industry consortium formed in 2010 as a government and industry partnership to define an open avionics environment for all military airborne platform types. Dr. Bartusiak and the rest of the ExxonMobil team realized that a similar approach could be extremely beneficial for the process control industry. In November 2015, ExxonMobil awarded Lockheed Martin the contract to serve as the systems integrator for early-stage development. Next steps. In January of this year, ExxonMobil and Lockheed

Martin held an “industry day” event for suppliers to test the industry’s appetite for this type of solution. Despite a major snowstorm that buried the Washington D.C. area, the vast majority of interested parties still managed to attend. The next step, Dr. Bartusiak said, is to solicit interest and support from other prospective users. “We plan to build a lab prototype in 2016. Beyond 2016, we would like to see a technically ready solution in 2018 and a fit-for-purpose system in 2019.” PAUL MILLER is a senior editor/analyst at ARC Advisory Group and has 30 years of experience in the industrial automation industry. He continues to follow the increasing adoption of IT in the OT area and its various ramifications for industrial organizations.

Hydrocarbon Processing | MAY 2016 31

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Petrochemicals

R. SHAFI, Nexant, Manama, Bahrain; T. NGUYEN, Nexant, Kuala Lumpur, Malaysia; and R. PLATT, Nexant, London, UK

Fluctuations in GCC ethylene production encourage refinery-petrochemicals integration

Changing competitiveness. Regulated pricing resulted in Saudi Arabia becoming the third-largest producer of ethylene globally, accounting for approximately 10% of world production. The pricing was maintained through a number of economic and political scenarios ranging from varying oil prices, global recession and regional conflict situations. In 2014, oversupply in the crude oil market impacted global prices. The price of Brent crude dropped below $40/bbl in 2015. This had a marked effect on the balance sheets of oil producing nations around the world. One of the responses by the GCC states was to readdress any domestic cost advantage to

both industry and citizens. In December 2015, Saudi Arabia announced that specific changes would be made to the regulated prices of methane and ethane, among others. Methane was increased from $0.75/MMBtu to $1.25/MMBtu, and ethane from $0.75/MMBtu to $1.75/MMBtu. These changes will result in a variable costs increase for Saudi Arabian producers. It is estimated that the total cost of production for a pure ethane cracker will increase by approximately 51%. The increase, from approximately $120/t to $180/t, shows that the plants will remain relatively competitive. However, the impact is not uniform for all plants. Ethane/ propane crackers are estimated to experience a lower increase of approximately 25% as the proportion of ethane processed is lower, tempering the impact of the price increase. The change in price regulation comes at a time when crude oil prices have decreased. Regions where ethane is not available are more inclined to process liquid feedstocks, such as naphtha. In Asia, for example, the petrochemical sector has developed ethylene production, which is strongly based on refinery-derived feedstocks, such as naphtha (FIG. 4). 25 20 MMt/yr

Global petrochemical production in 2014 totaled approximately 1.5 Bt. The Middle East produced approximately 207 MMt, or 14% of global production, making it one of the highest-producing regions globally. Much of this petrochemical industry is built around the abundant oil and gas reserves of the Gulf Cooperation Council (GCC) countries. A closer examination of ethylene, a key building block, shows just how dramatic the production growth in this sector has been. Much of the capacity is based within Saudi Arabia, which has been the key growth country (FIG. 1). This growth has been enabled by a select number of factors jointly contributing to favorable and highly competitive process economics. Large reserves and production of oil and gas have resulted in significant quantities of natural gas liquids (NGL), particularly ethane (FIG. 2). NGL have not always been used as petrochemicals feedstocks in this region. For example, until the 1980s, much of the ethane and methane were flared. Post-1980, both were used to enhance the development of the domestic ammonia and methanol production industries through regulated pricing. Initially, both were priced at $0.50/MMBtu, but were further increased to $0.75/MMBtu in the 1990s (FIG. 3).

5 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 FIG. 2. Feedstock makeup in the GCC. 700

Saudi Arabia UAE Qatar Kuwait

600

10

1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015

5

FIG. 1. Ethylene capacity in the GCC.

FOB Mont Belvieu Saudi Arabia

500 400 $/t

MMt/yr

15

15 10

25 20

Mixed feed Ethane/propane Ethane

300

200 100 0 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 2009 2011 2013 2015

FIG. 3. Comparative ethane pricing, 1985–2015. Hydrocarbon Processing | MAY 2016 33

Petrochemicals Propane

Butane

Naphtha

40

Gasoil Ethylene capacity, MMt/yr

%

0.4

25

0.2

20 15 10

0.3 0.2

0.1

0.1 0.0 South East Asia North America Western Europe

AsiaPacific

Africa

Middle East

Central/ Eastern Europe

Western Europe

South America

North America

Integrated

Liquids cracking

Oil price, $/bbl

100 70

Lighter feedstocks

50

0

50

100 150 Ethylene cumulative capacity, MMt

200

FIG. 5. Global ethylene cost curve at different crude oil prices.

The impact of the price of crude oil on petrochemical competitiveness can be analyzed by considering a global cost curve (FIG. 5). Lowest-cost producers are shown on the left, and higher-cost producers are shown on the right. At $100/bbl, the grouping for plants processing similar feedstock slates is immediately discernible. The analysis shows that liquid-based crackers are significantly disadvantaged compared to ethane crackers at this higher oil price. At the lower oil price of $70/bbl, the cost of production for liquids-based crackers is decreased most significantly. Mixedfeed and LPG crackers also experience lower production costs at this lower oil price. At $50/bbl, a similar, but more pronounced, change is seen. Effectively, the cost curve is flattened at lower oil prices, with an increase in the competitive positioning of liquids-based crackers. The price adjustment for Saudi Arabian feedstocks, therefore, comes at a time when Asian and West European plants are more competitive. Future outlook. Ultimately, the cost advantage will still be

maintained; however, the gap between Saudi producers and West European and Asian producers does decrease. Oil market fundamentals are expected to be maintained in the near term, moderating away from oversupply, with crude oil prices expected to recover. The competitive position of Western European and Asian liquid crackers is, therefore, expected to decrease somewhat (restabilizing to pre-2014 levels). Further growth for Saudi Arabian and GCC ethylene production is unlikely to be based around ethane crackers. In all GCC

34 MAY 2016 | HydrocarbonProcessing.com

0.6 0.5

30

Middle East

Global

Ethylene cash cost, $/t of ethylene

0.5

0.5

5 0

FIG. 4. Ethylene production by feedstock type. 2,000 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0

0.5

35

RPI

Ethane 100 90 80 70 60 50 40 30 20 10 0

Not integrated

East Asia RPI

FIG. 6. Regional refinery-integrated ethylene production, 2014.

countries, availability of ethane is limited; therefore, growth in ethylene production will be based on liquid feedstocks. As demonstrated in FIG. 5, the economics of producing ethylene from liquid feedstocks is more challenging, and fine-tuning of the resulting cost structure can be advantageous. One way in which the variable cost of a liquid cracker can be reduced is by integration with a refinery. FIG. 6 examines the production of ethylene in each region and the extent to which production is refinery-integrated. FIG. 6 details the amount of ethylene production capacity that is refinery-integrated by region, and the corresponding Refinery Petrochemical Integration Index (RPI), defined as the ratio of the integrated capacity to the total capacity. East Asia has the largest ethylene production capacity, although approximately half of this is based on refinery-integrated feedstock production due to the lack of available gas feedstocks. This results in a relatively high RPI of 0.5. A similar scenario is seen in Western Europe. North America has more oil and gas production and, thus, more ethane availability. The degree of integration is correspondingly lower (RPI = 0.2). In the Middle East, the degree of refinery-integrated petrochemical production is very low (RPI = 0.1), although the actual ethylene production capacity is correspondingly high. In the GCC, little refinery-integrated ethylene production is seen. As GCC petrochemical companies eye continued growth, this is expected to increase, in part driven by limited gas feedstock availability. More refinery-integrated capacity is expected to be developed, which is anticipated to raise the RPI from 0.1 to approximately 0.2 by 2020. RAHEEL SHAFI is a senior consultant in refining and petrochemicals at Nexant. He has a wide background in refining and petrochemicals. He has been working with organizations within the Middle East for a number of years and is based in Bahrain.

TIN NGUYEN is a senior consultant in Nexant’s Malaysian office. He routinely works on petrochemical feasibility studies at Nexant, carrying out market, pricing and technical analyses as well as developing complete competitiveness and financial models. He has also performed numerous studies on the competitiveness of olefins plants. RICHARD PLATT is a senior research analyst in Nexant’s energy and chemicals advisory for Europe, the Middle East and Asia. He routinely authors multi-client reports in the chemicals sector. His single-client work includes market research, business analysis, cost competitiveness modeling and price forecasting.

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Engineering Case Histories

TONY SOFRONAS, CONSULTING ENGINEER http://mechanicalengineeringhelp.com

Case 90: Precautions when working near equipment Most machines and pressure vessels are designed with safety in mind, but they can release large amounts of energy if not constructed, maintained or operated correctly. Testing of piping and pressure vessels. Pneumatic testing

is performed for leak detection at low pressures and small volumes. Hydrotesting is performed at higher pressures for leak testing, stress distribution and structural integrity. Catastrophic failures can occur when pneumatic tests of large volumes are performed.1 Compressed gas contains much more energy than water. A 200-ft3 vessel pressurized to 50 psig with air contains about the same energy as 0.5 lb of TNT, or an automobile driving 75 mph. The energy in the same vessel with pressurized water is 7,000 times less. When someone at a meeting says, “It will contain gas at that pressure anyway, so why not pneumatically test it?” remember to speak up. Flying fragments can travel thousands of feet. Codes and standards may be considering only safe distances due to the pressure wave, not the flying fragments. Other ways to pressure test exist.2 Reciprocating machinery. On my first visit to a site with

hyper-compressors, where discharge pressures can be much higher than 20,000 psi, I was shown the bent beams in the roof where pieces impacted when they had come apart due to lack of maintenance. Lower-pressure gas engine compressors have challenges, too. I have seen rods come through the sides of the engine, and cylinder heads blown off, due to a lack of proper operation or preventive maintenance. Rotating machinery. One purpose of the housing is to keep the parts contained if the rotating parts fail. Turbocharger rotors, compressor and clutch discs can break through their housing. I have witnessed a turbocharger test in a test cell where the rotor broke out of the housing and bounced off the cell walls. Pressure vessels and brittle fracture. Brittle fracture is

the rapid extension of a crack in a low-toughness steel at 7,000 fps without warning.3 My advice has always been that if an old low-toughness steel vessel has a crack, do not try to monitor it—shut it down immediately. Replacing such vessels is usually the safest choice.

tigue failure.4 Good designs, thorough inspections and sound welds can minimize this risk. Valves handling hazardous material. A valve with elastomer internals that remains closed for years can take a permanent set and will not operate correctly when needed. Valve maintenance is imperative. Initial selection may not have been correct, so it is a good idea to verify the internals of critical service valves. Hydraulically fitted couplings. Rotating couplings can fail.

Coupling guards should be robust and in place. On tapered hubs that are removed hydraulically, the hub can “pop off ” at over 25 mph and travel many feet. Use a safety nut and treat the hub as you would a loaded gun, by staying out of the line of fire.

Do not count on your sense of smell. Odors are important. However, when you do not smell something, it might be too late. Hydrogen sulfide is an example. In deadly concentrations, it can deaden sense of smell. Plant steam leaks. Steam from boilers can reach 4,000 psi.

Any leaks from super-heated steam are deadly and would be invisible due to a lack of condensate. Be aware, and listen to experienced advice. Always have an escape route if something fails. Even a ruptured steam hose can cause terrible burns.

LITERATURE CITED “Pneumatic test explosion in Shanghai LNG terminal,” Chemical & Process Technology, March 2009, online: http://webwormcpt.blogspot.com/2009/03/ pneumatic-test-explosion-in-shanghai.html 2 Sofronas, A., “Survival techniques for the practicing engineer,” J. Wiley & Sons, Hoboken, New Jersey, 2016, unpublished. 3 Barsom, J. M. and S. T. Rolfe, Fracture and Fatigue Control in Structures, 2nd Ed., Prentice-Hall, Upper Saddle River, New Jersey, 1977. 4 Sofronas, A., B. Fitzgerald and E. Harding, “The effects of manufacturing tolerances on pressure vessels in high-cycle service,” ASME, PVP Vol. 347, 1997. NOTE Case 89 was published in HP in March. For past cases, please visit HydrocarbonProcessing.com. 1

TONY SOFRONAS, D. Eng, was the worldwide lead mechanical engineer for ExxonMobil Chemicals before retiring. He now owns Engineered Products, which provides consulting and engineering seminars on machinery and pressure vessels. Dr. Sofronas has authored two engineering books and numerous technical articles on analytical methods.

Welded pressure vessels under cyclic loading. Depressuring and repressuring several times per day is cyclic loading. This can induce a cyclic stress on poor welds and cause a faHydrocarbon Processing | MAY 2016 37

| Special Report MAINTENANCE AND RELIABILITY In 2016, the hydrocarbon processing industry will spend over $101.9 B globally on various maintenance projects. Since equipment failures can result in expensive unit or total plant shutdowns, best-of-class companies maintain the mindset that spending to improve reliability and equipment conditioning is a great benefit to the organization. Maintenance and reliability programs also create value. They should not be viewed as services, but rather as equal partners of operations in the creation of business value. This month’s special report explores innovative methods and programs to keep facilities operating as designed. Photo: Edmonton Exchanger provides onsite plant maintenance services for the petrochemical industry, refineries and fertilizer plants.

Special Report

Maintenance and Reliability M. BARNES, Des Case Corp., Goodlettsville, Tennessee

Take steps to achieve lubrication maintainability According to IEC 60300-3-10, maintainability refers to “The ease, economy, safety and accuracy with which the necessary maintenance of a product can be undertaken and can be measured, either in terms of probability or in the level of resources required to maintain the item.” In the context of asset management, this can be re-stated simply as, “How easily can a machine be inspected, preventive maintenance performed or repairs effected by how a machine is designed, installed or operated?” While the premise is simple, very few plants are able to achieve a basic level of maintainability. The concept of maintainability is not new. Its origins can be traced back to many of the same philosophies embodied in reliability-centered maintenance (RCM), with one critical difference. At its core, RCM prescribes the desired (required) minimum maintenance policy to keep an asset safely performing as designed. Maintainability, on the other hand, refers to the ease with which those maintenance tasks can be performed. RCM vs. maintainability. The difference between RCM and maintainability is important. Often, even the best-designed plant maintenance (PM) plans that come out of RCM, or other maintenance optimization processes, cannot be executed because equipment is simply not configured to permit the work to be done. Put simply, if the way in which a machine is designed, installed or operated does not permit the necessary PM plans to be completed, then even the most well-developed RCM-based maintenance processes cannot be executed. While the reasons for this discrepancy are wide-ranging, perhaps the most common is how equipment is designed, installed and commissioned. Typically, when a new production line or piece of equipment is installed, careful consideration is given to operational functionality (i.e., can the desired throughput of on-spec product be achieved) at the lowest total cost, with little consideration as to how the equipment will be maintained moving forward. Driven by an increasingly price-sensitive business climate, original equipment manufacturers (OEMs) are forced to remove all of the “bells and whistles” from their equipment to maintain competitive pricing. The result is equipment that comes in on budget, but contains few adaptations that make onthe-run maintainability easy or even possible. As an example of how pervasive this problem has become and how it can impair even the most basic common sense, consider the following true story. A project engineering manager was tasked with the installation and commissioning of a new paper machine. Unwilling or unable to consider even the most basic lubrication contamination control measures due to time and/or budget constraints, the project team was focused (and probably

receiving a bonus) on having the new machine up and running on time, at or below the allocated capital budget for the project. Fast forward two months to after the new paper machine went into production. The same engineer—now assigned as the plant’s maintenance manager—could not get support fast enough to ensure that the new equipment could continue to run reliability if it was retrofit with every conceivable way of controlling contamination ingress! This short-sightedness is at the root of maintainability problems pervasive in many plants. It is unlikely that a wholesale change in attitudes to equipment lifecycle cost will happen anytime soon. Even if it did, the millions of assets that are already in service cannot be accounted for. A different approach is needed—one that is simple and cost-effective, but which allows some of the most fundamental PM tasks to be completed in the right way, at the right frequency. To do this, minor modifications must be made to in-service equipment to permit the right PM tasks to be performed at the optimum frequency, no matter the operational state of the equipment. Achieving lubrication maintainability. For rotating and re-

ciprocating equipment, many of the day-to-day PM tasks that are most affected by poor maintainability revolve around lubrication. Since 40%–60% of all mechanical issues relate directly or indirectly to lubrication, these tasks represent “low-hanging fruit.” Without proper design for maintainability, even basic lubrication tasks like oil changes, level checks, oil sampling or bearing regreasing cannot be performed optimally. With a few basic changes, however, almost all lubrication tasks not only become possible, but can also be performed more precisely and with less time requirements.

Checking oil level. For wet sump applications, in particular,

maintaining the correct oil level is critical. Many wet sump applications, such as gearboxes and pumps, are equipped with a dipstick that is designed only to be removed to check the oil level or a level plug. While both of these checking measures are effective when the gearbox has been shut down for a number of hours, the reality is that most critical gearboxes simply cannot be shut down once a day for two hours just to check the oil level. Moreover, even if the gearbox can be shut down, or an accurate level can somehow be obtained from a dipstick or a level plug, removing the dipstick or plug is in violation of another fundamental tenet of maintainability—the need to exclude external contaminants. Consider the two images shown in FIG. 1, which portray the same plant. To check the level on the gearbox on the left, the technician must find a ladder, climb up to the gearbox and remove the level plug, in the hope that it accurately depicts the Hydrocarbon Processing | MAY 2016 39

Maintenance and Reliability

FIG. 1. Comparison of the maintainability of checking the oil level of two elevated gearboxes.

FIG. 2. Maintainability modifications for a typical gearbox.

correct level while running. While a maintenance planner could write a PM and schedule a task to do exactly that, the likelihood that this task is overlooked is high. The gearbox on the right of FIG. 1 presents a different scenario and a different set of requirements. Standing 10 ft below this gearbox, the level of oil can still be clearly seen, with high and low running levels obvious from the green and red markings on the level gauge. Moreover, with a large column sight glass, the color and clarity of the oil can also be assessed, offering a further visual check of oil condition. A column-level gauge allows for the oil level to be checked in a matter of seconds, making this a simple task that can performed by anyone with little to no mechanical expertise or experience. Changing oil. While oil changes require that equipment be

shut down and, therefore, may fall into the reliability gap, not having equipment set up for best practice can significantly affect the outcome. The most common way to change oil is to place a waste oil container under the drain, remove the drain plug or open the drain port valve and let the oil flow out under gravity. Under some circumstances, this can be a tedious task. The challenge lies with how quickly the oil flows. Particularly

40 MAY 2016 | HydrocarbonProcessing.com

for higher-viscosity oils at lower temperatures, flowrates will be very low, so the only practical solutions are to open the fill port, or to remove the vent or breather cap to increase the flow. While doing so ensures that the oil can be drained faster, this action can have detrimental effects. By removing the vent port or breather cap, the air that replaces the oil as it drains is completely unfiltered. Draining 5 gal of oil from an oil sump in this way means that 5 gal of dirty, moist plant air is sucked into the oil sump. Instead, the drain should be modified to include a quick connect so a filter cart with a manual bypass can be used to extract the oil. The importance of the manual bypass is to allow the transfer pump of the filter cart to evacuate the oil without passing it through the filters. Since gravity is no longer counted on to cause the oil to flow, the vent (or breather) does not need to be removed, ensuring that the act of draining the oil does not affect the intent and outcome of the task: getting clean, fresh oil into the oil sump. Adding or topping of oil. After the oil has been drained, the

oil sump must be refilled with new oil. Again, this is an opportunity for error. Most oil is added by removing the fill port and pouring directly, or by pumping the oil into the sump using a hand pump. In doing so, however, the oil is again exposed to the plant atmosphere. By installing a quick connect on the fill port, the sump can be filled without opening it to the atmosphere, using the same filter cart used to drain the oil. This time, the manual bypass is closed so that new oil is filtered during top-off. One added benefit to this type of modification is the ability to connect a portable filter cart to the quick connects on the drain and fill ports to permit kidney loop filtration, either routinely or on-condition, based on oil analysis results. By simply adding two quick connects, the maintainability of the asset has been dramatically increased, permitting this simple task to be carried out more effectively and efficiently.

Taking an oil sample. Oil analysis is a key indicator of asset

health, but with a proper oil sample, decisions may be made based on erroneous or inaccurate data. Many oil samples are taken by opening a fill port or removing a breather or vent and inserting a flexible plastic tube connected to a vacuum oil sam-

Maintenance and Reliability pling gun—a process often referred to as “drop tube sampling.” Wherever possible, drop tube sampling should be avoided. Not only does this result in a less-than-representative sample, but it also exposes the oil inside the pump to the ambient plant environment. Instead, all assets that warrant routine oil analysis should have properly sampled valves installed. In some cases, oil samples cannot be taken due to accessibility, particularly where guarding prevents direct access to the machine during normal operation due to safety constraints. Again, this is a maintainability issue, as a sample cannot be taken from the right location at the right frequency. Where accessibility is a concern, a simple extension known as a microbore test hose can be permanently affixed to the sample valve on the machine and run to a safe location, so that a sample can be safely taken during normal machine operation. Putting it all together. Often, equipment has limited accessibility for necessary modifications. However, by combining different functions using simple pipe fittings or specialized adapter kits, it is possible—with just a single drain port and a single fill port—to accomplish several goals: • Install a sample port and quick connect for oil drains • Mount a column-level gauge to check the level • Install a second quick connect on the fill port for oil top-off • Install a proper particle and desiccant breather • Connect the level gauge to the headspace of the oil sump to equalize pressure from proper oil level indication.

FIG. 2 shows a modification of this type for a common industrial gearbox. Set up in this fashion, level checks, oil top-offs, oil sampling and basic contamination control can be achieved without once opening the gearbox to the plant environment. In fact, it is not inconceivable to think that a gearbox, modified as described, would never need to be opened to atmosphere for its entire in-service life. Now, that is true maintainability!

Takeaway. Modifying equipment for maintainability is not

complex. Even with limited accessibility, simple tasks like oil changes, level checks and oil samples can be performed according to best practice, with just a few basic fittings and some “outof-the-box” thinking. Do not accept that what the OEM delivered, or how the equipment has been configured for the past 30 years, must be maintained into the future. Optimize your company’s PM program and look for maintainability improvements to ensure that the right work can be performed in the right way and at the right time.

MARK BARNES serves as vice president of the Des Case Lubrication Transformation Services team. Prior to joining DesCase, Mark was vice president and chief technology officer for Noria Corp. Dr. Barnes has been an active consultant and educator in the maintenance and reliability field for nearly 20 years, and has worked with clients around the world to design and implement lubrication improvement plans. He is a frequently invited speaker at maintenance conference around the world. Dr. Barnes holds a PhD in analytical chemistry and is a certified maintenance and reliability professional belonging to the Society for Maintenance and Reliability Professionals.

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Hydrocarbon Processing | MAY 2016 41

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Special Report

Maintenance and Reliability M. CHOWDRY and V. TIWARI, Reliance Engineering Group (REG), Mumbai, India

Apply a short-term, high-temperature carbon steel solution to piping systems

Designing application systems. A logically safe, but not an

ultra-conservative, methodology in the form of case studies for the design of such piping systems and equipment should be followed. Different approaches for the design of such systems are graphitization, creep and time dependency, and the life fraction rule. The graphitization phenomenon is dependent on material type, time and temperature. Graphitization generally results from the decomposition of pearlite (iron + iron carbide) into the equilibrium structure of iron + graphite, and it can lead to the severe embrittlement of the steel when the graphite particles or nodules form in a planar, continuous manner.

FIG. 1 illustrates the relationship between graphitization, temperature and time for CS material.

Case study 1. A reactor requires bi-yearly regeneration by using steam measured at a temperature of 500°C: • Time duration—10-hr regeneration • Piping construction material—A106 Gr B • Design reactor temperature—278°C • Design pressure—12 kg/cm2 • Service life—25 yr • Corrosion allowance—1.6 mm • Selected schedule thickness—Standard weight, 9.53 mm • Connected piping size—16 in. While selecting the material of construction for the mentioned system, it was observed that the conservative approach is to use the Cr-Mo steel (alloy steel) instead of CS due to the use of 500°C steam for regeneration purposes. Nonetheless, some checks for the suitability of CS for the case discussed above should be performed.

Check 1—Total time of exposure at 500°C during regeneration = 10 hr × 2 (bi-yearly) × 25 yr = 500 hr FIG. 1 shows that CS will not suffer the phenomenon of graphitization at 500°C during regeneration for 500 hr. 100

Heavy 80

Graphitization, %

Carbon steel (CS) piping and equipment are used extensively in refineries and petrochemical plants, where fluid temperatures vary from moderate to high for various processes. The American Society of Mechanical Engineers (ASME) code B31.3 limits the use of CS material in piping systems operating up to a maximum temperature of 427°C, due to the conversion of carbides to graphite that may occur after prolonged exposure to temperatures above 427°C. Stress analysis of such systems becomes critical because the allowable stress values are much lower at temperatures above 427°C. In the hydrocarbon process industries (HPI), some systems will be exposed to temperatures above 427°C for a short duration because of various process upsets. A few examples of these systems are: • A pressure safety valve (PSV) discharge of high-high pressure (HHP) steam, design pressure = 105 kg/cm2 at 510°C • The acetylene converter, or the conversion of acetylene into ethylene by a cracking process, or an exothermic reaction, of a cracker plant • An ethylene oxide reactor of a monoethylene glycol (MEG) plant during run-away reaction, pre-ignition or post-ignition • A high-purity isobutylene (HPIB) unit’s selective hydrogenation reactor during regeneration, approximately 100 hr/yr at 450°C. It is recommended to use an alloy steel (Cr-Mo) material for piping and equipment rather than for CS. Considering the long-term, creep-fatigue approach for the design of such piping systems for short-term, high-temperature applications requires the use of Cr-Mo alloy piping and equipment.

60

538°C 510°C 482°C 454°C 441°C 427°C 213°C

Moderate Slight

40

Very slight

20

1 1

4

7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 55 58 61 Years, 8,000 hr

FIG. 1. Graphitization % and time dependency for carbon steel (CS). Hydrocarbon Processing | MAY 2016 43

Maintenance and Reliability TABLE 1. Life fraction rule, as per ASME B31.3 Appendix 5 For a design temperature = 278°C • Sd (Table A1 of ASME B31.3) = 128.6 Mpa • Pipe size = 16 in., seamless • Schedule thickness = Standard weight, 9.53 mm Pmax. = 44.20 kg/cm2 Spi = 128.6 × 12 / 44.20 = 34.91 Mpa. Since allowable stress values from Table A1 of ASME B31.3 and Table Y1 of BPVC section 2, Part D are 31.7 Mpa and 100 Mpa, respectively, at 500°C Considered longitudinal stress value SL = 90 MPa for sustained load case. For seamless pipe W = 1, and corresponding temperature to Si from Appendix 1M of ASME B31.3 is = 408°C = TE • LMP = (C + 5) (TE + 273) = (20 + 5) (408 + 273) = 17,025 • a = (LMP / Ti + 273) – C = (17025 / 278 + 273) – 20 = 10.89 • Rupture life = tri = 10a = 1010.89 = 7,762,471,162 hr For a design temperature = 500°C • Sd (Table A1 of ASME B31.3) = 31.7 Mpa • Pipe size = 16 in., seamless • Schedule thickness = Standard weight, 9.53 mm Pmax. = 10.89 kg/cm2 Now Spi = 31.7 × 12 / 10.89 = 34.93 Mpa. Since the design temperature considered is 500°C, then SL = 31.7 Mpa = Si. For seamless pipe W = 1.0, and corresponding temperature to Si from Appendix-1M of ASME B31.3 is = 500°C = TE. • LMP = (C + 5) (TE + 273) = (20 + 5) (500 + 273) = 19325 • a = (LMP / Ti + 273) – C = (19,325 / 500 + 273) – 20 = 5 Rupture life = tri = 10a = 105 = 100,000 hr. Usage factor U = ∑ (ti/tri) = 157,000 / 7,762,471,162 + 3,000 / 100,000 = 0.03 < 1 The piping system excursion is acceptable.

Check 2—As a result of Check 1, the phenomenon of graphitization is eliminated. The allowable stress value in ASME B31.3 for A106 Gr B at 500°C is 31.7 Mpa, which is much less. As per Clause No. 302.2.4 (1) (b) of ASME B31.3, subject to the owner’s approval, it is permissible to exceed the pressure rating, or the allowable stress, for pressure design at the temperature of the increased condition by not more than 33% for no more than 10 hr at any one time, and it should not exceed 100 hr/yr. With the above mentioned condition, the allowable stress values will be 1.33 × 31.7 = 42.16 Mpa. Case study 2. In this case, the regeneration time was increased

to a 60-hr regeneration while maintaining all the other parameters, as discussed in Case 1. Check 1—Total time of exposure at 500°C during regeneration = 60 hr × 2 (bi-yearly) × 25 yr = 3,000 hr

FIG. 1 highlights that carbon steel will not suffer the phenomenon of graphitization at 500°C during regeneration for 3,000 hr.

Check 2—Again, as a result of Check 1, the phenomenon of graphitization is eliminated. Clause No. 302.2.4 (1) (b) and (c) of ASME B31.3 does not discuss a duration of 60 hr, so the allowable stress values remain 31.7 Mpa at 500°C. It is known that the allowable stress 44 MAY 2016 | HydrocarbonProcessing.com

values given in Appendix A-1M of ASME B 31.3 are based on long-term creep properties as guided by code, and not on shortterm elevated temperature. The question arises as to why the allowable stress values given in Appendix-1M of ASME B31.3 directly for this case—short-duration, high-temperature exposure—should be used. The new approach will: 1. Infer the value of yield strength at 500°C, which is 150 Mpa, in the ASME boiler and pressure vessel code (BPVC) Section 2, Part D, Table Y-1. So, the allowable stress becomes 2/3rd of 150 Mpa, or 100 Mpa. 2. Infer the value obtained from Appendix A- 1 M of B31.3: The normal maximum operating temperature, design temperature of 278°C, which is 128.6 Mpa. For the purpose of stress analysis, the lesser value from (1) and (2), which is 100 Mpa, is used. It is more than three times that of 31.7 Mpa at 500°C, as per ASME B31.3. Thickness comparison. The advantage of these higher allowances on thickness selection and the integrity of the system (estimation of rupture life) should be checked by using the Larson-Miller parameter approach for the above cases. 1. Calculated thickness of a 16-in. pipe with allowable stress values (31.7 Mpa from ASME B31.3) at 500°C = 10.29 mm. 2. Calculated thickness of a 16-in. pipe with allowable stress values (100 Mpa from BPVC section 2, part D) at 500°C = 4.55 mm. The selected thickness defined in this case is the standard thickness of 9.53 mm, so from (1) and (2) it can be concluded that selecting the higher allowable values is advantageous in thickness, or the cost of the piping system, for higher sizes. Estimation of rupture life by the Life Fraction Rule as per ASME B31.3 Appendix 5 (TABLE 1). The piping system has a desired life of 160,000 hr, 157,000 hr of which are operating at a temperature of 278°C. This allows for 3,000 hr of operation at 500°C. It can be inferred that this given approach can be studied in a piping scenario where the normal operating temperature allows the use of commercial CS and there is a requirement for short-term, high-temperature condition. The following criteria requires consideration: Is there any such fluid service, e.g., hydrogen (H2), that can cause other failure phenomena during shortterm, high-temperature applications? For these applications, nitrogen (N2) purging can be carried out before the system faces high temperature for a short duration, so that H2 embrittlement and other such CS failures at high temperature are eliminated. M. G. CHOWDRY is a senior vice president and head of piping engineering of RPTL Engineering (formerly BecRel Engineering Pvt. Ltd.). He has 40 years of work experience in piping design engineering, with a particular focus on pipe stress. He has worked for various companies throughout his career, including EIL, Toyo, Chemtex and Sabic. Mr. Chowdry holds a BS degree in mechanical engineering. VIVEK KUMAR TIWARI is senior engineer working in the piping materials department of Reliance Engineering Group (REG) in Jamnagar, India. He has more than eight years of experience in piping material engineering, and holds a BS degree in chemical engineering.

VERSATILE. Always a leading innovator, ROSEN not only supplies pipeline customers with the latest diagnostic and system integrity technologies but also offers flexible solutions and all-round support for plants & terminals. www.rosen-group.com

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Special Report

Maintenance and Reliability B. SNIDER, Small Hammer Inc., Houston, Texas

Failure prevention—The ultimate asset management strategy

Preventing all failure modes. Failure modes are common-

ly used to describe how specific equipment types fail. Failure modes come in two forms: 1. Functional failure, or loss of a basic function of the equipment 2. Performance failure, or failure to perform at a design or desired level. Using a centrifugal pump as an example, the pump has several functions, the most basic being to continuously transform mechanical energy, provided by the driver (motor, engine or turbine) to potential energy (pressure) and kinetic energy (flow) of a primarily liquid fluid. Other basic functions include start on command, stop on command and fluid containment (no leaks). Expressing the loss of these functions as functional failures, the following list can be compiled: • Failure to pump (no flow or pressure) • Failure to continue to pump (stop, shutdown) • Failure to start • Failure to stop • Failure to contain the fluid (leaks externally). The centrifugal pump also has design performance levels. These are usually expressed by pump curves and show flowrate, developed head (pressure), power requirements and efficiency, as well as material specifications to match the process condi-

tions. If the pump does not perform as designed, then performance failures would occur and be expressed as: • Failure to perform • Failure to pump as designed. Combining the functional failures and the performance failures, six failure modes can be listed for a centrifugal pump: 1. Failure to pump (no flow or pressure) 2. Failure to perform or failure to pump as designed (low flow or pressure) 3. Failure to continue to pump (stops, trips, shuts down) 4. Failure to start 5. Failure to stop 6. Failure to contain the fluid (leaks externally). Similarly, a heat exchanger has four failure modes: 1. Failure to transfer heat at design or desired rate 2. Leaks internally 3. Leaks externally 4. Restricts flow (plugging or fouling). Traditional definition of failure. Almost all equipment failures

follow a time progression from normal operation to functional failure. This progression (FIG. 1) is called the potential-functional failure curve, or P-F curve. Variations of this curve appear in International Organization for Standardization (ISO) and American Petroleum Institute (API) standards, along with virtually every reliability and asset management handbook or instruction manual. The P-F curve depicts the performance of a piece of equipment over time. Starting at time zero, the equipment performs normally for some time, and then the performance starts to drop. This point is called the potential failure. Often, the potential failure is unknown until the symptoms of failure or damage mechaPotential failure

P-F interval

Current definition of failure Functional failure

Performance

The primary cause for losses and lost opportunities at refineries, chemical complexes, pipeline networks and gas processing facilities is equipment failures. The costs of these failures can run into hundreds of millions of dollars. Without a firm commitment to prevent failures, there is little hope for avoiding these enormous losses. Technologies abound that claim to prevent failures. These new technologies suggest that collecting vast amounts of data, applying hundreds of algorithms and simulations, and utilizing years of recorded history will somehow reveal hidden failure mechanisms and allow for significant improvements in failure prevention. A closer look of how and why equipment fails will show that these new technology applications fall short of truly preventing equipment failures. Failure prevention is more than performing inspections, analyzing data and formulating corrective actions. Failure prevention is a mindset; a culture; a driven objective that becomes the dominant focus of activities. It is easily the most effective core philosophy for achieving and sustaining stable, consistent, safe and profitable production.

Process and equipment alarms

0

Time

FIG. 1. P-F curve showing traditional definition of failure. Hydrocarbon Processing | MAY 2016 47

Maintenance and Reliability nism reach a detectable level. If nothing is done to stop or interrupt the failure or damage mechanism, then the performance will continue to deteriorate until reaching the point of functional failure. The time from the onset of failure or potential failure to the functional failure is called the P-F interval. Using this definition of failure, the term failure prevention is any activity, prior to the point of functional failure, that interrupts or corrects the drop in performance. In this context, preventing failures has created a huge industry focused on early detection of the performance drop or symptom within the P-F interval. Common processes such as preventive maintenance (PM), predictive maintenance (PdM), and condition monitoring (CM) all use the point of functional failure as the definition of failure. These processes all claim to “prevent failures,” while they primarily only “detect failures.” New definition of failure. To truly prevent equipment failures, one must prevent potential failures. To embed this concept into a new way of thinking, a new definition of failure is required. The same P-F curve shown in FIG. 1 is repeated in FIG. 2, but with “failure” defined as the point of potential failure and not functional failure. Using this new definition of failure, the term failure prevention is any activity that takes place prior to the potential failure. These activities involve the identification and elimination of underlying conditions, contributing factors, human errors, violations of the integrity operating window (IOW), and events that lead to the potential failure. Substantial documented evidence exists that 80%–95% of all equipment failures have origins in human errors and violations of the IOW. It is, therefore, necessary to prevent errors New definition of failure

Potential failure

Performance

Conditions Factors Errors Violations Events

P-F interval Functional failure

and violations to prevent most equipment failures. Activities performed after the potential failure do not prevent failures. The failure progression model. A second model of failure

progression exists that, unlike the P-F curve, is not based on time. This second model (FIG. 3) defines the most common sequence of events that lead to equipment failures. Reading from left to right, decisions and actions by humans, originating with the earliest contributing factors, cause errors or violations, which lead to events, which stress equipment, and which go on to create an equipment functional failure. The progression can happen over many years, with the contributing factors affecting decisions during the design, manufacturing, installation, operation, maintenance and management of equipment to show up as an equipment failure. The progression can also happen in a matter of seconds when a distraction causes an instantaneous error-event-stress-equipment failure sequence to occur. The significance of the progression model is that each stage in the sequence affects the probability of the subsequent stage. To achieve the most success in preventing equipment failures, failure prevention activities must be focused on reducing the contributing factors that influence human behavior.

Equipment failure. Equipment failures have consequences. The consequences can be expressed as risk, as shown in FIG. 4. Risk is the product of probability × consequence and is best illustrated in the form of risk matrices. Risk matrices should be simple and easy to apply to real-time conditions and equipment lifecycle considerations. The consequences of equipment failure are assumed to be constant, based upon the design. Design includes equipment selection, materials of construction, installation, location, configuration, control philosophy and operating conditions of the equipment. Design often assumes that a basic level of operation, inspection, maintenance and management capability will be in

Process and equipment alarms

Likelihood

Consequence

A

Once per year

M

H

B C D

Once per 2 years Once per 5 years Once per 10 years

L

M

H

H

H

L

M

H

H

L

M L

H

H

H

M

H

H

E

Once per 50 years

L

L

L

M

H

Safety

Hazard First aid Record- Lost time Fatality exposure, able or assignno injury ment

Probability 0

Consequence

Time

1-2 per year

CF

CF

CF

CF

CF

CF

CF

CF

CF

CF

Probability

Probability

E

Once per 50 years

4

5

H H H M

H H H H

H H H H

L

L

M

H

L Nonreportable

1

Probability

Consequence

Equipment failure

Stressed equipment

Equipment failure

4

5

M

H

H

H

H

B C

Once per 2 years Once per 5 years

L L

M

H M

H H

H H

D

Once per 10 years Once per 50 years

L

M L

M

M

H

L

L

L

L

H

E

2

1

2

L

H

5

H

L

H

H

C D

Once per 10 years

L L

L L

M L

H M

H H

E

Once per 50 years

L

L

L

L

M

$1 million

Once per 2 years Once per 5 years

A

2

3

4

H

Costs

5

Consequence H

H

B

1–2 per year Once per 2 years

H

H

H

M

M

H

H

H

C

Once per 5 years

L

L

M

H

H

D

Once per 10 years

L

L

L

M

H

E

Once per 50 years

L

L

L

L

H

Internal procedure violation

1

48 MAY 2016 | HydrocarbonProcessing.com

4

H

H M

Likelihood

FIG. 4. The failure progression model.

3

Consequence

2–3 per year

1

FIG. 3. Equipment failure relationship to risk.

Production

1-6 hours 6-12 hours 12-24 hrs 1-2 days >2 days shutdown or shutdown or shutdown or shutdown or shutdown or equivalent equivalent equivalent equivalent equivalent throughput throughput throughput throughput throughput reduction reduction reduction reduction reduction 12–75,000 75–150,000 150–300,000 300–600,000 >600,000 bbls bbls bbls bbls bbls

B

Contributing factors that influence human performance

3

Consequence

Likelihood

1. Process deviations outside design limits 2. Human interaction with process or equipment performed incorrectly

Environment

Reportable, Reportable, onsite not Offsite Significant contained onsite contained or onsite manageable environmental impact impact (5 bbls

Likelihood Once per year

A

Violations

3

A

Errors Event

2

H M M L

Consequence

Once per 2 years Once per 5 years Once per 10 years

FIG. 2. P-F curve showing new definition of failure. Probability

1

L L L L

Likelihood A B C D

Agency Self identified and notification reported non-violation violation

2

3

with Notice of Violations violation significant operating issued implications

4

5

Compliance

Maintenance and Reliability place throughout the life of the equipment. All equipment has design limitations. Equipment failures, and the consequences of failures, occur when one or more of the limitations are exceeded. With the consequences of failure being constant, based upon the design, the primary approach for risk management is to lower the probability of equipment failure. Probability is a statistical determination that, at any given moment, an equipment failure is likely to occur. The likelihood or probability of equipment failures is not constant in oil refineries. This statement is in direct conflict with nearly every reference book or white paper written about equipment failure. The overwhelming consensus among industry and scholarly professionals is that equipment failures occur at a constant failure rate for most of the equipment lifecycle. This erroneous conclusion is brought on by the assumptions that the equipment is always operated and controlled within its design limitations. Equipment in oil refineries are often subjected to conditions that exceed one or more of the design limitations. This applies undue stresses on the equipment. The probability of equipment failures is directly related to the stresses applied to the equipment. To lower the probability of failure, the probability of stresses must be lowered. Equipment stress. Equipment stress represents forces, dam-

age mechanisms, defects, anomalies and deterioration of equipment components that indicate a reduction in performance or

function after a potential failure occurs, but before a functional failure happens (FIG. 2). Stress comes in four basic forms: chemical, mechanical, electrical and thermal. These stresses lead to visible or detectable effects, conditions or symptoms of strain. TABLE 1 shows some of the effects of the four stresses. The basic stresses are interrelated, often occurring together to inflict damage or increase strain on equipment, which then leads to equipment failure. Common practices for inspection, maintenance and asset management of equipment are based on detecting stresses or symptoms of stresses. These practices have been the mainstay of the refining industry, as well as all other process and manufacturing industries, for over 50 years. The practices include: • Preventive maintenance • Predictive maintenance • Condition-based maintenance • Condition monitoring • Risk-based inspection (API 580, API 581) • Reliability-centered maintenance • Maintenance optimization • Operational excellence • Overall equipment effectiveness • Asset management (ISO 55000) • Risk-based machinery management (API 691). Events. In the dynamic environment of oil refining, equipment stresses and functional equipment failures are rarely caused by

IT ALL STARTS WITH

API STANDARDS. ™

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4/8/16 3:37 PM

Hydrocarbon Processing | MAY 2016 49

VIPs Attend Free! Employees of Owner/Operator companies involved in the Petrochemical Industry are eligible to attend this event at NO COST. To see if you qualify for a free pass, contact Melissa Smith, Events Director, at [email protected] or +1 (713) 520-4475

July 19–20, 2016 / PetchemTechForum.com Norris Conference Centers – CityCentre, Houston, Texas

Explore the Latest Technology + Best Practices in the Booming Petrochemical Industry Don’t miss Super Early Bird Registration: Save $200 when you register by May 10! The US petrochemical industry is in the midst of one of the largest industry expansions to ever occur in North America. Cheap, readily available shale gas has provided chemical producers in the US with low-cost feedstocks, that is fueling over $135B in new petrochemical capacity. This includes capacity expansions, upgrades, plant restarts and greenfield facilities. Join us for the inaugural Petchem Tech Forum July 19–20 in Houston, Texas, as we explore the latest technology advancements and best practices being used in this growing industry. Over the course of two days, you will get a high-level look at the innovative technology and solutions available to help you more efficiently and cost-effectively upgrade, expand, or build new facilities. Get Valuable Insight into Successful Strategies Employed by Top Operators: • TOTAL will share how their refinery has achieved high APC utilization rates and stakeholder acceptance. You’ll learn how to change the APC approach at your facility to improve APC utilization and support from stakeholders, increasing your bottom line. • Kuwait Petroleum International will provide a technical analysis about on-going downstream refining and petrochemicals projects and their current progress along with key success factors and future strategic initiatives. Plus learn how to: • Optimize your budget to navigate challenging market conditions; • Enhance your operating margins, flexibility in operations, rapid market response, quality and consistency for optimum plant performance with process plant automation systems and infrastructure; • Achieve more efficient and flexible production, reduce operating costs, and promote a greener global economy with a comprehensive energy management strategy; • Properly perform risk assessments and studies during the different phases of design in a project to ensure safety in design; • and much more. Download the preliminary agenda at PetchemTechForum.com For Speaker/Sponsor/Exhibit Opportunities: Contact Melissa Smith, Events Director at +1 (713) 520-4475 or [email protected]

July 19–20, 2016 / Houston, Texas / PetchemTechForum.com Presentations Include: Restructuring your APC approach to improve APC effectiveness Randy Conley

DCS/ SIS / APC Implementation Supervisor TOTAL Petrochemicals USA

Industrial downstream vs municipal wastewater: Differences, challenges and viable solutions Carlo Zaffaroni, PhD, PE

Industrial Water & Process Director, Europe - Technical Manager - MENAI CH2MHILL

Moving towards alternative feedstocks: Strategic investments & future petrochemicals process technology configurations in the Middle East & Europe Shailendra Mohite

Senior Engineer Stakeholder Management Kuwait Petroleum International

Use process plant automation systems and infrastructure to enhance petrochem industry operation margins and overall profits Romel S. Bhullar, PE

Senior Technical Fellow/ Director Control Systems Fluor Corporation

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$600

Maintenance and Reliability normal wear or aging. The stresses that initiate a potential failure overwhelmingly come from an event or a series of events. Events are occurrences that cause the stresses and strains listed in TABLE 1.

Failure prevention activities must be focused on reducing the contribution factors that influence human behavior. To lower the probability of stresses, one must lower the probability of events. Some common events that create stresses on equipment are: • Operational changes: cavitation, flashing, running dry, misalignment, imbalance, corrosion and erosion • Process changes: in pressure, temperature, flow or fluid composition, surge, choke, pH, viscosity and loss of control • Structural changes: cracking, bolt tension, support failure, bending, breaking, impact, rupture, shear, slipping, movement and collapse. Following the failure progression model in FIG. 3, events are most often caused by violations and errors. To lower the probability of events, the probability of violations and errors must be lowered. Violations. Extensive research exists that indicates that 80%– 95% of all equipment failures have their root causes in: TABLE 1. Four basic stresses

1. Violations of the design limits of the equipment (IOW) 2. Errors from some human interaction with the process or equipment. The design (of equipment) includes equipment selection, materials of construction, installation, location, configuration, control philosophy and operating conditions of the equipment. Design often assumes that a basic level of operation, inspection, maintenance and management capability will be in place throughout the life of the equipment. All equipment have design limits. A violation occurs when the process conditions, structural supports, physical connections or transferal of energy are outside the design limits. Integrity operating window. To operate any process unit, a set of operating ranges and limits must be established for each piece of equipment to achieve the desired performance and manage the risks. The IOW is a specific set of key operating limits that focuses on maintaining the integrity and preventing the failures of process equipment. Typically, the IOW involves process variables that, if allowed to exceed the limits of the IOW, can increase the likelihood or probability of events that lead to undue stresses on equipment. To lower the probability of events and stresses on equipment, operations must be maintained inside the IOW (FIG. 5). All equipment should have a defined set of operating ranges that will allow operation, as designed, without failure. Points of light. Each piece of equipment should have defined

Form of stress

Effects, conditions or symptoms (strain)

Chemical

Corrosion, erosion, cracking, pitting, dissolving, melting, freezing, congealing, condensing, vaporizing, molecular change, density, viscosity, lubricity, expansion, contraction, heating, cooling, fire

Mechanical

Friction, impact, tension, compression, fracture, shear, torsion, bending, fatigue, creep, inertia, vibration, heating, cooling

specific operating ranges and the design conditions that make up the IOW. To ensure that the process is maintained inside the IOW, specific inspection points and values are identified. The inspection points are called the points of light. For process pumps, 20 points of light (FIG. 6) define the process variables and conditions that make up the IOW. To prevent pump failures, the 20 points of light inside the IOW must be maintained.

Electrical

Charging, discharging, arcing, pitting, magnetizing, melting, welding, short circuit, open circuit, molecular change, heating, fire

Errors. As stated previously, 80%–95% of all equipment failures have the root causes of either violations of the IOW or errors.

Thermal

Expansion, contraction, weakening, vaporization, condensing, melting, freezing, molecular change, density, viscosity, heating, cooling, fire

FIG. 5. Zones of operation defining the IOW.

50 MAY 2016 | HydrocarbonProcessing.com

FIG. 6. Process pumps showing the 20 points of light.

An error occurs when a human interaction with the equipment or process is performed incorrectly. Errors happen at all points of human interaction during the lifecycle of the equipment. Four basic types of errors exist: 1. Error of commission: task performed incorrectly 2. Error of omission: correct task not performed 3. Error in timing: correct task performed but at incorrect time 4. No awareness that task is necessary. Errors can occur during: • Design • Selection • Fabrication • Testing • Shipping • Storage • Installation • Commissioning • Management • Startup • Operation • Shutdown • Inspection • Maintenance • Major repair • Response to changes. Errors are the result of a natural cycle in the way the human mind processes information and makes decisions. The brain constantly performs a decision-action thought process. Issues such as procedures, training, communication, experience, ergonomics, motivation and awareness are factored into the normal interactive process outlined by the following decision-making sequence: • Perception (senses) • Discrimination (awareness) • Interpretation (understanding) • Diagnosis (deduction) • Decision (recall, reasoning) • Action (recall, training, experience, skill) • Perception (feedback). The ability to accurately and consistently perform these steps is the basis for improving the performance of the human being in any activity. Strengthening the decision-action cycle is the most effective method to eliminate errors and prevent failures. Contributing factors (the “dirty dozen”). The human mind continuously and autonomously performs the decision-action cycle during conscious moments throughout one’s life. This is the essence of human behavior. The ability to perform the cycle is influenced by hundreds of forces and events, both internal (intrinsic) and external (extrinsic), that determine people’s behavior and level of performance in virtually everything they do. These influencing forces are called contributing factors. Hundreds of contributing factors influence human behavior. Most of them are present all of the time. The extent to which these factors affect behavior or influence the decision-action cycle depends on a person’s ability to focus on the task he or she is attempting to perform and the awareness, or mindfulness, of the contributing factors present. To overcome the influences of contributing factors, one must practice being focused and mindful. Through practice, the suc-

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 51

Maintenance and Reliability cessful execution of decision and action can occur by blocking the effects of the ever-present contributing factors. The top 12 contributing factors that influence human behavior are called the “dirty dozen” (FIG. 7). To effectively block the dirty dozen and other contributing factors, a change must occur in the entire approach to refinery management. The new approach must change the mindset, the belief and the culture of the entire organization, so that equipment failures can and will be prevented.

Blocking the “dirty dozen” 1. Miscommunication 2. Complacency 3. Distraction 4. Pressure 5. Resource allocation 6. Lack of knowledge 7. Lack of awareness 8. Stress 9. Fatigue 10. Lack of assertiveness 11. Lack of teamwork 12. Normalization of deviance

• Perception (senses) • Discrimination (awareness) • Interpretation (understanding) • Diagnosis (deduction) • Decision (recall, reasoning) • Action (recall, training, experience) • Perception (feedback)

• Focus • Mindfulness • Practice FIG. 7. The “dirty dozen” and the influence on the decision-action cycle.

The science and techniques for preventing failures are not rooted in an IT solution, FMEA, ISO 55000 or a strategic analysis of overall equipment effectiveness. The primary science that will develop the most effective failure prevention strategies is behavioral psychology. Behaviors must be cultivated to prevent the human errors and process violations that are the root causes of the majority of equipment failures. It is recommended that organizations employ organizational and behavioral psychologists to effectively prevent equipment failures. LITERATURE CITED Endsley, M. R., “Situational awareness and human error: Designing to support human performance,” SA Technologies Inc., proceedings of the High Consequence Systems Surety Conference, 1999. 2 Albawaba News, “Human error is involved in over 90% of all accidents and injuries in a workplace,” September 24, 2009. 3 Maguire, R., “Safety case,” Safety cases and safety reports: Meaning, motivation and management, 2006. 4 Boeing Corp., “Maintenance error decision aid (MEDA) user’s guide,” 2010. 5 US Federal Aviation Administration, “Avoid the dirty dozen,” online: https:// www.faasafety.gov/files/gslac/library/documents/2012/Nov/71574/ DirtyDozenWeb3.pdf 1

BARRY SNIDER is president and chief consultant of Small Hammer Inc., a consulting company specializing in refinery and facility management. He has 40 years of experience in maintenance, operation, management and consulting at refineries, chemical manufacturing complexes, pipeline networks and gas processing sites. He holds degrees in mechanical engineering from West Virginia University and an MBA degree in organizational psychology from American Intercontinental University.

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Process Engineering and Optimization M. MARVE, S. SAKTHIVEL and P. V. PALUSKAR, TATA Consulting Engineers Ltd., Mumbai, India

Small-scale coal-to-chemicals can revitalize India’s petrochemicals industry, economy—Part 2 In Part 1 of this article, published in April, the barriers of petrochemical production in India were discussed, along with the opportunity to explore chemicals from coal, using the specific example of polyvinyl chloride (PVC). In Part 2, the final part of this article, the example of manufacturing PVC from coal is explored, and a comparative analysis of PVC manufacturing from alternative feedstocks, including coal, is provided. Key assumptions for PVC comparative cost analysis. The

following are key assumptions on which the analysis is based: 1. Only direct operating costs of production (i.e., raw materials, byproducts, utilities and catalyst/ chemicals) are taken into account, without considering maintenance and repairs, insurance, taxes, depreciation, administration, distribution, overhead costs, etc. Hereafter, any cost discussion concerns only direct operating costs of production. For example, “PVC cost” implies the direct operating cost of PVC production. 2. CAPEX costs are not considered. It is important to realize the dilemma of the allocation of CAPEX costs while setting up an ethylene-based PVC facility. As discussed in Part 1, a contemporary cracker facility typically allocates 15%–20% of ethylene to PVC, while the rest of the capacity is allocated to other coproducts. While this may justify a partial cost allocation to compute PVC costs, the fact that a multibillion-dollar cracker facility is needed in the first place is an important consideration. For a dedicated PVC plant of similar capacity, the cracker capacity would need to be downscaled, losing its crucial economy-of-scale advantage. On the other hand, an on-purpose PVC-only plant, via the carbide route, avoids this inherently large overall investment or high-cost-perton CAPEX (at low capacity) dilemma. 3. Since the product yields of natural gas and naphtha cracking are typically different, especially for propylene (C3=), parity has been established between the costs of both routes by adding the C3= yield in ethylene, with a nominal cost advantage given to C3=. 4. Chlorine and hydrochloric acid (HCl) production are included as parts of the PVC manufacturing process.

5. Mass balances and utility requirements have been adapted from literature. 6. Since fossil fuel prices vary considerably and are also strongly linked to geographic locations, the analysis is based on three different energy price levels, as shown in TABLE 1. Moreover, all utility and feedstock costs are linked to respective energy costs in this analysis. Analysis and results. Costs for PVC production via the naphtha and natural gas routes, respectively, are shown in TABLE 2. The PVC cost difference between the two routes largely reflects the global ethylene cost curve, which is lowest for natural gas and increases significantly for naphtha-based products.1,2 TABLE 3 shows the cost of PVC production via the coal–calciumcarbide–acetylene route. To evaluate and compare the impact of feedstocks on the manufacturing costs of PVC and relate it to coal-based PVC prices, a breakeven analysis of the PVC cost curve has been developed (FIG. 1). The upper panel shows the costs of PVC from naphtha and the corresponding costs from coal, where the breakeven point may occur. For instance, in a scenario where coal prices are $50/metric t and oil prices are above $50/bbl, PVC via the calcium-carbide route is expected to be a relatively cheaper option. Similarly, in the bottom panel of FIG. 1, with natural gas prices above $ 14/MMBtu and coal prices below $100/metric t, PVC via the calcium-carbide route is expected to be a relatively cheaper option. Breakeven costs are summarized in TABLE 4. Discussion. Due to the confluence of macroeconomic and geopolitical factors, global oil prices are projected to rise above $65/bbl ($11.30/MMBtu)3 over the long run, while coal prices are expected to remain relatively stable, at approximately $2/MMBtu.4 In such a scenario, which has already transpired in TABLE 1. Energy price scenarios Feedstock price scenarios Feedstock

Unit

Low

Medium

High

Coal

$/metric t

50

100

150

Crude oil (naphtha)

$/bbl

40

80

120

Natural gas

$/MMBtu

4

12

20

Hydrocarbon Processing | MAY 2016 53

Process Engineering and Optimization TABLE 2. Costs for PVC production from naphtha (crude oil) and ethane (natural gas) Crude oil cost Feedstock

Unit

Low

Medium

Natural gas cost High

Low

Ethylene from naphtha

Medium

High

Ethylene from ethane

Ethylene cost

$/metric t

434

867

1,301

Net raw materials

$/metric t

289

531

774

241

755

1,269

459

738

VCM from ethylene 179

Net utilities, catalyst and chemicals

$/metric t

27

54

80

18

53

88

VCM cost

$/metric t

316

585

854

197

512

826

PVC from VCM Net raw materials

$/metric t

319

588

857

199

515

830

Net utilities, catalyst and chemicals

$/metric t

48

77

105

37

70

103

PVC cost

$/metric t

367

665

962

236

585

933

1,000 900

TABLE 3. Costs of PVC via the coal–calcium-carbide–acetylene route

Coal price at $150/metric t

Coal cost

PVC cost, $/metric t

800 700

Unit

Low

Net raw materials

$/metric t

110

Coal price at $50/metric t

145

180

Net utilities, catalyst and chemicals

$/metric t

110

188

264

220

333

444

CaC2 cost

400

50

60

1,000 900

70

80 90 Crude oil price, $/bbl

100

110

120

PVC cost, $/metric t

695

1,077

1,458

Net utilities, catalyst and chemicals

$/metric t

5

10

15

1,087

1,473

700

Acetylene to VCM

Coal price at $100/metric t Coal price at $50/metric t

Net raw materials

$/metric t

392

581

770

Net utilities, catalyst and chemicals

$/metric t

22

33

44

VCM cost

$/metric t

414

614

814

VCM to PVC

400 300 200 40

$/metric t

Acetylene cost

600 500

Net raw materials

Coal price at $150/metric t

800 700

High

Calcium carbide to acetylene

300 200 40

Medium

Coal to calcium carbide

Coal price at $100/metric t

600 500

Feedstock

8

12 Natural gas price, $/MMBtu

16

$/metric t

416

617

818

Net utilities, catalyst and chemicals

$/metric t

31

42

52

PVC cost

$/metric t

447

659

870

20

FIG. 1. PVC cost curve based on naphtha (top) and natural gas (bottom). Coal-based PVC costs are denoted by horizontal lines. Coal-based breakeven costs are denoted by vertical lines. The hatched areas are viability zones for coal-based PVC for respective coal prices.

the recent past, TABLE 4 and FIG. 1 suggest that coal-based PVC is a relatively more viable route to PVC production, as compared to naphtha-based PVC. High oil costs would translate into concurrently high costs for ethylene derivatives, since 46% of global ethylene capacity of 137 MMt in 2014 was based on naphtha, potentially opening up 54 MAY 2016 | HydrocarbonProcessing.com

Net raw materials

a large market for coal-based chemicals. Analogous to oil, global natural gas prices are expected to increase in the long run, albeit at a slower pace. Cheap natural gas is available to a handful of nations globally—e.g., with the advent of shale gas over the past decade, the US natural gas industry is receiving natural gas at very low prices, translating into significant cost advantages for ethylene. However, net importers of natural gas—Asia, in particular— may find coal-derived PVC to be a cheaper option, given that average Asian LNG prices are expected to almost double by 2030.5 While India’s 96 Tcf of technically recoverable shale gas reserves6 may promise salvage, several factors are combining to create uncertainty as to when commercial large-scale produc-

Process Engineering and Optimization tion will begin, and at what price.7 These factors include political opposition to raising gas prices, the lack of infrastructure, scarcity of information on gas location, policy support, water shortage, and slow assessment of the accessibility and size of gas reserves. Until commercial large-scale production can begin, Indian natural gas prices are expected to be largely dominated by imports. From the perspective of manufacturing PVC from coal, four key considerations are worth noting: 1. Adoption of existing carbide production processes to Indian coal, which has high ash content 2. Potential process improvements and energy efficiency gains to the carbide acetylene route 3. Reduction of the consumption of the mercury chloride catalyst used to convert acetylene to VCM, and its eventual replacement with mercury-free catalyst 4. Moving to entirely new processes, either for carbide production from low-rank coals, like the oxythermal process, or processes that entirely bypass carbide production to produce acetylene directly, like the plasma arc process. Given their high ash content, a binding need exists to adapt Indian low-rank coal feedstock for calcium carbide production. A variety of pre-utilization technologies for upgrading of lowrank coals exists. These technologies are capable of reducing ash, moisture and sulfur content.8–10 Technologies to address AMETEK 13914 Sulfur 1 4/5/13 9:10 AM the issue of highXRT-XRF ash content in Analyzer_Layout Indian coal are under develop-

A D V A N C E D

S U L F U R

ment—for example, the organo-refining and coal leaching processes, with demonstration and pilot plants under construction.11,12 The cost-effective development and adoption of such technologies will be an important step toward the production of coal-based chemicals in India. Secondly, PVC cost is most sensitive to acetylene yield, coal feedstock and energy costs. Depending on purity and process, approximately 3 metric t–3.6 metric t of CaC2 are required per t of acetylene, which corresponds to a yield of 303 l–252 l of acetylene gas per kg of calcium carbide, respectively. Also, electricity costs constitute a significant portion of calcium carbide production costs, as about 3.5 MWh of electricity is consumed per t of CaC2. While attempts have been made, particularly in China, to increase the process efficiency, considerable room for improvement is expected given that the process parameters are largely of World War II vintage. Process improvements, such as bigger furnaces and optimization of feed particle size,13 could help bring about better TABLE 4. Breakeven cost for coal-based PVC compared to naphtha and natural gas feedstock prices Coal price, $/metric t 50

Breakeven point prices Crude oil, $/bbl

Natural gas, $/MMBtu

51

8.8

100

79

13.7

150 1 Page

107

18.5

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Process Engineering and Optimization

TRI-CON

TRI-CHECK

activated charcoal. At present, approximately 1.2 kg of HgCl2 catalyst is consumed per t of PVC (having 11 % average HgCl2 content).18,19 Mercury is not only a cause of environmental concerns—with its trade being limited by the international Minamata Convention—but it is also a relatively expensive heavy metal with limited global and Indian domestic supplies. Although the route for mercury-catalyst-based PVC is open to India, progress on low-mercury-content (< 6 %) and mercuryfree catalyst are key developments to look forward to from a long-term, sustainable perspective.18,20 Apropos, in China, between 2006 and 2008 alone, 1.25 MMt of PVC capacity (or approximately 8% of 2008 capacity) shifted to low-mercury-content catalyst, showing no decline in conversion rate and service life, along with greatly reduced mercury consumption.18,21 Therefore, in terms of its product function and application cost, the low-mercury-content catalyst demonstrates an effective means to curb mercury consumption and pollution.18 Moreover, the fact that several mercury-free catalyst projects are in pilot- and industrial-scale test phases indicates that the elimination of mercury-based catalysts is within reach.22 For instance, new developments of noble metal (e.g., Au, Pd) and transition metals (e.g., Cu, Pt, Rh, Ir, Ru) catalysts are underway. Chinese industry reports suggest that Au-La-Co/ C catalyst with high activity and stability show acetylene conversion > 90 %, VCM selectivity > 98.5 %, and catalyst life > 1,000 hr, with the regenerated catalyst demonstrating performance of 90% compared to a fresh catalyst.23 Lastly, apart from the incremental energy-efficient processes discussed above, several new processes are under development, such as oxythermal combustion13,24,25 and plasma arc reactors,15,23,26 which offer much simpler, energy-efficient and environmentally friendly process schemes to utilize low-rank coals.23,27 In oxythermal combustion, in addition to the coke required for the conversion reaction (which is preferably upgraded from low-rank coal), additional coke is added as a fuel and burnt in the presence of oxygen. This replaces the heat derived from

Break-even oil cost, $/bbl

100

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110

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100 Coal price, $/metric t

7 150

FIG. 2. Sensitivity analysis of PVC costs with variation in electricity consumption in calcium carbide production and acetylene yield from calcium carbide and coal costs. Three cases are explored: the Base Case, as presented in TABLE 3; Case 2, with a 10% reduction in calcium carbide consumption; and Case 3, with a further 15% reduction in electricity consumption for carbide production.

Break-even gas cost, $MMBtu

economies of scale and CAPEX and OPEX savings. State-ofthe-art simulation tools and energy-efficient designs may play a significant role in maximizing efficiency and minimizing costs. FIG. 2 develops a sensitivity analysis where the impact on PVC costs resulting from reduced consumption of calcium carbide (by 10% from the base) and electricity (by 15% from the base) are studied. Such efficiency gains are not beyond the realm of possibility; already, electricity consumption of the closed furnace process is approximately 3.2 MWh/metric t of calcium carbide, while the process to maximize acetylene yields using 3 metric t–3.2 metric t of calcium carbide per metric t of acetylene, with approximately 79% calcium carbide purity, have already been established.14,15 This analysis suggests that a 10% reduction in carbide consumption results in an analogous, approximate 8% reduction in breakeven costs. If a further 15% reduction in electricity consumption could be achieved in addition to the reduction in carbide consumption, then it would bring down the breakeven costs significantly—by approximately 14% (FIG. 2). This analysis suggests that India, with its large coal deposits, may be able to exploit the potential of coal-derived chemicals. Moreover, from a global perspective, world coal prices have fallen more than 50% since 201116 and are not expected to revive over the medium term,17 serving as an added impetus for coalbased chemicals. Thirdly, for the production of VCM, acetylene reacts with HCl in the presence of a catalyst: mercury (II) chloride on

Process Engineering and Optimization electricity, producing CaC2 along with carbon monoxide, which can subsequently be converted into chemicals via the syngas route (see FIG. 2 in Part 1).28 While this method is expected to reduce energy consumption, the development of such technology for Indian low-grade coal is needed, along with due analysis of the accompanying techno-economic aspects. Similarly, coal pyrolysis in hydrogen in a thermal plasma reactor provides a direct and cleaner route to acetylene production, bypassing the energy-intensive carbide step. This results in no direct CO2 emissions and avoids the requirement of large amounts of water. A 5-MW arc reactor has been developed in China that demonstrates total energy cost savings of about 25%, a CO2 emissions reduction of about 50%, a water requirement reduction of about 60%, and coal savings of about 40% in comparison with the conventional calcium-carbide method.26 Also, the traditional fixed-bed reactors for VCM production from acetylene are replaced by fluidized bed reactors, which allow for better control of temperature, increased VCM conversion rate (≥ 99 %), reduced mercury catalyst sublimation, decreased equipment and catalyst costs, and dramatically increased production capacity.18 These developments suggest that new-generation technologies can have a significant impact on the cost of coal-based chemicals compared to the traditional calcium-carbide route. India should explore and exploit these upcoming technologies to its advantage.

Conclusions. The comparative cost analysis herein suggests

that manufacturing fit-for-purpose quantities of coal-based PVC can be an economically viable option, especially in high-oil-price scenarios. This will also help to avoid the high CAPEX requirements and associated project risks of large cracker complexes. Moreover, since the existing process is largely reliant on vintage technologies, it provides opportunities to implement modern technological advances and gives further scope for applying energy-efficient techniques to curtail production costs, potentially further reducing breakeven costs. The fit-for-purpose scale of such plants is apt for decentralized production near coal mining belts, with consequent benefits to local communities. Moreover, while the feasibility for PVC from coal is illustrated, analogous analyses may be carried out for other ethylene-based chemicals, especially for relatively low-volume ethylene derivatives. The authors believe that the above aspects will make many coal-based chemicals alluring, particularly from the Indian perspective. These advances could make India self-sufficient, curtail its dollar-based imports, bolster a “made-in-India”-tagged chemical industry, and justify strategic investment in these alternatives to meet the long-term objectives of energy import independence. The Indian industrial and scientific communities should explore and exploit developments in the carbide world, as well as newer processes for producing acetylene directly (which avoid the carbide step altogether). Recent remarks by the India’s secretary of the Department of Chemicals and Petrochemicals on

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Hydrocarbon Processing | MAY 2016 57

Process Engineering and Optimization the potential of coal-based chemicals in India29 acknowledge the need to substitute petroleum feedstocks with coal. End of series. Part 1 of this article appeared in April 2016. LITERATURE CITED IHS, “Outlook for olefins and polyolefins…and the great energy price deflation,” 2015. 2 Deutsche Bank, “China’s coal to olefins Industry,” 2014. 3 US Environmental Information Administration (EIA), “Short-term energy outlook” and “Annual energy outlook,” 2015. 4 World Bank, “World Bank commodities forecast,” 2016. 5 BNEF, “Is the US chemicals renaissance a flash in the pan?” 2014. 6 US EIA, “Technically recoverable shale oil and shale gas resources: An assessment of 137 shale formations in 41 countries outside the US,” 2013. 7 Mukherji, B. and S. Chaturvedi, “Why India can’t unlock its shale gas,” Wall Street Journal, June 11, 2011, online: http://blogs.wsj.com/indiarealtime/2013/06/11/ why-india-cant-unlock-its-shale-gas/ 8 IEA Clean Coal Center, “Techno-economics of modern pre-drying technologies for lignite-fired power plants,” 2014. 9 IEA Clean Coal Center, “Utilisation of low rank coals,” 2011. 10 IEA Clean Coal Center, “Coal upgrading,” 2009. 11 Kumar, V., C. Banerjee, P. K. Biswas, “Optimization of solvent extraction process parameters of Indian coal,” Mineral Processing & Extractive Metall. Rev., Vol. 33, 2012. 12 Sharma, D. K. and S. Gihar, “Chemical cleaning of low grade coals through alkali-acid leaching employing mild conditions under ambient pressure,” Fuel, Vol. 70, 1991. 13 Li., G., Q. Liu and Z. Liu, “CaC2 production from pulverized coke and CaO at low temperatures—reaction mechanisms,” Ind. Eng. Chem. Res., Vol. 51, 2012. 14 Paessler, P. et. al, “Acetylene,” Ullmann’s Encyclopedia of Industrial Chemistry, 2012. 15 Schobert, H., “Production of acetylene and acetylene-based chemicals from coal,” Chemical Reviews, Vol. 114, 2014. 16 Corones, M., “Is coal’s decline permanent?” Reuters, January 6, 2015, online: http://blogs.reuters.com/data-dive/2015/01/06/is-coals-decline-permanent/ 17 Hoyle, R., “As coal prices fall, miners cut output,” Wall Street Journal, June 2, 2015, 1

58 MAY 2016 | HydrocarbonProcessing.com

online: http://www.wsj.com/articles/as-coal-prices-fall-miners-cut-output1433269071 18 China’s Ministry of Environmental Protection, “Project report on the reduction of mercury use and emission in carbide PVC production,” 2010. 19 UNEP, “Vinyl chloride monomer production,” online: http://www.unep.org /chemicalsandwaste/Mercury/PrioritiesforAction/VinylChlorideMonomer Production/tabid/4523/Default.aspx Complete literature cited available at HydrocarbonProcessing.com MAHESH MARVE is chief technology officer (CTO) and senior vice president at Tata Consulting Engineers (TCE) Ltd. He has a chemical engineering degree from ICT in Mumbai, India, with 25 years of extensive experience in refining, petrochemicals and technology management. Prior to joining TCE, he worked for Reliance Industries for 24 years. His last role at Reliance was chief of advanced technical services for Reliance’s Jamnagar refinery. He was instrumental in a significant debottlenecking of the original refinery and played a key role in concept-to-commissioning work of the second refinery at Jamnagar. S. SAKTHIVEL has been senior technologist at Tata Consulting Engineers Ltd. since 2009. He holds a BTech degree, an MTech degree and a PhD from the University of Madras, Anna University and the Indian Institute of Technology Delhi, respectively. Dr. Sakthivel has experience in chemical processes, nano and particle technology, and biofuel energy. He is the author of 12 articles in peer-reviewed journals. PARESH V. PALUSKAR is a senior technologist at Tata Consulting Engineers Ltd. He completed his PhD in physics from Eindhoven University of Technology in the Netherlands in 2008, and his MSc in sensor systems technology from FH-Karlsruhe in Germany in 2003. Dr. Paluskar has been working with Tata Consulting Engineers since 2009 in the field of renewable and sustainable energy.

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Process Engineering and Optimization H. DE PAZ CARMONA and A. BRITO ALAYÓN, University of La Laguna, Santa Cruz de Tenerife, Spain; M. ROMERO VÁZQUEZ and J. FRONTELA DELGADO, Cepsa Research Center, Alcala de Henares, Spain; J. J. MACÍAS HERNÁNDEZ, Cepsa, Santa Cruz de Tenerife, Spain

Catalytic coprocessing of used cooking oil with straight-run gasoil in a hydrotreating pilot plant A promising route to obtain bio-gasoil (bioGO) or hydrotreated vegetable oil (HVO) is the catalytic coprocessing of vegetable oil with diesel oil in a conventional hydrotreating unit. Here, the catalytic cohydroprocessing of vegetable waste cooking oil with straight-run gasoil (SRGO) in a diesel hydrodesulfurization pilot plant is analyzed. Particular attention is paid to the influence of waste oil on the pilot plant operation (increase of temperature), product quality (density at 15°C, cetane index, etc.) and the main products and byproducts formed (principally, n-paraffin and propane). A commercial NiMo/Al2O3 hydrotreating catalyst was used, as well as a high concentration of waste vegetable cooking oil in the feed (20.48 mass percent, or %m/m). Under the constant operating conditions used, an increase in bed temperature was observed in the first part of the reactor, with a total conversion of the vegetable oil triglycerides, keeping a 99.7%–99.8% sulfur elimination and a slight decrease on the denitrification capacity. The main byproducts obtained are n-paraffins with a number of carbons between 15 and 18, and light gases such as CO2, CO and propane. The presence of these byproducts means that the catalyst favors decarboxylation/decarbonylation reactions, to the detriment of hydrodeoxygenation reactions. The results of this study confirm the technical feasibility of the coprocessing of cooking oil with diesel oil in a conventional hydrotreating unit. Fossil fuel vs. biofuel. Most of the fuels used throughout

the world come from fossil origin. The increase in fossil fuel consumption is associated with population growth and with the development of increasingly industrialized societies. The use of fossil fuels also impacts the environment—above all, with an increase in greenhouse gases, such as CO2. Efforts are being made to develop new and environmentally friendly sources of energy, such as wind and solar energies, and cleaner fuels, such as biofuels.1 To reduce energy dependency, encourage the use of energy from renewable sources and reduce greenhouse gases, the European Parliament and the Council of the European Union

(EU) adopted the Directive 2009/28/EC. The directive establishes the objective of achieving a 20% share of energy from renewable sources in the EU’s total energy consumption by 2020. It also includes the objective that at least 10% of the energy consumed by transport in each member state must come from renewable sources by 2020.2 Since the German-French scientist Rudolf Diesel first began using vegetable oils as fuel for his diesel engines, it has been clear that this product of vegetable origin can be used as a real alternative to liquid fuels of fossil origin. Owing to their high triglycerides content, vegetable oils are an ideal feedstock for the production of biofuels, such as biodiesel.3 Many different types of vegetable oils can be used for this purpose, but cooking oil is a good alternative. Its use not only eliminates an environmental contaminant residue, but a combustible product of high-added value is also obtained. FIG. 1 shows the typical structure of a triglyceride.4 Transesterification is the process most often used to transform vegetable oil into fuel. In this process, a reaction between oil triglycerides and a short-chain alcohol—usually methanol—is carried out in the presence of a basic catalyst, such as NaOH or KOH, thus forming fatty acid methyl esters (FAMEs) and glycerin.5 BioGO, or HVO, is an alternative to traditional biodiesel. It consists of a biofuel formed mainly of n-paraffins, and is obtained from the catalytic hydrotreating of vegetable oil under H H

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FIG. 1. Example of a triglyceride structure. Hydrocarbon Processing | MAY 2016 59

Process Engineering and Optimization Therefore, the coprocessing of vegetable oil and diesel oil in a diesel hydrodesulfuron onylati ization unit is postulated as a suitable methDecarb CO H2 O O O O od to obtain a biofuel of paraffinic chartion la =R1 O O O O R2= H2 R1 R2 H2 y n acter. This biofuel integrates well into the o DecarbH H O Diglycerides 2 2 desulfurized product diesel oil, improving n-C18 Monoglycerides iso-C n-C16 Isomerization iso-C18 Acids R3= R3 O O some of its main properties, such as cetane 16 Hydrogenation/ Propane Waxes index or density.10,11 dehydration O O Hydrogenated triglycerides Vegetable oil (triglycerides) Here, the aim is to analyze, in a diesel hydrodesulfurization pilot plant, the catalytic FIG. 2. Chemical reactions occurring during the hydrotreating of vegetable oil. coprocessing of vegetable cooking oil and diesel oil, focusing on the following aspects: • Influence of the coprocessing of vegetable cooking oil TABLE 1. Results of analyses performed on cooking oil with diesel oil on the operation of the hydrotreating Analysis Result pilot plant for the desulfurization of diesel oil Density at 15°C, kg/l 0.922 • Influence of the coprocessing of vegetable cooking oil 43.54 Viscosity at 40°C, mm2/s with diesel oil on the properties of the desulfurized product diesel oil obtained in the hydrotreating pilot plant Acid number, mg KOH/g 2.87 • Analysis of liquid and gaseous products and byproducts Sulfur content, mg/Kg 4.1 formed as a result of catalytic coprocessing of vegetable Karl Fischer water, ppm 555 oil, consisting mainly of n-paraffins and light gases, Elemental analysis, % m/m – such as C3H8 , CO and CO2. CO 2

iso-C17 n-C15 n-C17 Isomerization iso-C15 Propane Cracking lighter alkanes

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76.91

Hydrogen

11.93

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< 0.01 – 0.1

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4.4

Fe

< 0.1

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< 0.1

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