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PETROCHEMICALS FCC can be used to produce olefins and aromatics on-purpose ®
HydrocarbonProcessing.com | NOVEMBER 2014
MAINTENANCE Process equipment may be vulnerable to brittle fractures
REFINING DEVELOPMENTS Ultra-fine solids need aggressive treatment to protect heat-transfer networks
SPECIAL REPORT:
Plant Safety and Environment
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NOVEMBER 2014 | Volume 93 Number 11 HydrocarbonProcessing.com
36
41 SPECIAL REPORT: PLANT SAFETY AND ENVIRONMENT 37
Heater training improves safety and operations D. Basquez, M. Baker, C. Baukal and R. Luginbill
41
Environmental regulations: How much do they really cost? K. Allen
47
Consider true zero-emission packing for reciprocating compressors T. Lindner-Silwester
55
An examination of three recent accidents in the downstream industry
DEPARTMENTS 4 10 19 91 93 94 96 98
Industry Perspectives News Industry Metrics Innovations Events Marketplace Advertiser Index People
J. C. Jones
59
Design a safe hazardous materials warehouse R. Benintendi and S. Round
MAINTENANCE AND RELIABILITY 67 Is your plant vulnerable to a brittle fracture?
COLUMNS 9 Editorial Comment Wanted: Future leaders
21
Can integrally geared compressors be successfully used with variable speeds?
B. Macejko
23 PETROCHEMICALS 79 Optimize olefins and aromatics production W. Letzsch and C. Dean
REFINING DEVELOPMENTS 85 Manage the impacts of high-solids crude oil more effectively
Automation Strategies Virtualization in process automation systems
25
Global European refining—Cornered, with no way out?
29
Automation Safety It is easier to sit on the couch than go exercise
G. Hoffman and D. Longtin Cover Image: In a turnaround, the 46-year-old coke drums at Chevron’s El Segundo, California refinery were replaced. This project involved 15 major lifts totaling 8.3 MM aggregate lb in just 15 days. Six old coke drums weighing 400,000 lb each were pulled and replaced by six improved 600,000-lb drums. Nooter Construction, the St. Louis company with a long history of coke drum turnarounds, installed the original coke drums in 1968 and was responsible for the removal and installation of the new coke drums. See the full article on the El Segundo refinery coke drum project in HP December 2014. Photo courtesy of Nooter Construction.
Reliability
31
Boxscore Construction Analysis Vietnam: Reversing the tide of refined imports
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Industry Perspectives
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EDITORIAL
Cyber bullies continue to be a menace Cyber security is still a critical issue that the hydrocarbon processing industry (HPI) must address. Speaking at the American Fuel and Petrochemical Manufacturers Q&A and Technology forum in Denver, Colorado, Mark Bristow, chief of the Industrial Control System Cyber Emergency Response Team (ICSCERT), US Department of Homeland Security, emphasized that cyber attacks are increasing and becoming more sophisticated. In short, the threat of a cyber breach to a plant control system is more likely than in past years. Industry data collected by ICS-CERT show that more incidents are occurring by outsiders probing for company information, including control systems. While you were sleeping. Bristow stressed that such breaches will not be dramatic events with a total system/network meltdown. Staff members will most likely notice them as minor or “weird” blips in plant data. Furthermore, these breaches will require plant analysts to drill into the system in order to uncover the true extent of the breaches and to identify the damage. Too often, victims of cyber attacks are not aware of the attacks on their systems, and they are often notified by ICS-CERT on the security breach. HPI facilities are relying on networks and data-collection systems to move information throughout the corporation. These systems must be open to be efficient. The outlook. “Things will get worse before getting better,” says
Bristow. Stuxnet, Heartbleed, Mariposa, Energetic Bear and Dragonfly are just a few of the highly publicized viruses used in cyber attacks. These attacks can occur outside, and within, the network. Disgruntled employees, UBS devices and vendor’s infected laptops are just a few ways that networks can be infected. You can’t fix stupid. There are steps that companies can set in
motion to protect themselves. Cyber risks should be part of the organization’s risk-management goals. Also, companies should get back to basics. The best practices are 1) know who is on the system, 2) prepare a recovery program and have readily accessible backup resources and 3) practice the recovery programs.
Editor Managing Editor Reliability/Equipment Editor Online Editor Associate Editor Director, Data Division Contributing Editor Contributing Editor Contributing Editor
Stephany Romanow Adrienne Blume Heinz P. Bloch Ben DuBose Helen Meche Lee Nichols Loraine A. Huchler William M. Goble ARC Advisory Group
MAGAZINE PRODUCTION / +1 (713) 525-4633 Vice President, Production Manager, Editorial Production Artist/Illustrator Graphic Designer Manager, Advertising Production
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SUBSCRIPTIONS Subscription price (includes both print and digital versions): Print—One year $239, two years $419, three years $539. Digital format—One year $239. Airmail rate outside North America $175 additional a year. Single copies $35, prepaid. Because Hydrocarbon Processing is edited specifically to be of greatest value to people working in this specialized business, subscriptions are restricted to those engaged in the hydrocarbon processing industry, or service and supply company personnel connected thereto. Hydrocarbon Processing is indexed by Applied Science & Technology Index, by Chemical Abstracts and by Engineering Index Inc. Microfilm copies available through University Microfilms, International, Ann Arbor, Mich. The full text of Hydrocarbon Processing is also available in electronic versions of the Business Periodicals Index.
ARTICLE REPRINTS If you would like to have a recent article reprinted for an upcoming conference or for use as a marketing tool, contact Foster Printing Company for a price quote. Articles are reprinted on quality stock with advertisements removed; options are available for covers and turnaround times. Our minimum order is a quantity of 100. For more information about article reprints, call Rhonda Brown with Foster Printing Company at +1 (866) 879-9144 ext. 194 or e-mail
[email protected]. Hydrocarbon Processing (ISSN 0018-8190) is published monthly by Gulf Publishing Company, 2 Greenway Plaza, Suite 1020, Houston, Texas 77046. Periodicals postage paid at Houston, Texas, and at additional mailing office. POSTMASTER: Send address changes to Hydrocarbon Processing, P.O. Box 2608, Houston, Texas 77252. Copyright © 2014 by Gulf Publishing Company. All rights reserved. Permission is granted by the copyright owner to libraries and others registered with the Copyright Clearance Center (CCC) to photocopy any articles herein for the base fee of $3 per copy per page. Payment should be sent directly to the CCC, 21 Congress St., Salem, Mass. 01970. Copying for other than personal or internal reference use without express permission is prohibited. Requests for special permission or bulk orders should be addressed to the Editor. ISSN 0018-8190/01.
President/CEO Vice President Vice President, Production Editor-in-Chief Business Finance Manager
FIG. 1. The HPI is still vulnerable to cyber attacks and must take precautions. Source: Hydrocarbon Processing, October 2013.
Part of Euromoney Institutional Investor PLC. Other energy group titles include: World Oil and Petroleum Economist. Publication Agreement Number 40034765
4NOVEMBER 2014 | HydrocarbonProcessing.com
John Royall Ron Higgins Sheryl Stone Pramod Kulkarni Pamela Harvey
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Enhanced and Including More Data Than Ever Before.
HPI Market Data 2015 is the hydrocarbon processing industry’s most trusted forecast of capital, maintenance and operating expenditures for the petrochemical, refining and natural gas/ LNG industries. Produced annually by the editors of Hydrocarbon Processing and the Construction Boxscore Database, and featuring data provided by governments and private organizations, this comprehensive resource provides comprehensive and toplevel insight into HPI market trends, spending and activity. HPI Market Data 2015 features: • Global spending in the refining, petrochemical and gas processing sectors • Capital, maintenance and operating spending broken out by region • An exploration of the Impact of local and national trends on spending and activity • An exploration of changing markets and demand within the global HPI, with discussion of emerging markets • More than 40 tables and 100 figures, including information and data collected from governments and private organizations • Expanded editorial analysis of worldwide economic, social and political trends driving HPI activity across all sectors
Obtain HPI Market Data 2015 to: • Plan strategically for 2015 and beyond • Recognize global and regional market trends • Locate new business opportunities • Discover how spending trends by sector will impact your company
Call +1 (713) 520-4426 or visit GulfPub.com/2015HPI.
Get Reliable, Accurate Information to Drive your Strategic Decision-Making for 2015 and Beyond. The global hydrocarbon processing industry is larger and more competitive than ever before. HPI Market Data 2015 provides trusted forecast data and market intelligence to give you the tools you need to make strategic decisions and recognize new market opportunities in North America and throughout the world. We invite you to utilize this market analysis and insight to optimize your budgeting and strategic planning. Expenditures are Broken out for the Local and Global HPI by the Following Categories: • HPI economics
• Natural gas/LNG
• Petrochemicals
• Refining
Highlights include: • The HPI’s capital, maintenance and operating budgets are expected to exceed $324 B in 2015, representing an all-time high. • Global announced project spending continues to surge. • New and existing refineries will be designed to handle unconventional feedstocks, such as NGLs, bitumen, heavy oil, and shale, and more than 53% of the new capacity will be constructed in developing nations. • The most significant expansions in the petrochemical sector will be in developing countries in Asia-Pacific, Latin America and the Middle East. • Growth on both the supply and demand sides of the gas processing plants has resulted in the announcement of billions of dollars of capital investments across the world. • Investments include the construction of LNG export and receiving terminals, cryogenic and gas processing plants, fractionators, pipelines and storage facilities
Included in the Book are Answers to such Critical Questions as: • Where are the global hot spots of construction activity? • What are the latest developments in the petrochemical industry? • What types of fuels will become increasingly part of everyday use? • Where is project spending ongoing for the downstream sectors? • What are the future feedstock trends for refineries and petrochemical plants? • How will environmental rules change future transportation fuel production slates?
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The hydrocarbon processing industry is undergoing an incredible expansion wave and new business opportunities; all are supported by new crude oil and natural gas resources,” said Stephany Romanow, editor of Hydrocarbon Processing. “In particular, the petrochemical industry is experiencing a renaissance period as shale gas and continued economic growth result in significant new project announcements globally.
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Editorial Comment
STEPHANY ROMANOW, EDITOR
[email protected]
Wanted: Future leaders The hydrocarbon processing industry (HPI) has known for some time that a great shift change is eminent. The experienced engineers, chemists and crafts hired in the 1970s and 1980s are reaching retirement age very soon, and they are ready to start their well-earned second chapters. Besides the loss of the experience that seasoned technical experts will take with them upon retirement, the HPI will also be short on future leaders. Where do you find new engineers, operators, and skilled craft workers? The choices for employment have dramatically changed since the 1970s. Young talented workers have more employment choices. The HPI will also be in direct competition with other industries to attract staff. Who could be leaders for your organization? Some choices include:
• The individuals with the most education • The most charismatic individuals of the organization • The individuals at the highest job levels of the organization or group • The individuals who use control and manipulation to get results. Actually, this list is just a myth. Leaders can be developed within the organization. They do not need to have the highest level of education or the top job within the group. They do not have to be the most charismatic. Manipulation/control tactics can gain some short-term results, but they will not lead to fruitful achievements over the long term. Todd Monette, plant manager for LyondellBasell’s facility in Houston, Texas, recently addressed the AFPM’s Q&A and Technology Forum in Denver, Colorado. Monette emphasized that HPI organizations must create their own leadership within their facilities and they must begin now. The future leaders of the HPI are the new workers now entering the workforce. These young people have different needs and expectations than the
seasoned veterans. Thus, new training/ mentoring programs for young leaders must be developed. All employees can contribute leadership to the organization. In the areas of safety and environment, all employees can, and must, contribute effectively to health, safety and environmental (HSE) goals in various ways, such as managing themselves, supporting their co-workers and embracing their job responsibilities to meet the company’s goals.
INSIDE THIS ISSUE safety 36 Plant and environment. Maintaining proper safety and environmental performance is a multi-faceted endeavor. Numerous government regulations drive standards for improved operations of HPI facilities. Environmental performance, just like safety, is a 24/7 task; there is no single solution. While improved
Empowerment. As leaders, employees
must be empowered to identify and report problems. Even more important, they must know that corrective actions will take place to remedy the situation. Open dialogue is particularly important. It is great to have monthly safety meetings. However, it is more important that the staff believes that all members of the plant and company share, and work toward, the same goals daily. An energized employee is more valuable than any innovative device. Technology has a very special place in the HPI, but people will be responsible on how well that plant operates or how well that process equipment is operated and maintained.
training and adherence to safety and operating practices can enhance plant performance, more improvement is needed.
67 Maintenance and reliability. Much of the process equipment operating today was designed to construction codes that did not require a formal evaluation for low-temperature considerations. Metal temperature highly influences the fracture toughness of construction materials of plant equipment. At low temperatures, some materials are more susceptible to fracture. Methods to identify potential
Maintenance, crafts and operators Process unit/shift foreman Craft foreman
Process/project engineers
Superintendent Managers of operations and engineering maintenance and technical service
Plant manager
brittle-fracture conditions in process equipment are discussed.
79 Petrochemicals.
The fluid catalytic cracking
(FCC) process can produce a wide range of products. FCC technology was introduced almost 72 years ago to facilitate the production of high-octane fuels, and many units are still operated
FIG. 1. Leadership profile for HPI facility.
for that purpose. However, the FCC process can also be used to produce
An expanded version of Editorial Comment can be found online at HydrocarbonProcessing.com.
petrochemicals. The authors discuss the various FCC operational changes that can enhance propylene yield. Hydrocarbon Processing | NOVEMBER 20149
| News EPA: GHG emissions from refineries increase 1.6% in 2013 The US Environmental Protection Agency (EPA) has released its fourth year of GHG data, with over 8,000 large facilities reporting 2013 emissions. The report data is broken down by industrial sector, geographical region and individual facilities. According to the EPA, reported emissions from large industrial facilities were 20 metric MMt higher (or 0.6%) than in the previous year, mainly driven by the coal and power plant industries. Power plants (1,550 facilities) emitted more than 2 B metric tons of GHG, an increase of more than 13 MMt compared to 2012. Petroleum and natural gas systems reported 224 metric MMt of GHG emissions, a decrease of 1% from the previous year. Refineries were the third-largest stationary source, with 177 metric MMt of GHG emissions, a 1.6% increase from the previous year.
HP STAFF
[email protected]
News
Cellulosic ethanol enters the laundry detergent market DuPont and Procter & Gamble are collaborating to use cellulosic ethanol in North American laundry detergent. Tide will be the first brand in the world to blend cellulosic ethanol in a scalable and commercial way. Ethanol has long been a key ingredient in the detergent formulation, allowing for stability of the detergent formula and better washing performance. The substitution of cornbased ethanol with cellulosic ethanol is the latest innovation in the companies’ 30-year partnership. DuPont will produce the cellulosic ethanol at the company’s new biorefinery, which is under construction in Nevada, Iowa. Once completed, the plant will produce 30 MMgpy of cellulosic ethanol, a process that DuPont claims has zero net carbon emissions. The detergent, combined with cellulosic ethanol, will allow for the repurposing of over 7,000 tons of agricultural waste a year. This is the equivalent to the power needed to do all the washing in homes across California for over a month.
Dow Chemical unveils apprenticeship program Dow Chemical will launch a US apprenticeship pilot program at various Dow sites across the nation in 2015. This pilot program supports a major initiative of the Advanced Manufacturing Partnership (AMP), an effort to secure US leadership in emerging technologies, create high-quality manufacturing jobs, and enhance the US’ global competitiveness. The launch advances the goals and national workforce development efforts of the AMP Steering Committee 2.0, a renewed, cross-sector, public/private partnership. As part of AMP 2.0, Dow, Alcoa and Siemens have formed a coalition to build regional apprenticeship models and create an instructional playbook for other
US-based companies seeking to develop apprenticeship programs. In addition to sharing best practices gained from over 40 years of experience offering apprenticeship programs in Europe, Dow joined the coalition in committing to pilot key playbook concepts at company facilities in the US. Within the next five years, through its US Apprenticeship Program, Dow says it aims to develop a highly skilled technical workforce that will support business growth and advance skill development in manufacturing and engineering. Dow’s US program will offer participants two to four years of training and on-the-job experience in some of the most sought-after and highest-earning technical specialties in the industry. Through partnerships between Dow and local community colleges, the program will combine classroom training and hands-on learning to build in-depth skills and experience. Upon completion of the program, apprentices will be evaluated for employment opportunities at Dow. Dow says it will pilot its US Apprenticeship Program at five of its manufacturing sites in Texas (Freeport, Bayport, Deer Park, Seadrift and Texas City), as well as at its manufacturing sites in California; Pittsburgh, Pennsylvania; and Chicago, Illinois area. The company expects to hire approximately 60 apprentices for the pilot program in 2015, training them for roles as chemical process operators, instrumentation and equipment technicians and analyzer technicians. Fueled by cost-advantaged energy and raw materials, Dow and other US-based manufacturers have, in recent years, announced plans to expand their US operations and create new jobs. A recent IHS Global Insight study estimates the creation of 630,000 new jobs in US manufacturing as a result of the US shale gas boom, with 2,800 to 3,500 indirect jobs also created due to natural gas and shale exploration. However, one of the greatest challenges facing industry today is a shortage of candidates with the technical skills necessary to qualify for key roles now available
in the manufacturing sector. According to the study, today more than 600,000 jobs, most of them technical, are unfilled despite high US unemployment statistics.
New chemical plants to boost natural gas demand by 4% in 2015 Industrial natural gas consumption has grown steadily since 2009, as low prices have been attractive to customers who use natural gas as a feedstock for chemical production. Methanol plants and ammoniaor urea-based fertilizer plants are among the most natural gas-intensive industrial end users, with many using 100 MMcfd or more. Low gas prices and proximity to shale resources have led to proposals for several new industrial facilities, the details of which were included in a US Energy Information Administration (EIA) report. Two methanol plants are set to begin service this year: a small facility in Pampa, Texas and one in Geismar, Louisiana. A handful of fertilizer plants have begun service, and an expansion is planned at a plant near Beaumont, Texas later this year. Many plants are on the Gulf Coast, but proximity to shale development in the Marcellus, Bakken and Niobrara areas have led to proposals for facilities outside of Texas and Louisiana. Two large facilities coming online in 2015—a methanol plant in Clear Lake, Texas and a fertilizer/ urea plant in Wever, Iowa—will support continued growth in industrial demand. The EIA projects that growth in industrial demand will continue through 2015, with consumption averaging 21.3 Bcfd in 2014 and 22.1 Bcfd in 2015, a 4% increase. Developers hope to take advantage of abundant natural gas in North Dakota’s Bakken shale. Two ammonia-based fertilizer plants are proposed for North Dakota for 2018. Farm-owned cooperative CHS Inc.’s proposed plant in Spiritwood and Northern Plains Nitrogen’s proposed plant for Grand Forks are both in the permitting stage. Both have expected production of 2,400 tpd of ammonia and would use nearHydrocarbon Processing | NOVEMBER 201411
News ly 100 MMcfd of natural gas each, according to Bentek Energy estimates. While most of the proposed methanol plants are on the Gulf Coast, two are proposed for 2018 in the Pacific Northwest. Northwest Innovation Works, a Chinese company, is planning two methanol facilities on the Columbia River in Washington and Oregon. The company hopes to export methanol produced in the US to Asian markets.
ISA100 wireless standard gains final IEC approval The International Society of Automation (ISA) announced that ANSI/ ISA-100.11a-2011, “Wireless Systems for Industrial Automation: Process Control and Related Applications,” has been unanimously approved by the International Electrotechnical Commission (IEC) as an international standard and will be pub19
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lished by year’s end with the designation IEC 62734. Since its initial approval by the American National Standards Institute (ANSI) in 2011, ISA-100.11a-compliant devices have found wide global use, with more than 130,000 connected devices reported in 2012 and over 1 B hours of operational service at customer sites. ISA-100.11a was originally developed with international collaboration following ISA’s open consensus process as accredited by ANSI, which requires participation and voting by experts from multiple stakeholder groups, including end users in addition to suppliers—ensuring that all views and needs are taken into account. ISA100 voting members, including those from enduser companies deploying wireless systems in real-world industrial applications, overwhelmingly voted to approve ISA-100.11a. ISA-100.11a/IEC 62734 provides reliable and secure wireless operation for monitoring, alerting, supervisory control and open-loop and closed-loop control applications. The standard defines the protocol suite, system management, gateways and security specifications for wireless connectivity with devices supporting limited power consumption requirements. The focus is to address the performance needs of process manufacturing applications, which include monitoring and process control where latencies on the order of 100 ms can be tolerated, with optional behavior for shorter latencies. IEC 62734 utilizes Internet Protocol version 6 (IPv6), adheres to the OSI model and uses object technology—all necessary to support the Industrial Internet of Things (IIOT). In addition, the standard fully supports the ETSI EN 300 328 v1.8.1 EU specification taking effect in 2015. Industrial wireless products, branded as ISA100 Wireless, already meet this requirement.
US fuel economy reaches all-time high New vehicles achieved an all-timehigh fuel economy in 2013, according to data released from the US EPA. Modelyear 2013 vehicles achieved an average of 24.1 miles per gallon (mpg), a 0.5-mpg increase over the previous year and an increase of nearly 5 mpg since 2004. Fuel economy has now increased in eight of the last nine years. Average carbon dioxide emissions are also at a record low of
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News • Nissan achieved the greatest improvement in average fuel economy and GHG reductions • SUVs achieved the greatest improvement in all classes of new personal vehicles. The EPA and the US Department of Transportation have implemented standards projected to double fuel economy by 2025 and cut vehicle GHG emissions by half. The EPA estimates these standards
369 g/mi in model-year 2013. Some additional findings from the report: • The recent fuel economy improvement is a result of automakers’ rapid adoption of more efficient technologies, such as gasoline directinjection engines, turbochargers and advanced transmissions • Mazda vehicles averaged the highest fuel economy and lowest greenhouse gas (GHG) emissions
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will save US families more than $8,000 in fuel costs per vehicle by 2025. The standards are projected to reduce US oil consumption by more than 2 MMbpd by 2025.
The Major Economies Forum meets in New York The Major Economies Forum on Energy and Climate met in New York City at the end of September. The meeting was chaired by US Deputy National Security Advisor Caroline Atkinson and attended by ministers and officials from the 17 major economies, with ministers and officials from Denmark, Grenada, the Marshall Islands, New Zealand, Norway, Peru, Poland, Saudi Arabia, Singapore and Tanzania. The executive secretary of the United Nations Framework Convention on Climate Change (UNFCCC) and the co-chairs of the Durban Platform for Enhanced Action also attended. In her opening remarks, Ms. Atkinson highlighted the need to stay on track for a robust climate agreement in Paris in 2015. Participants then received a readout on the third Climate Finance Ministerial meeting from Norwegian Minister of the Environment Kristine Sundtoft. For the first time, the meeting included a foreign minister’s session, hosted by US Secretary of State John Kerry. Foreign ministers stressed the urgency of addressing climate change and noted the links between climate change and global, national and energy security. They exchanged views on how best to build upon the momentum regarding climate change and how best to harness political will. They also stressed the need to approach the Paris agreement constructively and cooperatively.
Impact of fuel price increases on the aviation industry A recently commissioned US General Accounting Office (GAO) report found that commercial passenger airlines have taken a number of steps aimed at mitigating the financial impact of the increases in fuel prices since 2002, according to aviation associations and government officials. Some airlines restrained the growth of their domestic seat capacity, while others have reconfigured their fleets to make them more fuel efficient,
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News conducted flight and ground operations more efficiently, improved aerodynamics and reduced the weight of items onboard. Airlines have also used fuel hedging, in which they enter into contracts that are designed to provide more certainty over the future price of fuel. Partly in response to financial pressures from increases in fuel prices, some airlines have merged or entered into route-sharing deals with other airlines. While these efforts coin-
cided with increased fuel prices, an airline trade association identified other factors that contributed to these changes, such as a weak economy. The GAO report cited aviation associations and government officials that said fuel price increases have contributed to a decline in general aviation activity (which is all non-scheduled air service), including the hours flown in general aviation aircraft. This decline in
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activity adversely affected general aviation airports and the services provided at these airports (such as reductions in flight training and refueling). For these activities and services, the price of fuel is not the only factor that contributed to this decline. According to associations that represent general aviation interests, a weak economy and other factors, such as increased security requirements, also contributed to the decline. The GAO’s analysis shows that US Airport and Airway Trust Fund revenues would grow marginally higher if fuel prices increased 200% from 2010–2024, when compared to the growth under present forecast fuel price increases, because the projected increase in per-ticket revenue would outweigh the projected decrease in the number of tickets sold. However, the models for this analysis are limited and have greater uncertainty for later years. The GAO contracted with IHS Global Insight to produce a model of macroeconomic variables, such as real gross domestic product (GDP), if fuel prices increased by 200% from 2010–2024 and the GAO provided these outputs to the US Federal Aviation Administration (FAA). The FAA used the results and the rise in fuel prices to produce an alternative forecast of passenger traffic, which the GAO then used to simulate annual trust fund revenues from 2010–2024 if fuel prices increased by 200% over that time. While this analysis allowed the GAO to estimate how a hypothetical increase in fuel prices may affect growth in the trust fund, it is not a prediction of how the trust fund will actually grow in the next 10 years. Study explanation. The aviation industry is vital to the US economy. Passenger airlines directly generate billions of dollars in revenues each year, and communities depend on passenger airlines to help connect them to the national transportation system. Between 2002 and 2013, jet fuel prices more than quadrupled from $0.72/gal to $2.98/gal, and general aviation gasoline prices more than tripled from $1.29/gal to $3.93/gal in nominal terms. The Airport and Airway Trust Fund is funded principally by excise taxes on ticket purchases, aviation fuel and cargo shipments as well as interest revenue. Section 808 of the FAA Modernization and Reform Act of 2012 required the GAO to study the impact of increases in
News aviation fuel prices on the trust fund and on the aviation industry in general.
Booming Chinese market for flue gas desulfurization and pumps China will add more megawatts (MW) of flue gas desulfurization (FGD) between 2014 and 2020 than exist in the US. By 2020, China will have 50% of all the FGD systems in the world (TABLE 1). This prediction was released in a recent forecast by McIlvaine Co. China plans to install FGD on new power plants and to retrofit older power plants without FGD. There are 96,000 MW of power plants targeted for the fiveyear period. Some of this new power plant capacity is to meet the rising energy needs of the country. Some will replace existing coalfired boilers in residences, commercial buildings and industry. More than 600,000 small coal-fired boilers will be retired. Most new FGD systems will produce wallboard-quality gypsum, using lime-
stone reagents. Dry scrubbing using lime is becoming more popular in the arid areas where water is scarce. McIlvaine is recommending that Chinese utilities consider two-stage limestone scrubbing systems in which the first-stage creates hydrochloric acid (HCl). This acid can be used to leach gallium and other rare earths from the fly ash. Since China is spending billions on technologies to leach metals from fly ash, the one-step scrubbing and leaching process is vital. On a related note, McIvaine is also reporting that industrial pump sales in China will exceed $9 B in 2015. The exports will exceed imports by approximately $1 B, so total industrial pump production is over $10 B. Higher technology pumps are produced by international JVs and obtained by imports. There are 20 large domestic producers accounting for sales of just under $2 B. Some of the JV international companies are exporting pumps from China. As a result, the sales by this group are several billion dollars per year. The energy sector will contribute much of the growth in the coming years. China
TABLE 1. China’s FGD, MW Classification
2014
2020
659,971
896,555
FGD retirements
–1,000
–1,000
New construction FGD
42,500
25,500
Retrofits
13,004
11,316
Total new FGD
55,504
36,816
Existing FGD
has embarked on a huge coal-to-chemicals and fuels program. If all planned projects are completed, China would be converting 10% of the coal produced in the world into synthetic natural gas, gasoline and chemicals. The larger plants will use more than 20,000 pumps each. China continues to build new coalfired power plants at the rate of 50,000 MW/yr. Existing power plants are being retrofitted with NOx control. These retrofits require pumps for ammonia injection. Expenditures for FGD are larger than the expenditures at all the countries of Europe combined. These systems require both water and slurry pumps.
Industrial Bolting Systems Advanced Tensioning Systems Hydraulic Torque Wrenches Pneumatic Multipliers Electric Multipliers Hands-Free Safety Time Saving Simplicity Industry-Leading Accuracy Patented Innovations
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Hydrocarbon Processing | NOVEMBER 201417
The Clock Is Ticking.
Looming NSPS Subpart Ja and other federal, state, and local regulations mean rethinking your entire flare system. Stay ahead of the curve – and the deadlines – by adding a ZEECO® Flare Gas Recovery System. Zeeco engineers flare gas recovery systems that are world-renowned for performance, reliability, and extra-long life. You’ll conserve fuel, operate more energy efficiently, and capture waste gases required to comply with EPA regulations. Zeeco puts more than 35 years of advanced engineering experience to work in every system we design. So, even though the clock is ticking, there’s still time to make the right choice, right now.
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HP STAFF
[email protected]
Industry Metrics
20
5
Aug 14
Sept 14
Aug 14
Sept 14
July 14
July 14
June 14
Selected world oil prices, $/bbl
May 14
Feb 14
Mar 14
April 14
Japan Singapore
Jan 14
US EU 16
Sept 13
Production equals US marketed production, wet gas. Source: EIA.
US Gulf cracking spread vs. WTI, 2013–2014*
World liquid fuel supply and demand, MMbpd
Sept 14
Aug 14
July 14
June 14
May 14
Mar 14
Jan 14
April 14
Sept 14
Aug 14
July 14
June 14
May 14
April 14
2015-Q1
Mar 14
2014-Q1
-20 Feb 14
2013-Q1
0 -10 Jan 14
-1.0 -1.5
10
Dec 13
-0.5
Gasoil, 10 ppm S Fuel oil, 1% S
20
Nov 13
0.0
Prem. gasoline unl., 98 Jet/kero
30
Oct 13
0.5
40
Sept 13
1.0
Gasoil/diesel, 0.05% S Fuel oil, 180c
Rotterdam cracking spread vs. Dubai, 2013–2014* Cracking spread, US$/bbl
Forecast
2.0 1.5
Stock change and balance, MMbpd
96 Stock change and balance 94 World demand 92 World supply 90 88 86 84 82 80 78 2009-Q1 2010-Q1 2011-Q1 2012-Q1
Dec 13
60 Source: DOE 45 A S O N D J F M A M J J A S O N D J F M A M J J A 2012 2013 2014
Nov 13
W. Texas Inter. Brent Blend Dubai Fateh
75
Oct 13
90
Prem. gasoline unl. 93 Jet/kero
Cracking spread, US$/bbl
105
60 50 40 30 20 10 0 -10 Sept 13
120
Feb 14
135 Oil prices, $/bbl
June 14
70 60 50
Dec 13
A S O N D J F M A M J J A S O N D J F M A M J J A 2012 2013 2014
Supply and demand, MMbpd
May 14
April 14
Mar 14
Feb 14
Jan 14
Dec 13
Sept 13
1 0
80
Nov 13
2
90
Oct 13
3 Monthly price (Henry Hub) 12-month price avg. 12-month Productionprice avg.
100 Utilization rates, %
4
Global refining utilization rates, 2013–2014* Gas prices, $/Mcf
Production, Bcfd
6
Nov 13
0 -5
7 5
Brent, Rotterdam
10
US gas production (Bcfd) and prices ($/Mcf) 80 70 60 50 40 30 20 10 0
Arab Heavy, US Gulf LLS, US Gulf
WTI, US Gulf Dubai, Singapore
15
Oct 13
An expanded version of Industry Metrics can be found online at HydrocarbonProcessing.com.
Global refining margins, 2013–2014* Margins, US$/bbl
Mid–October crude oil prices slumped as the International Energy Agency (IEA) announced a slight increase in global oil demand by 700 Mbpd. In contrast, oil production is forecast to increase by 900 Mbpd bolstered by OPEC and non–OPEC countries. The shift in demand is occurring at the same time as several mega–refineries in the Middle East come online.
Source: EIA Short-Term Energy Outlook, October 2014.
Singapore cracking spread vs. Brent, 2013–2014* Brent Dated vs. sour crudes (Urals and Dubai) spread, 2013–2014*
01 May 08 May 15 May 22 May 29 May 05 June 12 June 19 June 26 June 03 July 10 July 17 July 24 July 31 July 07 Aug 14 Aug 21 Aug 28 Aug 04 Sep 11 Sept 18 Sept 25 Sept 02 Oct
Gasoil, 50 ppm S Fuel oil, 180 CST, 2% S
Sept 14
Aug 14
July 14
June 14
May 14
April 14
Mar 14
Feb 14
-2 -4
Prem. gasoline unl. 92 Jet/kero
Jan 14
0
0
-10 -20
Dec 13
2
10
Nov 13
Dubai Urals
Oct 13
4
20
Sept 13
Light sweet/medium sour crude spread, US$/bbl
6
Cracking spread, US$/bbl
30
* Material published permission of the OPEC Secretariat; copyright 2014; all rights reserved; OPEC Monthly Oil Market Report, October 2014. Hydrocarbon Processing | NOVEMBER 201419
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© 2014 Baker Hughes Incorporated. All Rights Reserved. 41583 09/2014
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Reliability
HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR
[email protected]
Can integrally geared compressors be successfully used with variable speeds? A recent HP webinar answered a number of compressor-related questions. This same webinar also generated a few additional ones. A viewer thought that two statements from this presentation were in contradiction, as proven by his correspondence. Question 1. One slide from the webinar used the heading: “Single-shaft multi-impeller technology vs. integrally geared speedoptimized technology.” It was followed by a slide stating that integrally geared technology allows speed, impeller diameter and contour optimizations (3D). The viewer sought clarification if the use of variable-speed drivers (VSDs) was implied. Actually, the intent of this slide was to convey that the total arrangement of integrally geared air and/or process gas compressors (IGCs) allows the use of the most efficient impeller for each stage. There is a limit of 10 stages that can be accommodated on IGCs. These different impellers (each called a “stage”) are typically 3D and semi-open style, as shown in FIG. 1. Impeller design. Impellers are designed and then machined on multi-axis machines to optimize the blade contours, angles of twist, overlap, number of blades, and more. Engineers can, by design, optimize the efficiency of any of the three to 10 impellers, attached with two per pinion, as shown in FIG. 2. As illustrated in FIG. 2, a single bull gear engages several pinions, and each pinion can have a number of teeth that differs
from the number of teeth in the other pinions. Therefore, up to five different impeller speeds can be found in a single IGC. Question 2. Another webinar slide compared single-shaft conventional centrifugal/axial vs. IGC technology. Constant input speeds derived from 2- or 4-pole electric motors in 50/60 cps power systems were mentioned. The viewer asked if there are any particular concerns when configuring an integrally geared compressor to be driven with VFD input. Answer: Variable-input speeds could conceivably create an infinite number of different lateral and torsional critical speeds. Caution is warranted when applying VFDs on a compressor with many resonant frequencies; it is a complex task. Also, there would likely be an infinite number of critical speeds. Review. While a fixed input speed can be handled and undesirable frequencies avoided by design, the same is not true at VFD speeds. With infinitely variable input speeds, there would be an infinite number of torsionals and their harmonics. Also, each free-standing impeller blade resonates at a particular frequency, and these could be excited if VFDs were used.
FIG. 2. Semi-open impellers are attached two per pinion; a bull gear engages up to five pinions (= 10 stages) in modern integrally geared compressors; two pinions are shown in this image. Source: Cameron Compression, Buffalo, New York.
FIG. 1. Machining a semi-open 3D impeller. Source: Cameron Compression, Buffalo, New York.
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 600 publications, among them 18 comprehensive books on practical machinery management, failure analysis, failure avoidance, compressors, steam turbines, pumps, oil-mist lubrication and practical lubrication for industry. Mr. Bloch holds BS and MS degrees in mechanical engineering. He is an ASME Life Fellow and maintains registration as a Professional Engineer in New Jersey and Texas. Hydrocarbon Processing | NOVEMBER 201421
BENEFICIAL REUSE “Beneficial reuse” is defined by the EPA as reusing a material in a manner that makes it a valuable commodity. Spent caustics are generally byproducts of a refinery or chemical process that would ordinarily be treated as wastes. When beneficially reused without reclamation, the spent caustics are exempt from the solid waste definition and are categorized as a product (or valuable commodity) under the EPA regulations.
Merichem’s beneficial reuse of spent caustic, without reclamation, is more environmentally friendly than disposing of the material as a waste. As such, these materials are no longer a part of your waste generation statistics.
At Merichem Company, we bring to the petroleum refining and petrochemical industries more than 50 years of experience in the handling of caustic effluent streams. Our technical expertise allows us to recommend the right caustic treating needs for your specific processes and, if needed, handle most resulting caustic solutions. Our beneficial reuse of caustic streams helps our customers achieve waste minimization goals and eliminates labor intensive waste handling protocols such as manifesting, hazardous waste record keeping, etc. Your spent caustic is used as a substitute for other commercially available products or as a feedstock in manufacturing processes. In either case, Merichem will utilize your spent materials in a non-waste, environmentally responsible manner. Merichem's advanced logistics system allows us to transport caustic solutions to our chemical plants and terminals in a safe, efficient and cost effective manner. Additionally, our adherence to the American Chemistry Council's Responsible Care® program ensures compliance to the highest industry standards. It’s true! Merichem is the partner of choice for non-waste utilization of your secondary materials.
www.merichem.com/Beneficial-Reuse
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Automation Strategies
HARRY FORBES ARC Advisory Group, Burlington, Massachusetts
Virtualization in process automation systems Virtualization involves separating an information technology (IT) resource from specific physical hardware. This is usually managed by a specialized software layer called a hypervisor, which provides another abstraction layer. Virtualization can be applied to any IT resource, including servers, storage, desktops and networks. For example, server virtualization enables multiple virtual servers, or guests, to run on one physical host server. Virtualization can improve IT resource utilization and security and ease system administration. Virtualization has been well proven in IT environments and is foundational for all cloud architectures. Today, many process automation system suppliers offer products and solutions that use virtualization. Benefits. Since virtualization can only be applied to some
parts of process automation systems, it can be difficult to assign specific economic value to the technology. Virtualization plays an important role wherever server hardware is used in the automation system. This is at Levels 2 to 4 of the ISA-95 manufacturing model. Today’s automation suppliers offer system configurations that feature server consolidation. Multiple human machine interface (HMI) machines and other application servers are replaced by virtual machines. A small number (usually one or two) of more powerful hosts support these virtual machines. Besides being more powerful, the new servers incorporate levels of redundancy with respect to power, storage, computing and network resources. Server consolidation benefits include removal of physical equipment and freeing rack or panel space in congested control areas. Power requirements and system administration burden are also reduced (though the remaining administration work is technically more complex). The largest benefit to end users of server consolidation in process automation systems is the decoupling of the automation software from specific configurations of PC or server hardware. For years, many HMI and other automation system functions have been implemented on PC hardware. Plant owner-operators and automation suppliers have struggled to support these systems due to the short lifecycle of PC products. By virtualizing such a system, it can be more easily supported once replacement hardware is no longer available. This higher degree of hardware independence helps extend automation system life and reduces production interruptions due to automation system upgrades. At lower levels (1–2) in the ISA-95 model, automation functions are implemented in embedded systems (like process controllers or field devices) that are managed by a realtime operating system (OS). These devices can be simulated or emulated, but, strictly speaking, they cannot be virtualized
as is. Instead, their embedded software must be modified and/ or ported to some degree to operate in a virtual machine environment. Most automation suppliers have developed products that now provide this functionality. Plant asset lifecycle. For process manufacturers, virtualiza-
tion technology can bring significant value to their installed base of automation systems, as well as to automation projects for new plants. For installed systems, the benefits come from replacing dedicated servers with virtual ones. In new installations, the benefits come from compressing schedules by developing the system configurations and applications in a virtualized environment. Benefits during the design and build phase center around two major areas. First, is the reduced space and utility requirements of an automation system incorporating server virtualization. These reductions can be dramatic and result in substantial savings in high-cost installation areas. To take advantage of such savings, the reduced requirements must be known during the early stages of project engineering so that the project’s civil and mechanical engineering designs can take advantage of the reduced system power and space requirements. Without a main automation contractor (MAC) structure, projects are not likely to realize these benefits. Second is the ability to engineer the automation system in a virtual environment without access to the target hardware. This enables the virtualization user to: • Apply a geographically distributed project team working from different locations on the same virtualized automation system • Reduce project dependencies between system hardware deliveries and system configuration and engineering deliverables • Conduct a factory acceptance test for the automation system using a virtualized system • Late bind the system software and configuration with the target hardware • Have concurrent development of operator training simulators and automation system engineering. HARRY FORBES is a senior analyst at ARC Advisory Group. His research focuses on the impact of industrial networking and wireless technologies on today’s manufacturing. He also covers smart grid and electric power vertical industries. His research topics include the smart-grid, smart-metering and smart-energy technologies. Mr. Forbes is a graduate of Tufts University with a BS in electrical engineering and has an MBA from the Ross School of Business at the University of Michigan.
Hydrocarbon Processing | NOVEMBER 201423
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ALAN GELDER
Global
Global Practice Lead for Refining & Marketing for Wood Mackenzie
European refining—Cornered, with no way out?
Historical perspective. The historical oil product demand for Greater Europe (Northwest Europe, Scandinavia and the Baltics, Central and Eastern Europe and the Mediterranean) is illustrated in FIG. 1. This figure also shows the crude runs through its refining system. Key factors being: • Crude runs peaked in 2005, although demand continued to rise until 2007. Prior to 2005, higher demand was typically associated with higher regional crude runs. • From 2005 to 2007, demand grew modestly while crude runs shrank by 500 Mbpd, so the global context of European refining industry was changing. • The 2008 financial crisis started the decline of refined products, while demand has dropped almost 2 MMbpd from its peak, crude runs have dropped further (by 2.5 MMbpd). The traditional relationship of European refineries primarily running to satisfy local demand is under threat. Competition is gaining strength. The phenomenon of
North American unconventional oil and gas supplies is well known, which provides advantaged feedstock and utilities to its refining system. The positive impact on the competitive advantage of US refiners is dramatic, as shown in FIG. 2, comparing net
cash margins for USGC refiners against those in coastal NWE (on a volume weighted aggregate basis) for 2009, 2013 and also our outlook for 2018. This clearly shows the growing disparity between USGC refiners and those coastal NWE sites. US refiners are increasingly capable of pushing surplus refined products into other regions. FIG. 3 shows the change in net trade US balance for gasoline and diesel. The US is now a net exporter of both gasoline and diesel/ gasoil (GO). This poses a direct threat to European refiners, as: • The US has been traditionally a major market for Europe’s gasoline exports • US diesel exports to Europe can satisfy regional demand while EU refineries operate at lower utilization rates, thus reflecting the challenges in gasoline exports. Europe’s refiners are trapped by developments in both Russia and the ME. FIG. 4 shows net trade changes for gasoline and diesel in the ME. The threat to Europe is its declining gasoline deficit, reducing gasoline exports. Conversely, the higher diesel/GO surplus is likely to target European markets. Result: Europe needs to consider its options, we forecast that “business as usual” will result in Greater European crude Weighted average cash margin, US $/bbl
2013 was a dismal year for European refining in terms of record low crude runs, which reflect weaked demand outlook and increasing competition from other regions. Out to 2020, we envisage European refining to remain challenged by low demand growth and increasingly competitive exports from regions such as North America, Russia and the Middle East (ME). Commercially, Europe is cornered by exports from these markets, with no apparent exit route.
USGC Coastal NWE
8 6 4 2 0 -2 2009
2013
2018
Coastal NWE comprises of refineries in Belgium, France, The Netherlands and the UK Source: Wood Mackenzie
25,000 Demand Crude run
FIG. 2. USGC vs. NWE weighted average net cash margin (US$/bbl).
20,000 Gasoline and diesel trade balance, Mbpd
Demand and crude runs, Mbpd
12 10
15,000 10,000 5,000
Source: Wood Mackenzie
FIG. 1. Historical greater European demand and crude runs.
2013
2012
2011
2010
2008
2009
2007
2006
2005
2004
2003
2001
2002
2000
0
1,000 750 500
Exports
250 0 -250 -500
Gasoline Diesel/GO
Imports
-750 -1,000 2005
2010
2015
2020
Source: Wood Mackenzie
FIG. 3. US gasoline and diesel trade balances. Hydrocarbon Processing | NOVEMBER 201425
Global runs declining by a further 1 MMbpd (2014 to 2020). We forecast average refinery utilization to drop from 74% in 2013 to approximately 65% in 2020. Given highly competitive assets typically operate at over 90% utilization levels, this average requires many weaker sites to operate at unsustainably low throughputs. Options for European refiners. The range of options for Eu-
ME gasoline and diesel trade balance, Mbpd
ropean refiners spans: • Invest to secure a sustainable asset (which is the position adopted by Repsol and GALP in their recently completed investment programs) • Continue a focus on ongoing cost and efficiency improvements • Close refining operations. 1,000 750 500
Exports
250
However, this is more complex than the identification of the weakest sites, as poor financial performance is a necessary, but not sufficient, condition. Various other factors come into play regarding potential closures: • Refinery location and regional product balances, as closure of an adjacent competitor site could transform the outlook for a given asset • Ownership structure, which introduces social and energy security considerations for national oil companies or those public companies with the government as a key stakeholder • Investment requirements, including forthcoming major turnarounds, which could prompt a closure decision • Integration along the value chain (upstream production and petrochemicals) Further major upgrades and capacity rationalizations will be limited, condemning the region to a “lost decade” of weak commercial performance. ALAN GELDER is the global practice lead for refining and marketing for Wood Mackenzie. He is responsible for formulating Wood Mackenzie’s research outlook and perspectives on this global sector. Mr. Gelder joined Wood Mackenzie in 2005. Prior to joining Wood Mackenzie, he had 10 years of industry consulting after working for ExxonMobil in a variety of project planning and technical process design roles. Mr. Gelder has a first class MS degree in chemical engineering from Imperial College, London, supplemented by an MBA from Henley Management College.
0 -250 -500 -750 -1,000
Gasoline Diesel/GO
Imports 2005
2010
2015
2020
Source: Wood Mackenzie
FIG. 4. ME gasoline and diesel trade balances.
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26NOVEMBER 2014 | HydrocarbonProcessing.com
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Modular Solutions
Maximize project benefits and minimize overall project risk and execution time UOP delivers complete modular process units for the petroleum refining, petrochemicals and gas industries. Modular delivery minimizes overall project schedule, cost and risk by maximizing prefabrication of complex process units under quality controlled conditions and under the watchful eye of the process licensor. UOP has delivered more than 1,200 fully engineered and fabricated UOP process units to the global oil and gas industries.
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From: Plant Manager Sent: Tuesday, May 13, 2014 To: Process Engineer ps Subject: Constant process tri
our process energy consumption, I know we’re wasting money on of upgrading right now. but I can’t justify the cost
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Show your boss how smart you are. CCC spots the inefficiencies in your process that cost you time and money. In fact, we prove it with our Energy Savings Guarantee. Recently we worked with a customer to guarantee a 7% reduction in steam consumption, equating to a $50 million savings over the system’s entire lifecycle.
See how we prove it at www.cccglobal/guaranteed Select 69 at www.HydrocarbonProcessing.com/RS
Automation Safety
WILLIAM M. GOBLE Managing partner, exida
It is easier to sit on the couch than go exercise I like a routine each morning where I get up early and work on long-term projects—important tasks that lack the urgency of a short deadline, like reading that new safety critical systems book, writing a new book, or studying that new set of field failure data. Then, I eat breakfast on the couch while watching TV, followed by a cardiac exercise session. But most every morning, I think, “Why exercise when it is so comfortable to just relax on the couch?” Some mornings, I give in and skip the exercise session. It is not easy to exercise, but it is great in that, on most mornings, I find the discipline to leave the comfort of the couch. Why? I believe that the exercise will yield good health over the long run. That is a good return on the work/ pain investment. This same thinking can be applied to many things, including functional safety. It is easier to stay with the “comfortable couch” methods of the past than to adapt to new standards. It is easier to follow a simple rule book than to design a new and better safety function. It is easier to read a sports/hot rod magazine than that new technical article or new functional safety book. It is not comfortable to verify failure rates that look too low. It is easier to sit in your chair than to set up a good proof test data collection process. It is much easier to avoid taking the Certified Functional Safety Expert (CFSE) exam rather than to go through the preparation process and pass the test. Competency is required for functional safety. Fortunate-
ly, many have shown their discipline in terms of adopting the IEC 61511 standard in the HPI. Functional safety standards IEC 61511 and IEC 61508 were created by a global committee to provide a framework engineering process that allows engineers to design, innovate and optimize. In these standards, companies may establish their own risk-reduction process based on tolerable risk criteria. Methods are provided in these standards to design automatic safety protection systems to match estimated risk reductions. Described methods allow new, innovative designs to be verified against requirements. What is not provided is a cookbook of simple rules that must always be followed. These are performance-based standards, not prescriptions. What that means is simple: engineering competency is required. Chat group questions asking about the implementation of IEC 61511 and IEC 61508 are occurring on a global basis. Clearly, there is widespread global acceptance and implementation. However, discussion groups seem to indicate that there is a long way to go on competency for some companies and groups. Achieve and demonstrate competency. What about
reading that technical article or the new book on functional safety? Should engineers continue to broaden their under-
standing even after passing the CFSE exam? In a conversation within a chat group, the author was asked this question. The individual continued, “I am not interested in the new CFSE Endorsement Program to show additional skills. I have the CFSE certification. The E stands for expert. This means that I know everything, and no longer have to learn.” No one should let the title “expert” slow down or curtail learning. There is never a lack of new material to understand. Apparently, in hindsight, it was a mistake in calling the “E” in CFSE, “expert.” For those who realize they need to keep learning, the couch may look more comfortable. What about the certificate from T** Italia that shows a failure rate for a valve is less than a simple electronic resistor? This has no chance of passing a reasonability test. Yet, a chat-group participant asked, “Who am I to challenge an accredited certification body?” The answer is simple. That person is the engineer responsible for functional safety on this job. The performance calculations require that reasonability checking be done. A competent engineer knows how to do that and has the resources to get it done. Beginning on a new book, a training course or a new data collection process is hard. I feel that way every morning when sitting on my couch. I know there are people with strong functional safety competency. And I know that there are people who do not have that competency or the discipline to get it. Some people just cannot do it. So, for those folks, I ask: Please do not work on a functional safety project or on any task where you are not fully competent. The rest of us will gather the discipline to be fully competent. We will show our competence by getting an ISA Safety Instrumented Systems certificate or a certification like CFSP/CFSE. Many will show continuing knowledge by getting CFSE endorsement certificates. We do this because we know that competent functional safety work brings good health, good environments and good economics for the long run. Most companies consider this an excellent return on investment. WILLIAM M. GOBLE is the managing partner and co-founder of exida, a company that does research, training and 61508/cyber-security certification for safety, critical and high-availability systems. He has developed probabilistic analysis methods for functional safety that are widely used today. Dr. Goble has over 40 years of experience in control systems, product development, training and functional safety certification. He has a BS degree in electrical engineering from Penn State University, an MS degree in electrical engineering from Villanova and a PhD from Eindhoven University of Technology in reliability engineering. He is a registered professional engineer in the State of Pennsylvania and a certified functional safety expert. He is also a fellow member of ISA. Dr. Goble has written hundreds of technical articles and several best-selling functional safety books. Hydrocarbon Processing | NOVEMBER 201429
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Boxscore Construction Analysis
LEE NICHOLS, DIRECTOR, DATA DIVISION
[email protected]
Vietnam: Reversing the tide of refined imports Vietnam has ambitious plans for its downstream refining and petrochemical sectors. At present, the country has only one operating refinery, located at Dung Quat. With oil consumption rising steadily from 176 Mbpd in 2000 to nearly 400 Mbpd in 2012, the 146Mbpd refinery is unable to satisfy domestic demand for refined products. As a result, the country is dependent on fuel imports. Vietnam’s 2020–2025 development plan outlines several ways to completely eliminate the refined fuel supply gap. The country is developing six largescale refinery projects (TABLE 1). These projects have the potential to add 1.36 MMbpd of new domestic refining capacity at a total cost of over $50 B. This would reverse the country’s status from a net importer of refined products to a net exporter by 2020.
However, several variables may act as a deterrent to these plans. These variables include the need to secure a massive amount of crude oil feedstock and financial backing, overcapacity concerns that could lead to a glut of fuel in the Asia-Pacific region, the need to secure exporting supply contracts with other nations, and the threat of future governmental and environmental regulations. Vietnam will also need to construct a vast amount of new infrastructure to export refined fuels. Regardless, the country is poised to reverse its fortune and become a major Asian refined fuels exporter by 2021. Dung Quat. The refinery is operated
by Vietnam’s national oil company, the Vietnam Oil and Gas Group, or PetroVietnam. Located in the central province of Quang Ngai, PetroVietnam’s 140-Mbpd
Dung Quat facility began commercial operations in 2010. The plant satisfies about one third of the country’s domestic demand for refined products. To decrease refined product imports, PetroVietnam has instituted a $3 B expansion project. This expansion will increase refinery processing capacity from 140 Mbpd to 200 Mbpd. The 60-Mbpd expansion and upgrade project will not only help reduce domestic imports for refined products, but it will also allow the refinery to process a greater variety of crude oils. The refinery processes mainly sweet crude oil produced in Southeast Asia. With the addition of several processing facilities, including a new vacuum distillation unit, Dung Quat will be able to process sour crude oil from the Middle East, Russia and Venezuela. The project has been delayed several times due to the withdrawal of foreign oil companies. The
TABLE 1. Major downstream projects in Vietnam Project
Company
Capacity, Mbpd
Cost, $ MM
Completion
Dung Quat refinery expansion
PetroVietnam
200 (expansion of 60)
2,000
2018
Nghi Son refinery and petrochemical complex
Kuwait Petroleum, Idemitsu Kosan, PetroVietnam, Mitsui
200
9,000
2018
Vung Ro refinery and petrochemical complex
Vung Ro Petroleum, Technostar Management
160
4,000
2018
Nhon Hoi refinery and petrochemical complex
PTT, Saudi Aramco
400
20,000
2021
Nam Van Phong refinery
Vietnam National Petroleum Group, Daelim Industrial
200
8,000
N/A
Long Son refinery and petrochemical complex
PetroVietnam
200
7,000–8,000
2021
TABLE 2. Process technology licensing awards for the Vung Ro refinery and petrochemical project Company
Unit
Process technology
UOP
Multiple units
Unionfining, Selectfining, Resid UOP FCC, Platforming, PENEX, Huels selective hydrogenation, UOP indirect alkylation, Sulfolan, Merox, Chlorsorb system
CB&I Lummus
Ethylene recovery and olefins conversion units
Ethylene and olefins conversion technologies
INEOS
Polypropylene
Innovene PP
Jacobs Engineering
Sulfur recovery unit
SUPERCLAUS, caustic scrubber, Shell’s sulfur degasification Hydrocarbon Processing | NOVEMBER 201431
Boxscore Construction Analysis latest casualty was Japan’s largest refiner, JX Nippon, which announced in November 2013 that it would not participate in the refinery’s expansion project due to failure to agree on financing terms. In August, Russia’s Gazprom Neft began negotiations with Binh Son Refining and Petrochemical Co., a subsidiary of PetroVietnam and managing company of the Dung Quat refinery, for a potential partnership in the expansion project. As
part of a potential deal, Gazprom Neft would take a 49% ownership stake in the project and provide funding of $1.5 B to $3 B. At the time of publication, both sides are still negotiating on the funding structure. If completed, the project would help Vietnam move closer to its goal of refined fuels self-sufficiency. Nghi Son. Located 120 mi south of Hanoi in Thanh Hoa province, the Nghi
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Son refinery and petrochemical project will be Vietnam’s second domestic refinery. The project is being developed by a JV of Kuwait Petroleum Co. (35.1%), Idemitsu Kosan (35.1%), PetroVietnam (25.1%) and Mitsui Chemicals (4.7%). The 200-Mbpd refinery will process imported Middle East crude oil to produce high-octane gasoline, diesel and jet fuel. Upon completion, the refinery will double Vietnam’s domestic refining capacity. The complex will also integrate aromatics and polypropylene (PP) facilities. Based on a detailed feasibility study conducted by ABB Lummus Global, total project cost is expected to reach $9 B. This cost includes the construction of the $5-B refinery, as well as the building of nearby harbor facilities. In January 2013, the engineering, procurement and construction (EPC) contract was awarded to a consortium of Japan’s JGC Corp. and Chiyoda, South Korea’s GS E&C and SK E&C, France’s Technip and Malaysia’s Technip Geoproduction. Construction began in October 2013 and is expected to be completed by 2018. With the expansion of Dung Quat and the completion of Nghi Son, Vietnam will be able to satisfy 65% of domestic refined product demand by 2020. Vung Ro. If completed, the Vung Ro refinery will be Vietnam’s third domestic plant. The project is a $4-B oil refinery, petrochemical complex and seaport development in the Dong Hoa district of Phu Yen province. The Vung Ro refinery and petrochemical complex is being developed by Vietnam’s first fully private company in the petroleum sector, Vung Ro Petroleum. The 160-Mbpd refinery will process East Asian crude oil into Euro 5-quality gasoline and diesel, jet fuel, LPG, fuel oil and other products. BP and Morgan Stanley Commodities will be the main suppliers of crude oil to the refinery. The petrochemical complex will produce benzene, toluene, mixed xylenes, PP and sulfur. Japan’s JGC was awarded both the FEED contract and the EPC contract. JGC will be in charge of supplying equipment, technology, design and construction of the complex. UOP Honeywell was appointed the managing licensor for the project. The company will provide multiple process technologies for the complex, including the main automation
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Boxscore Construction Analysis and control systems, as well as carry out basic engineering. Additional technology licensing contracts are shown in TABLE 2. Construction commenced in September, with full construction operations set to begin in 1Q 2015. If completed, the plant is scheduled to begin commercial operations by 2018.
plants. These plants will be able to produce 2.9 MMtpy of olefins and 2 MMtpy of aromatics. Although the refined products will be used to satisfy domestic demand for transportation fuels, the majority of the petrochemical products will be exported. If greenlighted, the project is expected to be completed in 2021.
Nhon Hoi. Thailand’s state-owned en-
Khanh Hoa. The Nam Van Phong re-
ergy company, PTT, is developing the Nhon Hoi refinery and petrochemical complex with Saudi Aramco. Both companies will control a 40% stake in the project, with the remaining 20% owned by the Vietnamese government. Under the initial plan, the facility had a refining capacity of 660 Mbpd at a cost of almost $29 B, although PTT has revised the capacity down to 400 Mbpd, decreasing the total capital cost to $20 B. The project includes the construction of olefins and aromatics petrochemical
finery is scheduled to be located in the Nam Van Phong Economic Zone in Khanh Hoa province. However, the $8-B refinery is in a state of limbo. The project was licensed for development by the Vietnamese government in 2008. At that time, the initial cost was $4.5 B. A feasibility study and environmental assessment soon followed, and an MOU for investment was signed by Korea’s Daelim Industrial Corp. and Vietnam National Petroleum Group, the local investor in the project.
The project is still seeking capital investment from foreign investors. However, with the capital cost nearly doubling to $8 B and multiple billion-dollar projects planned or in development, it is unlikely this project will come to fruition. Long Son. PetroVietnam is also devel-
oping a 200-Mbpd integrated refinery and petrochemical complex in the southern coastal province of Ba Ria-Vung Tau. The $7 B–$8 B project will produce Euro 4-graded gasoline and diesel, as well as 1.4 MMtpy of olefins. The petrochemical plant will ultimately produce polyethylene, PP and vinyl chloride monomer for domestic sale. A detailed feasibility study has been completed. At present, the project developers are seeking financing, which should be secured by the end of 2014. If greenlighted, the project is scheduled to begin commercial operation in 2021.
Detailed and up-to-date information for active construction projects in the refining, gas processing, and petrochemical industries across the globe | ConstructionBoxscore.com
34NOVEMBER 2014 | HydrocarbonProcessing.com
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| Special Report PLANT SAFETY AND ENVIRONMENT Maintaining proper safety at HPI facilities is a multi-faceted endeavor. It involves preparing, implementing and supporting plant procedures and employee training programs. Environmental performance, just like safety, is a 24/7 task; there is no single solution. HPI facilities depend on the efficient operation of process equipment and employee actions without failure or deviations from approved protocols.
Special Report
Plant Safety and Environment D. BASQUEZ and M. BAKER, HollyFrontier, El Dorado, Kansas; C. BAUKAL and R. LUGINBILL, John Zink, Tulsa, Oklahoma
Heater training improves safety and operations As a part of an initiative to conserve energy and other valuable resources, an independent petroleum refiner began a twoyear training program in the summer of 2013 for more than 900 operators at six plants. In addition to improving the operational safety and management of furnaces, the program created a single point of leadership for fired heaters at each facility, who has the expertise and knowledge to lead the organization’s efforts on every aspect of furnace operation and integrity.
BACKSTORY In 2013, the company stepped up its efforts to minimize the potential for process safety events associated with fired heaters and to optimize heater performance. Most employees understand who to go to when there is a rotating equipment problem or an electrical issue. However, furnace issues can be much more complex, as there are many different components and individuals in the organization that have a role in furnace management issues. This includes mechanical inspectors for tube integrity, instrumentation and electrical (I&E) technicians, process engineers and operations personnel for O2 management. Add to that firebox conditions, burner operation and refractory condition and things can become very complex. All of these fired heater aspects must be managed effectively. Thus, there was a need to create clear leadership, with expertise and knowledge to focus the organization on every detail of furnace operation and integrity. The position of corporate fired heater specialist was created to provide such ownership and expertise. The renewed fired heater and boiler management program covers refining operations in Artesia, New Mexico; Cheyenne, Wyoming; El Dorado, Kansas (FIG. 1); Tulsa, Oklahoma; and Woods Cross, Utah. In order to improve performance, the fired heater population had to be assessed for current condition. Having a wide variety of equipment manufacturers, control schemes and operator awareness, plus differing repair methods, the fired heater specialists saw an opportunity to partner with an emissions control company to provide the support necessary to identify and make improvements. Through this partnership, equipment was surveyed and deficiencies and corrective actions were identified. To get things started, a database was created to capture all heater evaluations. The database included design data, burner curves, operating targets, descriptive pictures, parts lists and drawings. It was designed to allow for easy access by refinery personnel. In addition, operator training programs were improved and tailored specifically to heaters at each refinery. Finally, maintenance personnel were trained on “best practices” for
heater repair and preventive maintenance. In short, steps were taken to create a “best in class” fired heater management system. A dedicated technical representative was assigned to develop and oversee the program at all refineries. A rigorous schedule was established to survey all fired heaters in every facility. At the same time, a tailored training program was built to meet the needs of a furnace operation overview. Further, based on the heater surveys, a curriculum was created to train relevant personnel in the specific operation of fired heaters. This curriculm was in addition to general fired heater training.
TRAINING PROGRAM The goal is to train more than 900 operators at all six locations over a two-year period. The training started in the summer of 2013. The program consists of accredited classroom training (FIG. 2) and “hands-on” in-field training (FIG. 3). The classes are
FIG. 1. A refinery in El Dorado, Kansas, which is one of six locations where the training program has been implemented.
FIG. 2. Operators in a typical classroom training session. Hydrocarbon Processing | NOVEMBER 201437
Plant Safety and Environment kept small (approximately 20 operators) to promote classroom interaction between students and instructors.1 A training objective is to address the potential problems posed by improper process heater operation. These problems include reduced thermal efficiency, higher operating costs, increased emissions and unscheduled downtime.2 In so doing, the training will minimize the potential for the creation of hazardous conditions and process safety management events. Operator training is particularly important when new equipment is installed.3 The operators can earn continuing education units (CEUs) for the one-day class if they meet four criteria: take (not pass) a pretest, attend at least 80% of the class, pass (at least 80%) a post-test and complete a course evaluation. The pre-test and post-test are identical so learning can be directly measured. To date, 10 classes have been conducted at five different plants, with 196 students. All of the maintenance personnel at three of the plants and well over half of the total maintenance personnel have been through the training. The average attendance has been 20 students per class, with a minimum class size of nine and a maximum of 26. The pre-test scores have ranged from 0% to 60%, with an average
FIG. 3. Operator field training.
FIG. 4. Plastic burner models.
of 21%. The post-test scores have ranged from 27% to 100%, with an average of 94%. Of those taking the post-test, over 97% passed (minimum of 80%). Over 94% of the students have earned CEUs. There are a number of questions on the post-course questionnaire. One of the more important is, “What are the most significant items you learned during the training?” The most common answers have been: • Basic heater operation • O2 and draft • Troubleshooting • Safety. These are key aspects of heater operation that will help to enhance safety and thermal efficiency, while reducing emissions and downtime. The main criticism of the training has been the large amount of material covered in one day. Future classes will be modified to address this issue. Students were also asked to rate each section of the course immediately after it was delivered, using the following scale: Excellent, good, fair, needs work or not applicable. These ratings were assigned a value from 4 (Excellent) to 0 (Not Applicable), so overall ratings could be calculated, as shown in TABLE 1. The data reflects that the course has been highly rated. The company has found that even the most knowledgeable operators ask many probing questions during the training. After several training classes were completed, it became obvious that more training was desired. Natural turnover in the workforce, along with ever-changing burner designs, have necessitated continuous training on heater operation. It is very important for operators to know how heaters do what they do, why heaters are operated in a particular way and how they are monitored and adjusted so they operate safely and correctly.
NOTABLE INSTANCES There are some unique aspects of this training. The course material focuses specifically on operators and maintenance personnel and their responsibilities. The classes open with a member of the local senior management team emphasizing the importance of training. This helps to motivate the operators regarding the importance of the class. To provide a visual and tactile learning environment, a set of plastic quarter-scale models of process burners (FIG. 4) was purchased. These are used during the training for hands-on learning. Selected actual components (FIG. 5) are also brought to each class to demonstrate different design features of burners. Some of the components are examples of how things should be and some components are actual damaged parts that show what can happen TABLE 1. Course section ratings for all 10 classes combined Section
FIG. 5. Burner parts used for training.
38NOVEMBER 2014 | HydrocarbonProcessing.com
Rating
Combustion fundamentals
3.68
Combustion safety
3.69
Burner fundamentals
3.66
Burner design
3.65
Process heater fundamentals
3.58
Heater operations
3.61
Troubleshooting
3.54
Overall
3.63
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Plant Safety and Environment if burners/heaters are not properly operated and maintained. Using physical examples helps support kinesthetic learners who learn best by touching and having active involvement in the process. An electronic process heater simulator is also provided to teach the operators heater tuning techniques prior to actual field heater adjustments. A simpler simulator (FIG. 6) is available to the students after the class is over so they can practice the techniques that they learned on their own. The simulator can be accessed via the Internet. This allows newer operators to test their skills without worrying about being embarrassed if they make
FIG. 6. Screen shot of the electronic heater simulator training tool.
OPTIMIZED PROCESS WATER CIRCUITS
a mistake in front of their colleagues. They can also try a wide range of scenarios to see the effects on operation. For example, they can vary the incoming combustion air temperature and humidity, and see how they impact excess oxygen levels that affect both thermal efficiency and pollutant emissions.4 A detailed plant heater survey is completed prior to the training. This helps instructors target the training to the specific equipment in a given plant. A heater survey database compiles all of the survey results, and is made accessible to the operators via the company’s intranet so they can be studied in detail after taking the course. Along with the heater design data collected during heater surveys, the operators use the burner curves and targets to troubleshoot and tune up their heaters.
RECOMMENDATIONS Customized training for plant operators across a company can effectively help improve operations, standardize procedures and enhance organizational performance. It also helps share best practices with all locations and identify common issues. The training program described here has been particularly effective because of the close relationship between the equipment supplier providing the training and the end-user company. Setting company-wide goals (in this example, for thermal efficiency, safety and environmental concerns) helps determine training objectives. Collaboration between the training provider and the end user helps ensure that the objectives will be met. Small class sizes, pre-class plant surveys, scale equipment models, examples of actual components and in the field sessions all enhance the learning experience. LITERATURE CITED Valencia, R., D. Link, C. Baukal and J. McGuire, “Consider classroom training for plant operators,” Hydrocarbon Processing, November 2008. 2 Baukal, C. and M. Crawford-Fanning, “Combustion Training,” Chapter 17 in The John Zink Hamworthy Combustion Handbook, Vol. 1: Fundamentals, CRC Press, Boca Raton, Florida, 2013. 3 Gilder, T., D. Campbell, T. Robertson and C. Baukal, “Customize operator training for your thermal oxidizers,” Hydrocarbon Processing, November 2010. 4 Baukal, C. and W. Bussman, “Thermal Efficiency,” Chapter 12 in The John Zink Hamworthy Combustion Handbook, Vol. 1: Fundamentals, CRC Press, Boca Raton, Florida, 2013.
1
DOUGLAS BASQUEZ is an energy coordinator for HollyFrontier. He has 35 years of experience in oil refining. Working in the corporate refinery integrity department, he pulls from his operational experience to focus on process safety and reliability of fired heaters and boilers, along with other energy activities. Mr. Basquez is located at the El Dorado, Kansas refinery, but has responsibilities at various HollyFrontier facilities.
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MIKE BAKER has 22 years of experience in the refining industry, where he has held several positions, most recently as energy coordinator with the corporate refining integrity department. Mr. Baker uses his operational knowledge and technical skills to help at various HollyFrontier facilities with fired heaters and boilers in the areas of process safety, reliability and operating best practices. He holds a BS degree from the University of Utah. CHARLES BAUKAL is the director of the John Zink Institute, which is part of the John Zink Co. LLC where he has been since 1998. He has 35 years of industrial experience and holds a PhD, an Ed.D. Dr. Baukal holds a Professional Engineering license. He is an adjunct instructor at several universities and the author/editor of 13 books on industrial combustion. Dr. Baukal is an inventor and holds 11 US patents. ROBERT LUGINBILL is the manager of combustion survey services and inspections. He has worked with process burners and flares at John Zink since 1991. Mr. Luginbill has been extensively involved in testing, field services, and troubleshooting of existing burners and flares in the field. At present, he coordinates and conducts plant-wide combustion surveys, inspections and pre-turnaround surveys.
Special Report
Plant Safety and Environment K. ALLEN, Kleinfelder, Colorado Springs, Colorado
Environmental regulations: How much do they really cost? It is not unusual for some hydrocarbon processors to make environmental compliance activities a lower priority than daily operational needs, such as plant maintenance, product flow and product transport. After all, compliance does not directly generate profit. Although not all owners/operators intentionally ignore environmental compliance, this mode of operating has been seen in the industry throughout the years—until now. In the past decade, a great shift has occurred in hydrocarbon processors’ operating environments. As America’s robust oil and gas market expands—combined with increased international competition and unending news coverage of “environmentally unsound” industry practices—the US Environmental Protection Agency (EPA) has increased compliance enforcement, enacting nearly 78 civil cases and settlements in 2013 alone. Furthermore, the EPA is considering a diverse array of new rules and regulatory program obligations to achieve the US’ long-term environmental goals. Recent examples include the Obama administration’s September 2013 announcement that it will direct the EPA to use the Clean Air Act (CAA) to cut carbon dioxide pollution at power plants under the Climate Action Plan. In the wake of this evolving and dynamic regulatory environment, owners/operators can spend a considerable amount of time and resources attempting to understand and comply with new or revised rules and regulatory program obligations. Instead of investing in new equipment or totally refocusing their processes, hydrocarbon processors should instead grasp some understanding of the costs and benefits by asking themselves: “How much will these changes really cost, and what’s in it for me?” Cost of compliance. Hydrocarbon processors operating in
the US are faced with a dynamic environment that has the potential to drive capital expense on pollution controls and compliance management at the local, state and federal levels (FIG. 1). It is logical, therefore, for hydrocarbon processors to assume that environmental compliance activities (compliance monitoring and record-keeping, emissions testing, etc.) are a very expensive proposition when scaled to a multi-asset operation. Data collected about industry sentiment toward environmental regulations justifies this assumption. A 2013 report by BDO USA LLP, featuring analyses of risk factors listed by the top 100 oil and gas companies in their June 2013 10-K filings, revealed that regulatory and legislative changes remained the top concerns for the third consecutive year, with 100% of companies citing them as leading risks.
In responding to the cost analyses, many hydrocarbon processors have adopted outsized asset and risk-management programs, or implemented premature or ineffective emission-reduction systems, to use as methods of ensuring environmental compliance. Costs associated with a highly integrated compliance program, with high levels of control systems in the tens of millions of dollars, are not unusual for large processors with multiple assets in various regions. Depending on the total number of assets and emissions sources that an operator manages in any given year, the cost of maintaining this system can be astronomical. The expenditure does not always result in a particularly compelling return on investment. Nevertheless, the issue of compliance has an equivalent force—and equivalent regulatory liability—to other programs in terms of the cost of implementation. Often, after thorough pricing and cost analyses, owners/operators determine that the costs associated with compliance are multiple standards of deviations lower than expected. Cost of noncompliance. The costs associated with the “wait-
and-see” compliance model (which is not uncommon throughout the industry) are monumental in comparison to the costs of compliance, both to a singular organization and to the larger industry (FIG. 2). A few “bad players” can give the entire industry a failing grade in the eyes of regulators and the public. The perception that hydrocarbon processors do not give credence to the importance of environmental actions gives regulatory bodies the traction to institute more environmental program obligations with community support, thus causing the regulatory “feedback loop” to continue. Examples of this pattern include the Greenhouse Gas Reporting Program
FIG. 1. Hydrocarbon processors face a dynamic environment that has the potential to drive capital expense. Hydrocarbon Processing | NOVEMBER 201441
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Plant Safety and Environment (GHGRP); Mercury and Air Toxics standards (MATs); Maintenance, Startup and Shutdown (MSS); and the New Source Performance Standards (NSPS) Subpart OOOO. Furthermore, many states are imposing more stringent regulations, including leak monitoring and repair standards for upstream production facilities and standards for methane emissions, such as those recently instituted in Colorado. The results of the “wait-and-see” approach are clearly resulting in greater compliance stringency and resource allocation that dramatically outweigh the cost to operate in compliance. Furthermore, there is an ever-growing risk of litigation and penalties as new, more stringent regulatory program obligations are imposed. The EPA has increased the volume and degree of penalty in recent prosecutions, affecting more and more organizations. According to the EPA’s Fiscal Year (FY) 2009 Final Report, over 22,307 active, noncompliant entities were reported to the EPA, states, tribes and delegated local agencies. In 2010, the EPA levied a $100 MM penalty against a midsized coal-fired power plant, while, in 2013, a $1.1 MM penalty was imposed against a large oil and gas exploration company, and $26 MM was levied against a small foundry in New York. Penalties for hydrocarbon processors can prove equally monumental. Using a conservative estimate, if 1% of companies mentioned in the EPA’s FY 2009 Final Report are hydrocarbon processors, and if the estimated daily penalty for violating the CAA is $37,500, then an individual processor can have up to $2.25 MM in fines levied against it, if the company is found to be out
of compliance for a mere 60 days. For smaller operations, that can be enough to put an operation at risk or even out of business. New approach. Given the regulatory environment, it is clear
that environmental compliance should become (or remain) a top priority. Nine steps should be considered to successfully integrate environmental activities into the core of operations: Understand the intricacies. It is often said that the best offense is a great defense—and this axiom holds true on the regulatory court as well. To ensure that operations continue to comply with environmental regulatory program obligations, owners/operators must understand all applicable regulations.
FIG. 2. Penalties for hydrocarbon processors can be monumental. In 2009, over 22,307 noncompliant entities were reported to the US EPA alone.
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Plant Safety and Environment One of the more common mistakes encountered by environmental professionals is processors relying entirely on environmental consultants to understand the rules. Although consultants are always willing and eager to provide assistance, internal knowledge is key to long-term success. Know plant operations, inside and out. Environmental compliance requires careful planning to collect information at a level of accuracy required to meet the objectives of an environmental program. Detailed information should be maintained for all assets throughout an organization, including the age, material type, service records and construction specs. Other information—such as installation, contractor, climate, and exposure (i.e., weather conditions)—may also be helpful. Implement asset- and risk-management programs. Although most owners/operators already have integrated asset- and risk-management programs throughout their organizations, those who do not have such a program need to implement one, and quickly. The goal of integrated asset- and risk-management programs is to allow an operator to assess the entirety of its processes and assets, rather than to keep track via the narrow lens of permits and departments. The rationale for such a program must be demonstrated through a risk-based asset-management approach that prioritizes capital, as well as operation and maintenance investment, on the basis of the highest return on investment, weighed against the level of risk that an organization is willing to accept. Note: Integrated asset- and risk-management programs must be organization- and location-specific, and take long-term operational and business goals into account. Beyond this, such programs should be built upon by the local operation manager, based on local needs. A fully developed, integrated asset- and risk-management approach requires a number of iterations, and it should be reviewed frequently for more complex systems, especially where program performance goals are high. Be proactive. It is understandable that some owners/operators wait until the last minute to conduct environment-related activities, including environmental permitting, remediation or negotiations with regulators. However, by waiting, these owners/operators face the risk of penalties, negative press, increased regulatory scrutiny and decreased operational efficiency (FIG. 3). Of course, putting off these activities creates its own problems. The last-minute panic of starting the process days before a permit
FIG. 3. Do not wait until the last minute to conduct environmental activities, including remediation, permitting and negotiations.
44NOVEMBER 2014 | HydrocarbonProcessing.com
is due or a regulatory action is taken can have severe impacts on an organization, including lost time from shutdowns, frantic data compilation, and increased legal and administrative fees. Choose the right consultant. The best way to avoid getting caught in the negative feedback loop is to hire the right consultant for an operation. Unfortunately, this can also be the toughest decision, especially since there is often no physical product to evaluate. Aside from checking credentials and references, the decision often rests largely on what a consultant communicates. When interviewing consultants and reading proposals, things to look for include questions such as: • Does the consultant’s technical experience match the company’s needs? • Does the consultant understand the regulations as they apply to the company’s operations/location? • Does the consultant offer strategic options that provide cost-effective solutions that are in the company’s best interest? • How well does the consultant communicate? • How busy is the consultant, and what capacity does the consultant have to support the size of the company’s operations now and in the future? • Will the consultant be a long-term partner to support the company’s business needs? Asking these types of questions and carefully considering the consultant’s qualifications is critical and will save time and money in the long run. Develop the right plan. Environmental compliance program plans outline the entire compliance structure of an organization. These plans name the environmental compliance team, outline compliance requirements, describe commitments, develop mitigation plans, create staff training plans and list environmental permits. In addition, these plans demonstrate an organization’s commitment to compliance and to integrating verification procedures into operational and management systems. These steps help ensure compliance with regulatory requirements, detect nonconformities and correct identified deficiencies. Due to the importance of these documents, they must be organization- and site-specific, and they must include all applicable regulatory program obligations. Owners/operators should not try to save resources in this step, as it will prove detrimental in the long run. Do not treat environmental activities as commodities. In recent years, some hydrocarbon processors have treated environmental activities—from audits, investigations and negotiations—as commodities, using inexpensive “one-size-fits-all” approaches to support regulatory compliance programs and environmental loss investigations. Although attractive from an initial investment, generalized assessments can create higher risks over the long term for hydrocarbon processors, as compared to site-specific investigations. The biggest challenge with this method is that non-specific site investigations often do not incorporate the complex regulatory environment that varies by region, city and county. Furthermore, these investigations do not take into account an operation’s unique objective. An incomplete, inaccurate or even overly comprehensive assessment can cause delays and add unexpected costs to a project.
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Plant Safety and Environment Openly communicate. Generally speaking, owners/operators who meet with regulators have a higher probability of positive outcomes than those who do not, so it is highly encouraged that owners/operators, environmental consultants, and the applicable regulatory body meet to discuss project challenges. Open communication has two main goals. First, it gives an opportunity for the agency to provide guidance to facilitate compliance with regulations governing land use, emission controls, compliance and new facility development. Second, it maintains open lines of communication throughout the compliance process. This will help prevent misunderstandings in compliance communication, and it may help explain how mistakes occurred in the first place. Follow through, but be flexible. An effective environmental compliance plan is a living, breathing document. To be effective, it must become an integral part of an organization. Too often, these documents lay dormant until a regulator shows up for an audit, or until a violation occurs. Through active application of the plan’s policies and procedures on a daily basis, active compliance can be achieved. This compliance can streamline an organization’s business and operations, reduce the likelihood of statutory violations, help mitigate damages and show that a company is doing its best to comply with all applicable rules and regulations. Owners/operators must follow through with fully implemented and verified corrective actions, as outlined in the compliance plan. Those who do not follow through with these actions face further compliance issues, negative press and even higher penalties. Risky business. Long gone are the days of the “wait-and-see” environmental approach—owners/operators should remove the phrases “let the regulators tell us what to do” and “we’ll worry about that later” from their lexicon. To remain competitive, owners/operators must possess a deep understanding of all requirements to ensure compliance and move the industry away from the regulatory spotlight. Hydrocarbon processors have never had a better opportunity to address the regulatory “elephant in the room” than the present. Comprehending the regulatory environment, understanding operations thoroughly and teaming with key environmental professionals will help owners/operators prepare for, plan and mitigate any hazards associated with normal operations. With technological advances, hydrocarbon processors will be able to make informed and defensible decisions to address critical needs in the appropriate sequence and in a financially sustainable manner. Regulators may not offer complete relief, but these steps can deliver a much-needed compromise.
With over 50 independent subsidiaries and more than 220 engineering and sales offices spread across the world, SAMSON ensures the safety and environmental compatibility of your plants on any continent. To offer the full range of high-quality control equipment used in industrial processes, SAMSON has brought together highly specialized companies to form the SAMSON GROUP.
VERNON “KRIS” ALLEN has 18 years of practical experience focused on air quality planning and permitting. He is a senior project manager engaged in the growth and development of air quality practice. His experience includes technical and project management support for numerous projects, including conformity analysis, environmental planning/review (NEPA/CEQA), air permitting (NSR, PSD, Title V, Title IV and Minor Source), emission inventories, abatement (RACT/BACT/LAER/MACT), regulatory applicability reviews and air-dispersion modeling. Mr. Allen holds a BS degree in environmental restoration and waste management from Colorado Mesa University. He is a member of the Gas Processors Association, the Air and Waste Management Association, the Rocky Mountain EHS Peer Group and the Colorado Oil and Gas Association. A01120EN
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Special Report
Plant Safety and Environment T. LINDNER-SILWESTER, HOERBIGER Kompressortechnik Holding GmbH, Vienna, Austria
Consider true zero-emission packing for reciprocating compressors Reciprocating compressors are essential machines in refineries. Especially when handling hydrogen, reciprocating compressors must provide ruggedness, operating flexibility and energy efficiency at pressures up to 3,000 psi (200 bar). Reciprocating compressors are also widely used to boost pressure in natural gas pipelines. Piston-rod sealing is a key factor in the efficiency and reliability of reciprocating compressors. Yet, conventional compressor packings, no matter how elaborate, always leak to some degree. Leakage can bring significant financial costs, in terms of both the value of lost product and the cost of nitrogen for purge systems. Likewise, the environmental and regulatory consequences of leaks—in terms of both greenhouse gases (GHGs) and toxic substances—are also significant. In particular, leakage rates can become unacceptable as the sealing rings approach the end of their service life. Another challenge is rod sealing when the compressor is pressurized but stationary; this may require special auxiliary seals to be activated whenever the machine stops. For some applications, it would be a great advantage to have a piston-rod sealing system that is inherently leak-free under both dynamic and static conditions. Zero-emission systems. A new pis-
ton-rod sealing system has been developed to address leaks for reciprocating compressors. It is based on a pressurized oil barrier surrounding the piston rod and contained by two oil seal rings. As long as the oil pressure exceeds the gas pressure, then the system cannot leak. The main design challenge is to keep the oil in place. A careful study of hydrodynamics has yielded an arrangement in
which the motion of the rod “pumps” oil back into the packing against the prevailing pressure gradient. Oil loss, in fact, is lower than with a conventional lubricated packing. The design avoids the need for a separate packing cooling system, and continuously monitors oil pressure and consumption. The system also incorporates a failsafe mode in which it operates as a conventional vented pressure packing, with purge if necessary. Role of reciprocating compressors. Though reciprocating—piston-type— machines are the oldest form of gas compression technology, they are by no means out of date. Especially where high pressures are required, these rugged, lowspeed workhorses hold their own against turbocompressors in many applications. Examples. Pipeline-booster compres-
sors are an excellent application. The reciprocating compressor’s ability to be driven directly by gas engines, which, in turn, take their fuel straight from the pipeline, makes economic sense, especially in remote locations with no power grid. In refineries, reciprocating compressors often handle hydrogen-rich gas mixtures for hydroprocessing and hydrotreating operations, where their reliability and high-pressure performance are valued. Many of these machines have seen decades of service in a variety of applications. Reciprocating compressors are inherently versatile, and they can generally be adapted to handle new throughputs and pressures, different gases, and lubricated or oil-free operations. Although reciprocating compressors have used the same underlying principles for more than a century, new de-
sign techniques, materials and control systems have kept them competitive in recent years. New polymer composites and advanced flow-modeling techniques have yielded lightweight valves that are both efficient and durable. Research on the physics of sliding surfaces has resulted in rod seals and packings that outperform their predecessors, over a wide range of temperatures, pressures, moisture levels and gas characteristics. Modern sensors, actuators and electronic systems allow reciprocating compressors to be controlled efficiently, and monitored continuously for best reliability. Gas leaks. Any double-acting compressor cylinder requires a seal around the piston rod. Modern sealing rings and rod packings made from various combinations of PTFE, bronze, graphite and other materials offer excellent performance. However, over the long term, there is always some gas leakage. A typical oil-lubricated rod packing on a large compressor may leak a couple thousand liters/hour of gas. For worn or damaged packings, these figures could be several times greater. As the packings approach the end of their service life, leakage rates can become unacceptable. Consequences. Leakage has financial and other consequences. In hazardous locations, such as refineries and pipeline compressor stations, leaks are typically rendered safe by nitrogen purging and disposal to a flare stack. As well as making the process more complex, however, the use of nitrogen adds cost, especially if purged-distance pieces are also required. In sensitive applications, other techniques may reduce both leakage and gas Hydrocarbon Processing | NOVEMBER 201447
Plant Safety and Environment costs, but with the penalty of added capital costs and complexity. An example is a pneumatically operated static seal used to prevent leakage when the compressor is at a standstill but is required to remain pressurized. Elaborate gas recovery equipment also falls into this class. Older compressors of the singlecompartment type (API 618, 6.12.1.3 type B) have a direct-gas leakage path between cylinder and crankcase, allowing leaked gas to dissolve in the crankcase oil. This lowers the flashpoint of the oil and increases the fire hazard in the
FIG. 1. The new packing design relies on a pressurized volume of oil held between two sealing rings.
event of an accident. Pressurized crankcases are sometimes used; but again, they add cost. GHG issues. Methane is a potent GHG.
So, the regulatory cost of leaks may be significant. Toxic components, such as benzene, in raw natural gas are of concern. Even the smell of gas may be undesirable in some applications, such as compressed natural gas fueling stations. Oil consumption. Conventional lubricated packings consume oil—1.5 l/d per packing is typical. This has economic and often environmental costs, too, since the oil must be disposed of after use. Leak-free sealing: Oil is the key. The cost and complexity of controlling gas leakage means that a truly leak-free rodsealing system would have considerable benefits in some applications. Such a system is possible. The principle behind the new zero-emission packing is the use of oil, rather than a solid material, as the sealing medium. A volume of pressur-
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ized oil surrounds the piston rod and is kept in place by two specially designed oil-seal rings (“1” and “2” in FIG. 1). As long as the pressure of this “oil barrier” is higher than the gas pressure, the gas cannot leak out. And, because the rod is always covered with an oil film, the oilseal rings operate virtually without wear. Even when the compressor shuts down, the oil volume maintains an effective static seal. As a result, a compressor that must remain pressurized during shutdown needs no additional arrangements to ensure effective static sealing. The complete packing contains several other elements that together enable a conventional pressure packing (FIG. 2). As well as oil-seal rings (3a, b and c), there are two or three conventional single-acting packing rings (1), a buffer volume (2) and a wiper ring (4). All the rings are floating, i.e., they are free to move with lateral movements of the piston rod. The job of the buffer volume (2) is to stop the oil barrier from seeing the full discharge pressure of the cylinder. This allows the oil pressure to be set just above the suction pressure, rather than above the discharge pressure, as it would have to be if the buffer were not present. This pressure reduction, in turn, lowers the mechanical loading on the oil-seal rings. The buffer volume is able to remain at the suction pressure of the cylinder due to the conventional packing rings (1) upstream. Any leakage past these rings during the compression stroke will increase the pressure in the buffer some-
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FIG. 2. Section through a practical zeroemission packing. The cylinder is to the left and the crankcase to the right.
Plant Safety and Environment what. Because the rings are single-acting, the pressure immediately falls again during the suction stroke. In practice, the rings need only modest sealing performance, and even worn rings will hold the buffer at the suction pressure satisfactorily. The oil barrier is kept in place primarily by two oil seal rings (3b and 3c). An extra oil seal ring (3a) minimizes oil leakage into the cylinder over the lifetime of the seal rings. Any oil leaking past the oil seal ring on the crankcase side (3c) is wiped off the rod by the oil wiper (4) and recovered via a drain line. The specific wiper arrangement depends on the compressor configuration, such as whether a distance piece is used. Understanding oil-film dynamics. The idea of using oil as an infinitely flexible seal is straightforward. More difficult to implement in practice are seals to keep this oil in place effectively. Just as process gas or purge gas leaks past the rings of a conventional pressure packing, so oil will always leak past the oil-sealing rings. The difference is that this oil leakage is extremely slow compared to the corresponding situation for gas. In part, this is because of the much higher viscosity of oil as compared to gas. There is another important reason: the reciprocating motion of the rod “pumps” oil back into the barrier volume against the prevailing pressure gradient. When the oil seals are correctly designed, the resulting net oil loss is lower than that from a conventional lubricated packing. This pumping effect is well known in hydraulic seals, but it has never before been applied to compressor seals, which present a greater challenge. Compared to an elastomeric hydraulic seal, the “load collective” (the product of the differential pressure to be sealed and the mean rod speed) for a compressor seal is much higher. The seal must accommodate a much greater range of rod movement in the radial direction. So, can an oil seal be designed that will pump effectively? This will require an understanding of viscous flow, hydrodynamics and elasticity.
glected. Thus, the problem reduces to a linear balance between pressure and viscous forces (Reynolds equation). As shown in FIG. 3, oil flow can be treated as a combination of three fundamental cases: a) shear flow between two plane surfaces moving parallel to one another, b) pressure-driven flow between stationary parallel surfaces, and c) “squeezing” flow as two parallel surfaces approach each other. The continuity equation, with the appropriate boundary conditions, determines how these three fundamental flow cases can be combined to describe any particular local flow in a narrow gap bounded by non-parallel walls. A classic example combining a) and b) is when a surface moving at velocity, U, pulls a lubricant into a stationary, wedge-shaped space (FIG. 4). Continuity dictates that the mean flow velocity, umean , increases in the x-direction. Accompanying this increase is a buildup of hydrodynamic pressure, p(x). Upstream of
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Plant Safety and Environment the pressure maximum, umean , is smaller than U/2; downstream of the maximum, umean , is higher than U/2. At the pressure maximum, the local pressure gradient vanishes, and the velocity profile is of the Couette type, so that umean = U/2. Adding elasticity. The buildup of hy-
drodynamic pressure happens when oil is forced into a rigid, narrowing gap by a moving surface. But what if the resulting pressure is large enough to deform one of the surfaces, so that it is no longer treated as rigid? In this case, solving the Reynolds equation and simultaneously finding the elastic response of the solid to the prevailing pressure distribution is required. These “elastohydrodynamic” effects make it possible to recover oil lost during the out-stroke when the rod drags oil out of the oil barrier. Consider a simplified model in which the rod speed stays constant during both the out-stroke and the in-stroke. FIG. 5 shows the velocity profile and pressure distribution between the rod and the outermost oil seal (ring 2 in FIG. 1). During the out-stroke (FIG. 5, left), the oil-film pressure rises from the barrier pressure (at x = 0) to a peak at location x = x*out. This pressure increase arises from the existence of a convergent gap, which, in turn, is created by the hydrodynamic pressure buildup—both effects being mutually dependent in a way that is determined by the geometry and material of the seal ring. Downstream of x*out, the pressure drops until it reaches the present gas pressure and cavitation sets in. At x*out, the velocity profile is of the Couette type, so the volumetric leakage rate per unit circumference during the out-stroke is given by
(U/2) h*out, where h*out is the film thickness at x*out. At the end of the out-stroke, the piston rod is covered with a thin film of oil downstream of the seal ring. As the right-hand side of FIG. 5 shows, however, there is also a pressure buildup during the in-stroke. In fact, the peak pressure is of the same order of magnitude as during the out-stroke, and the film thickness, h*in, is virtually the same as h*out. As a result, virtually all (> 99%) of the oil that leaks out during the out-stroke is dragged back into the oil barrier during the instroke. This effect not only keeps oil loss to a minimum, but also allows the oil-seal rings to operate virtually without wear. Building a complete system. At the beginning of the project to develop a leak-free packing, the functional requirements were set as: • An oil-loss rate no higher than the lube rate for a conventional packing • Stable operation under a wide variety of operating conditions (pressure, temperature, rod size and speed) and with many start/ stop cycles • Service life of at least 8,000 hours. To meet these goals, performance of the oil-seal rings was crucial. It was also obvious that the seal rings would have to be made from a high-performance polymer with excellent tribological characteristics. A comprehensive simulation model was developed to determine the effects of ring geometry and operating conditions on the behavior of the lubrication film. The model’s predictions were then checked and refined using a purposebuilt test rig and a real test compressor.
FIG. 5. Velocity profile in the sealing gap between the oil seal ring and the piston rod, and the corresponding pressure distribution, during the out-stroke (left) and in-stroke (right). Select 163 at www.HydrocarbonProcessing.com/RS
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Plant Safety and Environment After thousands of hours of tests, in the field as well as in-house, the result is a robust seal profile that combines reliability with low oil loss. With the components of the packing box defined, the next step was to ensure a reliable supply of pressurized oil. This task involved a specially designed hydraulic unit that circulates oil at a defined flowrate and pressure through the channels in the oil barrier. Also, it picks up frictional heat released by the oil-seal rings. Oil returning to the hydraulic unit is cooled by an integral heat exchanger, so no additional packing cooling is required. Depending on rod size, speed and process gas pressure, one hydraulic unit can supply up to six packing cases. It must be extremely reliable, and approved for explosive environments. The hydraulic unit should increase the oil pressure when the compressor stops. In applications where the compressor must remain pressurized during standstill periods, leaking discharge valves can allow the cylinder pressure—and eventually the buffer pressure—to rise until it
A D V A N C E D
reaches the full-discharge pressure. Under these conditions, raising the oil pressure stops any gas passing the oil barrier. The increased load does not harm the oil-seal rings as long as the compressor remains stationary. Failsafe operation. An important task for the hydraulic unit is to monitor the rate of oil loss continuously. If oil loss exceeds tolerable limits, or if there is a sudden loss of hydraulic pressure (for instance, from a pump failure or a power blackout), the system switches automatically into emergency mode (FIG. 6), which needs no external power supply. In failsafe mode, there is no longer an oil barrier, and the whole system acts as a conventional vented pressure packing. The process gas is sealed entirely by the conventional packing rings (FIG. 2, 1), and any leakage is directed to the oil-supply line, which now acts as a vent. The buffer volume is at vent pressure, and the downstream oil seal ring (FIG. 2, 3c) works as a vent seal. For applications where a purge system would
S U L F U R
FIG. 6. Normal operation (top) and failsafe mode (above). In failsafe mode, the system operates as a conventional vented packing, with purge if required.
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Plant Safety and Environment be used in conjunction with conventional pressure packings, it is possible to purge the system automatically when (and only when) it enters failsafe mode. Field performance. The new system has demonstrated excellent performance in the field, as well as in the lab and on inhouse test compressors. Extensive field tests were conducted at a natural gas gathering and treatment plant in The Netherlands, at a natural gas/biogas compressor station fueling a fleet of city buses in
Sweden, and on a propane refrigeration compressor in Egypt. The demonstration units have recorded over 30,000 hours of successful operation (FIG. 7). With the systems running as designed, gas leakage has been zero. The failsafe design has also shown itself to operate as designed, with several hundred hours of successful operation in this mode after the oil pump was switched off. Controlling oil leakage has been the most challenging part of the development process, and some demonstration units have seen several iterations in the design of the oil seal ring. In all three demonstration plants, oil consumption is now at or below its previous value, and is typically 0.5 l/d–1 l/d per packing. Future of piston-rod sealing. This
FIG. 7. Zero-leakage sealing system installed on a compressor.
new system of sealing piston rods can offer operational advantages such as: • No gas leakage and purge gas consumption • Reduced oil consumption • Eliminated need for a separate packing cooling system
• Eliminated need for an additional static sealing system in applications where the compressor is kept pressurized during standstill • Versatility, as the system can be supplied to fit any size and shape of packing case • Built-in condition monitoring of the sealing system. The new leak-free packing will be beneficial for compressors in a variety of applications. Where gas leakage or packing oil consumption are high—especially if the cost of process gas or purge gas is a concern, or environmental restrictions are tight. TINO LINDNER-SILWESTER is the manager of the R&D central Hoerbiger center. He studied mechanical engineering at TU Vienna, Austria. Mr. LindnerSilwester continued post-graduate studies as an assistant at the Institute for Fluid Dynamics and Heat Transfer at TU Vienna and obtained a PhD in mechanical engineering. In 2003, he joined Hoerbiger’s R&D department, specializing in mathematical modeling simulation for compressor controls and rings and packings. He is also involved in the development of new rings and packings designs and was promoted to manager of the R&D group in 2010.
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Plant Safety and Environment
Special Report
J. C. JONES, School of Engineering, University of Aberdeen, UK
An examination of three recent accidents in the downstream industry Three accidents in the hydrocarbon processing industry (HPI) in recent years—two in the US and one in Europe—are examined here. The accidents are analyzed according to the principles and ideas in the second edition of Hydrocarbon Process Safety.1 Geismar, Louisiana, 2013. An accident occurred at an olefins plant, causing two fatalities and 77 non-fatal injuries.2 The disparity between the number of fatal and non-fatal injuries suggests that a vapor cloud explosion (VCE) occurred (FIG. 1), rather than a flash fire. It is known3 that a VCE leads to widely different numbers of fatal and non-fatal injuries, whereas a flash fire leads to comparable numbers of fatal and non-fatal injuries. The dense smoke shown in FIG. 1 is due to non-premixed combustion. The appropriate probit equation1 could be applied to quantitatively examine deaths from smoke inhalation. What distinguishes a VCE from a flash fire is that the former is characterized by major overpressure, and the latter is not. The circumstances of the explosion at Geismar can be examined for factors promoting a VCE. Equivalently, the conditions can be examined for factors that raised the turbulence of the leaked hydrocarbons in air. From accounts of the accident, it is clear that a major blast occurred due to overpressure.2 It has been reported2 that a quantity of 31,187 lb of hydrocarbons were released at Geismar and that 75% of the weight was accounted for by propylene, with smaller amounts of other hydrocarbons, including ethylene and benzene. Literature3 provides a route to calculating the blast energy. Using a value of 49 MJ kg–1 for the heat of combustion for gaseous propylene, the total energy released at Geismar can be calculated by Eq. 1:
14 × 103 kg × 49 MJ kg–1 = 690 MJ
agent in the Antwerp explosion, then mechanical energy must have been produced from the heat of vaporization. The steam involved in the Antwerp accident reportedly was at a temperature of 280°C and a pressure of 70 bar.5 Although the reliability of this information cannot be ascertained from the source, it does provide input to the calculation below. From steam tables, saturated steam at 70 bar has a temperature of 285.8°C. This is close to the temperature stated for the Antwerp steam, and it suggests that the steam that exploded was in (or close to) phase equilibrium. If the steam was also close to being entirely vapor to the exclusion of liquid—i.e., if it had a dryness fraction of nearly unity, as would be the case if it was lightly superheated—then its specific enthalpy is 2,772 kJ kg–1. Conversion as a result of the explosion of the steam to liquid water, for which the specific enthalpy is 113 J kg–1, gives the enthalpy drop shown in Eq. 2: (2,772 – 113) kJ kg–1 = 2,659 kJ kg–1
(2)
At approximately 20% conversion of heat to mechanical energy, the energy supplied is 530 kJ kg–1. For the purposes of the calculation, equating the total mechanical energy to the figure for Geismar in the previous section, the amount of steam having exploded is shown in Eq. 3: 34 MJ/0.53 MJ kg–1 ≈ 65 kg
(3)
(1) 1
Approximately 5% of this heat will be blast energy, giving a value of 34 MJ, or 34,000 kJ. That energy would propel a car traveling at 34 kW (45 hp) for 1,000 s. This perspective shows that major amounts of mechanical energy are involved in a VCE. The reasoning and calculations above have served to advance the study of the Geismar accident further than other studies in the public domain. Antwerp, The Netherlands, 2013. A steam explosion oc-
curred at Total’s Antwerp refinery, resulting in two fatalities.4 There is a limited basis for comparison with the steam explosion at an LNG plant in Algeria in 2004.1 If steam was the lethal
FIG. 1. The vapor cloud explosion at the Geismar olefins plant in 2013. Source: Reuters. Hydrocarbon Processing | NOVEMBER 201455
Plant Safety and Environment The explosions at Geismar and Antwerp each led to two deaths. The same mechanism—conversion of the released heat of vaporization to mechanical energy—applies to the accidental explosion of an autoclave. Devices containing much less than the 65 kg of steam in an autoclave have caused fatal injuries upon exploding. Anacortes, Washington, 2010. Seven fatalities were recorded
in a 2010 accident at Tesoro’s Anacortes refinery, which occurred due to a heat exchanger leak at a hydrocracking unit.6 A fireball with a diameter of approximately 50 m formed. The diameter,
FIG. 2. The ruptured heat exchanger at the Anacortes refinery. Source: Chemical Safety Board.
D(m), of fireballs, as a function of the quantity of hydrocarbon ignited, M(kg),1 is given in Eq. 4: D = 5.25 M(kg)0.314
(4)
A D of 50 m corresponds to a M of 1,300 kg (approximately 10 bbl) of leaked hydrocarbon. It can be inferred from Eq. 4 that the hydrocarbon-formed fireball originated from the source (i.e., a heat exchanger) and not from vessels or interconnected pipes. FIG. 2 shows the ruptured heat exchanger at the Anacortes refinery. Mechanical and thermal damage are consistent with the enclosure of the fireball. Such an enclosure causes turbulence in the fuel/air mixture before ignition, raising the propagation speed of the combustion and promoting overpressure. Application of safety cases. These recent accidents have been evaluated in semi-quantitative terms, according to principles in literature.1 The analyses illustrate how the application of fairly simple and transparent equations can clarify events in an accident. Likewise, the approach can be used in reverse— i.e., to predict the consequences of hydrocarbon leakage under particular conditions. These equations are helpful tools in the preparation of safety cases, which were formerly used in the UK but not in the US. Since the 2010 BP Deepwater Horizon oil spill, safety cases have replaced the application of national and international standards in the US oil industry.1
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Plant Safety and Environment Wider issues. Whenever an accident occurs like those dis-
cussed herein, especially where loss of life results, certain questions are inevitably asked by the media and by the population at large. The accidents discussed here happened at refineries. Has refining internationally fallen sub-standard in safety terms? Such a question is best addressed by examining the existing standard. At refineries and other facilities where hydrocarbons are processed or stored, safety procedures must be applicable to a particular situation. This is why, for example, the “ALARP” (“As Low As Reasonably Practicable”) approach1 has been widely adopted. In the application of ALARP, the frequency of a mishap, such as leakage of oil from a particular pipe, is estimated in units/yr. Therefore, 10–6/yr signifies once every million years, and 10–3/yr signifies once every thousand years. This frequency is calculated by close examination of the scene of the possible mishap, which can draw on data from accident records obtainable from such bodies as the UK Health and Safety Executive (HSE). Once the frequency is calculated as 10–n/yr, it must then be categorized as acceptable or unacceptable. Note: Application is to a particular situation; there is no general value of “n” above for which the frequency is always acceptable or always unacceptable. Acceptance depends on whether or not “n” can be increased (meaning that the frequency of the unwanted event is decreased) without costly and disruptive measures that would outweigh the safety benefits to be achieved. This is what is meant by “reasonably practicable.” The safety case, which might itself invoke ALARP, will involve the anticipation of an accident. To satisfy the regulating authority that serious consequences are precluded, the safety case will argue as if the accident had actually taken place. This process stands in contrast to the application of standards referred to in the previous section. Here, conformity or otherwise is easily ascertained, but identification of adherence to a standard with safe practice might be open to question. Standards are termed a prescriptive approach to safety, and they are attractive in that they are easily enforced and monitored. More knowledge and insight, drawing on recorded experience, are needed for such approaches as ALARP and the safety case. The question of whether refining has fallen sub-standard cannot be answered by a “yes” or a “no.” Related, oversimplified questions, such as whether training is adequate, or if supervision is sufficiently close, are also difficult to answer for the same reason. Takeaway. Hydrocarbon Process Safety takes a quantitative ap-
proach to the topic of process safety. If benefits are to be gained from following this approach, then it must be applied to real-life situations as it has to the case studies presented here. Furthermore, those involved in making process safety decisions can reference the analyses contained in Hydrocarbon Process Safety when confronted with questions from junior personnel. LITERATURE CITED Complete literature cited available online at HydrocarbonProcessing.com. J. CLIFFORD JONES, who holds BSc, PhD and DSc degrees from the University of Leeds, has held academic posts in the UK and Australia, and is a recognized expert in fuels and combustion. He has written 17 books in this subject area and has published a large number of research papers. Dr. Jones has held visiting appointments in several countries, including Kazakhstan.
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Special Report
Plant Safety and Environment R. BENINTENDI and S. ROUND, Foster Wheeler, Reading, UK
Design a safe hazardous materials warehouse The safe warehousing of hazardous chemicals is a design challenge in chemical and petrochemical projects. The wide range of properties and regulatory constraints requires a full understanding of all of the predictable implications over the various engineering disciplines engaged in the design, as well as a high degree of integration of the competencies. A systemic methodology for safe warehouse design has been developed, with the aim of identifying hazards, considering regulatory requirements, assessing risks, addressing adequate design criteria and implementing all necessary mitigation and risk-reduction measures. It is a complex process that involves, at different levels, different specialist expertise. Here, a methodology is provided for designing a safe warehouse, and the various implications and operating aspects in the design activity are identified. A case study shows the high level of analysis and integration required. Warehousing incident case history. According to the International Labour Organization, as reported by Bogdanović,1 24% of major chemical accidents happen in warehouses. A long series of incidents related to the storage of chemicals is reported. On January 4, 1977, in Renfrew, Scotland, the Braehead Container Clearance Depot chemical warehouse was destroyed by a fire and explosion. The event involved sodium chlorate under intense heat conditions, as stated by the UK Health and Safety Executive (HSE).2 Sodium chlorate storage had been involved in similar incidents since 1899, according to Kletz,3 such as the fire and explosions at River Road, Barking, Essex in 1980.4 On February 1, 1980, a fire and a series of explosions occurred at a warehouse in a factory at Trubshaw Cross, Longport, Stoke-on-Trent.4 On the morning of the
fire, the warehouse contained some 49 mt of LPG in cartridges and aerosol containers, as well as approximately 1 mt of petroleum mixtures in small containers, raw materials, and packaging materials. It is almost certain that the source of ignition was the electrical system of a batteryoperated forklift truck. On December 14, 1984, a fire broke out in a very large furniture repository in Sheffield,5 which also contained hazardous chemicals that, fortunately, were not involved in the fire. On November 1, 1986, a fire developed in a warehouse operated by Sandoz in Schweizerhalle, Switzerland. Of the chemicals stored in the warehouse, 30 mt were drained, along with water, into the nearby Rhine River during the fire-fighting, resulting in severe ecological damage over a length of 250 km. This accident triggered serious concern in at least four European countries (Switzerland, France, Germany and The Netherlands). On July 21, 1992, a series of explosions leading to an intense fire broke out in a storeroom in the raw materials warehouse of Allied Colloids Ltd. in Bradford, West Yorkshire.6 The fire was preceded by the rupture of two or three containers of azodiisobutyronitrile approximately 50 minutes earlier. These containers were accidentally heated by an adjacent steam condensate pipe. The fire spread rapidly to the remainder of the warehouse and the external chemical drum storage. Dramatic warehouse incidents have also occurred more recently. A massive explosion at a fertilizer storage and distribution facility owned by West Fertilizer caused 15 fatalities and hundreds of injuries on July 17, 2013. According to the US Chemical and Hazard Investigation Board, the explosion resulted from an intense fire in a wooden warehouse building that led to the detonation of approximately 30 mt of ammonium nitrate stored inside wood-
en bins. Not only were the warehouse and bins combustible, but the building also contained significant amounts of combustible seeds, which likely contributed to the intensity of the fire. The building lacked a sprinkler system or other systems to automatically detect or suppress fire. US federal codes covering fire and safety, such as OSHA’s Process Safety Management standard (29 CFR, 1910.119) and the Environmental Protection Agency’s Risk Management Program rule (40 CFR, Part 68) were largely not followed, despite the high reactivity of ammonium nitrate and its inclusion in these codes. On August 8, 2013, an explosion occurred in Opa-Locka, Florida, at the American Vinyl Co. warehouse, which caused one fatality and injured five. According to police hazmat crews, a storage container in the building that held 20,000 gal of liquid inexplicably exploded. The storage container blew a hole in the roof of the building. Benintendi and Alfonzo7 have analyzed 61 major chemical disasters that occurred between 1955 and 2002. The incidents have been grouped by their occurrence during processing, transport and storage of reactive chemicals and by intentional or unintentional chemistry. The conclusion is that nearly 15% of the incidents occurred when material was being stored, and that all of them underwent chemical reactions that did not belong to the design chemistry for the involved substances. Safe design for chemical warehouse. The UK HSE has identified several common causes of incidents in hazardous chemical warehousing: • Lack of awareness of the properties of the dangerous substances • Operator error, due to lack of training and other human factors • Inappropriate storage conditions with respect to the hazards of the substances Hydrocarbon Processing | NOVEMBER 201459
Plant Safety and Environment • Inadequate design, installation or maintenance of buildings and equipment • Exposure to heat from a nearby fire or other heat source • Poor control of ignition sources, including smoking and smoking materials, hot work, and electrical equipment • Carelessness, vandalism or arson.8 Most of these causes are directly or indirectly related to inadequate design. Accordingly, the safe design of a hazardous chemical warehouse is required. Safe design is defined by a number of characteristics: • Chemical substances may potentially interact and react according to any combination, depending on logistical and handling factors • The warehouse is not generally subject to the systemic process safety studies relative to the equipment, nor is it a “one-way working system” like a process plant, so some
•
•
• • •
•
behavioral and operating aspects can be unpredictable The warehouse may be unattended for a long time, and the hazarddetection measures must be effective to prevent all harmful effects Staff working in warehouse areas do not generally possess the same background and expertise that are found in process or plant operators The warehouse is an indoor system that entails particular design and operating aspects Spacing and layout safety constraints often clash with design requirements Regulatory constraints and design specifications can affect all design disciplines, and they require a high degree of integration The warehouse often includes complementary operations, such as conveying, filling and dispensing of materials packaging, which imply
Hazardous material table
Process data
Chemical identification Regulation
Chemical properties and codes identification
Standards Regulation
Literature Company work practice Literature
Chemical HAZID/ENVID
Company work practice
Standards
Process data
Regulation WH HSE design requirements Standards
Civil/structural data HAVAC/electrical data
Warehouse hazard classification and design
Standards
Maximum inventory
Compartmentalization segregation philosophy
Fire rating
Fire philosophy
Emergency alarm measures
Hazard analysis/classification input/output Standard/regulation requirement Design FIG. 1. Warehouse safe design flow chart.
60NOVEMBER 2014 | HydrocarbonProcessing.com
Drainage strategy
Regulation
Emergency HAVAC system Escape and evacuation
an additional spectrum of issues in the design. These and many other reasons make the safe design of a hazardous chemical warehouse both challenging and demanding. Methodology of a safe design. The methodology for a warehouse safe design has been summarized in FIG. 1. Rhombusshaped boxes identify safety design phases, the rectangular boxes indicate design input/output, and the round boxes represent the regulations, standards and company work practices adopted in the design. Hazmat table and process data collection. These sources provide all data to exactly identify chemicals, their statuses, phases, packaging and warehouse-handling modalities, and any other process data. Chemicals identification. On the basis of all of the information collected in the previous step, chemical substances can be identified. Due to the traditional uncertainty of the chemical nomenclature, reference will be made to validated sources, such as the European Regulation for Classification, Labeling and Packaging; the European Chemicals Agency; the classification and labeling database provided by the National Institute for Occupational Safety and Health; the Pocket Guide to Chemical Hazards; and data from the Occupational Safety and Health Administration, the Occupational Chemical Database and the International Union of Pure and Applied Chemistry. Hazardous properties classification and coding. Identification of hazardous properties of chemical substances is a key phase of the design. As a project requirement, the design team may need to adopt particular standards and local regulations, or it can be free to select the most appropriate sources. This is a potentially critical step of the design activity. A wide range of validated sources and information will be analyzed and collected. In addition to the cited institutional references, other international standards and validated sources can be adopted, such as NFPA 704 and NFPA 400.9 Proprietary material safety data sheets are not generally considered to be reliable documents because information included hereto does not necessarily reflect validated and checked data. FIG. 2 illustrates the chemical screening relative to the intrinsic hazardous characteristics of the substances, with specific reference to their reactive poten-
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Plant Safety and Environment configuration factor, which accounts for any logistical factors, including spacing, layout, potential for contact, etc. This can result in a hazard downgrade, or it can confirm the original National Fire Protection Association code. The company work practice considers a further process factor that is applicable in warehouses only if a significant process segment is present, such as a drum filling station. Warehouse HSE design requirements. The identification of the health, safety and environment (HSE) design requirements is the key phase of the design and the starting point of the multi-disciplinary design approach. This approach typically involves process, civil, electrical, machinery, and health and safety-integrated competences. On the basis of the design data, the hazard identification and classification, and
tial, as addressed by the relevant work practice. Identification and classification relative to their toxicity and to other potential harmful effects on human targets and the environment are carried out in this step. Chemical HAZID/ENVID. The chemical hazard identification (HAZID) and environmental impact identification (ENVID) step considers and assesses the potential effects and mutual interactions of chemical substances within the specific warehouse with respect to all site entities and constraints, such as other chemicals, adjacent buildings and equipment, environmental targets and the local community. A typical categorization relative to the reactive hazard, according to the company work practice, has been given in FIG. 3. Here, the NFPA 704 codes have been further investigated by means of a
Reactive hazards expected
Start Yes Any substances mixing?
Intentional chemistry? No Design input
No Any other physical processing? No
Yes Any spontaneously ignitable?
Any heat generated? Yes Yes
Yes
No
Peroxides forming? No
Yes
Yes
Yes
Incompatible Water Any Any selfmaterials reactive? oxidizer? reactive? coming into No No No No contact?
Hazard
Storage handle of any potentially Yes reactive substrates? No
Yes
Identification process
MSDS
FIG. 2. Reactive hazard screening.
NFPA
Lesson learned
CLP C. history
Stop reactivity hazards unlikely
NIOSH NPG Regulation
the results of the hazard assessment, all of the design requirements will be defined. Depending on the site, building Eurocodes in the European frame or the International Building Code and the International Fire Code in the American frame will apply. Should flammable or combustible liquid or powder chemicals be present in the normal operation of the warehouse, depending on the standard, hazardous area classification will be performed in the ATmosphères EXplosibles (ATEX) frame, or according to the American approach. Accordingly, IEC-EN-60079-10-1/2, IP 15 or NFPA 497 can be adopted. Other important codes are GOST-R and GOST-K. On the basis of the hazard and regulation assessment, the following safety design requirements will result: • The maximum allowable inventory of chemical products, depending on their toxicity, flammability, combustibility and chemical reactivity • Rules for the proper location of incompatible substances, or substances with configuration factors (FIG. 3) suggesting a specific location strategy • Fire-rating compartments for all chemicals and protection levels, if applicable • Distances from internal and external walls, from other buildings and equipment, and from sensitive targets • Fire-fighting strategy • Spill control and drain systems, which will take into account chemical compatibility, heat generation, water reactivity, gas formation and any other potential issues • Heating, ventilation and air conditioning, or mechanical or natural ventilation systems, which will need to account for any potential hazardous gas formation in the case of fire or an unintentional reaction • Smoke and gas detector systems • External emergency switchboards and associated equipment. Application example. A typical ap-
FIG. 3. Reactive hazard classification.
62NOVEMBER 2014 | HydrocarbonProcessing.com
proach to the design of a warehouse where solids and liquids are processed and/or stored is illustrated in TABLE 1. All of the typical potential issues of multiphase storage and liquid processing have been considered, including the design phases and the specific data included in FIG. 1.
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Plant Safety and Environment TABLE 1. Design summary table for a typical solids and liquids warehouse Chemical identification Project documents
• Physical properties of chemicals • Process data
Chemical properties
HAZID/ENVID
HSE design requirements
Multidisciplinary design activity
• Basic identification
• Warehouse plot plans • Warehouse plot plans • Hazardous area • Warehouse storage rack views • Warehouse storage rack views classification • Drum filling sketches • Drum filling sketches summary • Hazardous area Regulations • CLP • CLP • CLP classification • CAS number • Classification, risk • Water reactivity drawings phrases • Gas formation • Sprinkler system • Toxicity design • Heat generation • Safe layout and • Chemical incompatibility spacing • Architectural Standards • NIOSH • International building code • International building code design • F.P., B.P., IDLH • Use and occupancy • Fire barrier requirements • Required egresses classification of filling • ACGIH • International fire code • No corridor dead center, packaging center, • TLV-TWA, TLV-STEL • Sprinkler requirements ends storage center, control room, • Maximum travel mechanical room, battery distances to exits room, MCC switchboard • NFPA rack • NFPA 30 • NFPA 400 hazard level • NFPA 1 protection levels maximum heights flammability/ • Fire department • NFPA 13 sprinkler system combustibility access door design • Non-combustible • NFPA 30 control area MAQ, doors, sills, dikes, drainage system requirements sumps • NFPA 400 hazmat code, MAQ • Exterior walls exceedance, protection levels • Distance to property line • NFPA 5000 spill control • Mechanical ventilation • NFPA 13 classification • NFPA 497 filling station • NEC 70/IEC 60079 equipment • Drain system of solids hazardous area classification to be used in hazardous areas • Separate sewer • Secondary Company • CLP (company chemicals containment work practice classification reference) • Electrical • Reactivity data Literature • Bretherick • Outside manual • Physical chemical data • Yaws shutoff system • Overview information • CCPS
Takeaway. The design of safe warehous-
ing of hazardous chemicals is a complex task. It is a particular challenge, because it requires a different harmonized blending of disciplines and competences with respect to the general buildings and process plant design. Very specific, and sometimes conflicting, issues must be considered and covered by the design team because of the numerous factors that set the rules of this engineering game. NOMENCLATURE ACGIH American Conference of Governmental Industrial Hygienists B.P. Boiling point CCPS Center for Chemical Process Safety CHD Configuration hazard degree CLP Classification labeling packaging ECHA European Chemical Agency EPA Environmental Protection Agency F.P. Flashpoint IDLH Immediately dangerous to life and health IEC International Electrotechnical Committee IHD Inherent hazard degree MAQ Maximum allowable quantity
64NOVEMBER 2014 | HydrocarbonProcessing.com
NFPA National Fire Protection Association NIOSH National Institute for Occupational Safety and Health OSHA Occupational Safety and Health Administration PHD Process hazard degree STEL Short-term exposure limit TLV Threshold limit value TWA Time-weighted average LITERATURE CITED 1 Bogdanović, M., “Widely known chemical accidents,” Facta Universitatis, Working and Living Environmental Protection Series, Vol. 6, No. 1, 2009. 2 Health and Safety Executive, “The fire and explosion at Braehead container depot, Renfrew, January 4, 1977,” 1st Ed., 1979. 3 Kletz, T., “Lessons from disaster: How organizations have no memory and accidents recur,” Institution of Chemical Engineers, Gulf Professional Publishing, 1993. 4 Health and Safety Executive, “The fire and explosions at River Road, Barking, Essex, January 21, 1980,” 1st Ed., 1980. 5 Health and Safety Executive, “The Brightside Lane warehouse fire,” 1st Ed., 1985. 6 Health and Safety Executive, “The fire at Allied Colloids Ltd., Low Moor, Bradford, July 21, 1992,” 1st Ed., 1993. 7 Benintendi, R. and J. Alfonzo, “Identification and analysis of the key drivers for a systemic and process-specific
reactive hazard assessment (RHA) methodology,” 16th International Symposium, Texas A&M University, Mary Kay O’Connor Process Safety Center, 2013. 8 Health and Safety Executive, “Chemical warehousing: The storage of packaged dangerous substances,” 4th Ed., 2009. 9 Yaws, C. L., “Yaws’ critical property data for chemical engineers and chemists,” Knovel, Norwich, New York, 2012. RENATO BENINTENDI, principal consultant for loss prevention at Foster Wheeler, has 30 years of experience in process, environmental and process safety engineering. Since joining FW in 2008, he has worked on several FEED and EPC projects involving refineries and LNG facilities. Mr. Benintendi has an advanced degree in chemical engineering from the University of Naples in Italy, as well as a master’s degree in environmental and safety engineering. SIMON ROUND, group manager for loss prevention at Foster Wheeler, has over 23 years of experience in the industry, with a broad background in chemical engineering, including design, commissioning and plant operation. In his role at FW, he has responsibility for the management of the Loss Prevention Group, and for the execution of the process safety and fire protection scope of work on projects. He holds a degree in chemical engineering and biochemical engineering from the University of Birmingham, and is a Fellow of the Institution of Chemical Engineers.
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Maintenance and Reliability owner-user to minimize downtime without adversely affecting the mechanical integrity of the equipment.
OVERVIEW There have been a number of catastrophic brittle-fracture failures in the petrochemical industry. Deficiencies in historical codes of construction and discrepancies in present codes and standards have been identified. Pressure equipment must be properly assessed to qualify for low-temperature service. In many instances, a Level 2 FFS evaluation may not be sufficient or appropriate. If a legitimate concern exists for brittle fracture due to the potential for cracking, or if metal temperatures below –55°F are achievable, a detailed Level 3 Part 9 FFS fracture me-
150 °F/hr - quench nozzle 100 °F/hr - quench nozzle 75 °F/hr - quench nozzle Prior limit Recommended limit
Pressure, psi
1,800 1,600 1,400 1,200 1,000 800 600 400 200 0 260 240 220 200 180
160
140 120 100 Temperature, °F
80
60
FIG. 10. Level 3 MAT curve results for Case Study 4.
40
20
0
-20
chanics evaluation should be completed. The Part 9 Level 3 evaluation, coupled with PWHT and a detailed inspection plan, can be used successfully to qualify low-temperature acceptability. a
ACKNOWLEDGMENT Source for Fig. 1 is: Callister, W. D. and D. G. Rethwisch, Fundamentals of Materials Science and Engineering: An Integrated Approach, 4th Ed., and Callister, W. D., Fundamentals of Materials Science and Engineering, 5th Ed., pg. 257, Fig 9.3.
LITERATURE CITED API Recommended Practice 571, Damage Mechanisms Affecting Fixed Equipment in the Refining Industry, Second Ed., April 2011. 2 Occupational Safety and Health Administration, Part Number 1910, Subpart H, Standard Number 1910.119, Process Safety Management of Highly Hazardous Chemicals. 3 ASME B&PV Code Section VIII, Division 1, Rules for construction of pressure vessels, ASME, July 2013. 4 API 579-1/ASME FFS-1, Fitness-For-Service, June 5, 2007 (API 579 Second Ed.). 5 WRC Bulletin 528, “Development of Material Fracture Toughness Rules for the ASME B&PV Code, Section VIII Division 2.” 6 ASME B&PV Code Section VIII, Division 2, Alternative Rules for Construction of Pressure Vessels, ASME, July 2013. 7 National Board Inspection Code , Part 3 Repairs and Alterations, 2013. 1
BRIAN MACEJKO is the head of the pressure vessel group within the mechanical engineering business unit of The Equity Engineering Group, Inc. (E2G). He is also a member of the ASME/API Joint Committee on FitnessFor-Service. He has experience as both an owner-user and, as a consultant providing engineering support to oil and gas and petrochemical facilities. The primary focus of his experience has been in the design, maintenance/repair, failure analysis, and fitness-for-service activities for fixed equipment.
LIVE WEBCAST: Boxscore Global Construction Activity November 20, 2014 at 10 a.m. CST
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78NOVEMBER 2014 | HydrocarbonProcessing.com
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Petrochemicals W. LETZSCH, Technip Stone & Webster Process Technologies, Houston, Texas; and C. DEAN, High Olefins FCC Technology Services, Houston, Texas
Optimize olefins and aromatics production The fluid catalytic cracking (FCC) process can produce a wide range of products. FCC technology was introduced almost 72 years ago to facilitate the production of high-octane fuels, and many units are still operated for that purpose. However, the FCC unit (FCCU) can also be used to produce petrochemicals. Ongoing changes in ethane cracking operations do not produce sufficient propylene to meet growing demand. Petrochemical yields from the FCCU is an area of increasing interest as more companies try to integrate refining and petrochemical operations.1
PROPYLENE MAXIMIZATION In the last 10 years, the FCCU has typically been designed to produce large amounts of propylene. This has been true for catalytic crackers running both conventional and hydrotreated gasoils (GOs) and atmospheric resids. Several factors are contributing to this trend. Steam crackers are getting larger, and more are operating on ethane rather than naphtha. Ethane produces very little propylene, and other sources must be found to meet the required propylene demand. To make the situation even more acute is that propylene demands are once again expected to outpace ethylene demand. FCCUs are also getting larger. While the average FCCU processes about 40 Mbpd, new units typically range from 50 Mbpd–120 Mbpd. These units are large enough to support world-scale polypropylene (PP) facilities. To produce maximum levels of propylene, higher unit conversions are required. The increase in propylene yield comes primarily at the expense of overcracking the C6–C10 olefins in the gasoline boiling range. These higher conversions are obtained by operating in more severe cracking conditions, i.e., higher reactor temperatures, increased catalyst circulation rates for higher catalyst/oil (c/o) ratios, and/or higher catalyst activity. All of the commercial processes that maximize propylene use a pentasil (medium-sized pore) zeolite to overcrack the gasoline. Without exception, feeds that are higher in hydrogen content produce more propylene. FCCU designs. Unit designs for producing propylene enable increased severity in the reaction zone. Variations in the design parameters include: • Increasing cracking residence times by riser modifications or the addition of bed cracking • Using a downflow reaction scheme • Using advanced feed injectors with high levels of steam injection for feed atomization and optimal hydrocarbon partial pressure in the reaction system
• Applying reactor-termination technology that reduces excessive dry gas and Δ coke • Using higher c/o ratios due to the endothermic heat of cracking and operating at elevated reactor temperatures • Recycling cracked naphtha • Modifying the regenerator design to allow for the addition of extraneous fuel to maintain regeneration kinetics • Using modified and unique downstream product recovery sections • Adding product treating sections for producing a chemical- or polymer-grade product for petrochemical purposes • Using reactor designs that are compatible with the required temperatures for maximum propylene. Dual risers. There are options with dual riser designs. One configuration has two parallel reactor risers terminating into a common reactor-disengaging vessel, where the riser product effluents are combined and are recovered in a single fractionation and gas-plant recovery section. A second option is to have two reactors (riser or down flow) with separate termination vessels. The reaction products are segregated to produce fuel- and polymer-grade products. This design option allows for different operating modes and feedstocks to produce distillates or gasoline in one riser along with propylene in the second reactor. With the two reaction zones, these units can achieve propylene yields at the 12 wt% level.2, 3 Fractionator concerns. The main fractionator and gas con-
centration plants have different concerns. Due to the high conversions and better quality feedstock, the bottoms yields are minimized. This requires a careful review of the main column bottoms circuit and heat integration in the gas concentration unit.4 Additionally, a propane/propylene splitter may be included in the gas concentration to produce chemical- or polymergrade propylene. If this is the case, additional processing units are included for treating propylene for contaminant removal. TABLE 1 shows the gasoline and light-olefin yields for a conventional gasoline FCCU vs. a high-olefin FCCU (HOFCCU) for propylene.5 One drawback to producing maximum propylene is that it comes at the expense of gasoline yields and gasoline composition. While higher-severity operations can easily double or triple propylene yields, gasoline make will be reduced by 25%–50%. The gasoline composition is 2 to 3
Performance.
Hydrocarbon Processing | NOVEMBER 201479
Petrochemicals times higher in total aromatics.6 Further breakouts of propylene for the current operating modes are shown in TABLE 3. Gasoline production. Conventional FCCU units were designed to meet gasoline demand by cracking heavy GOs (HGOs) or resids that generally produce propylene yields from 3 wt%–5 wt% in a maximum gasoline mode. With the addition of a ZSM5 additive, the propylene is increased about 3 wt% on average. The high-severity FCCU (HSFCCU) mode utilizes more severely hydrotreated feedstocks or GOs from highly paraffinic crude oils to produce 12 wt% propylene yield. The catalysts and more severe operating conditions are similar to those in the traditional operation. However, these HSFCCUs are limited in processing flexibility to shift from propylene to fuels. Due to the recovery sections, these units are also limited in feedstock flexibility. High-olefin operation. The HOFCCUs were developed to produce propylene yields from 15 wt% to 20+ wt% and will yield high levels of other light olefins. The HOFCC gasoline is highly aromatic, and it is preferentially a petrochemical TABLE 1. Typical product yields for conventional gasoline vs. HOFCC comparison Typical product ranges
Gasoline FCC
HOFCC
1.5–3
3–12
Wt% on fresh feed Dry gas Ethylene
0.5–1.5
2–7
Total LPG
16–22
32–44
Propylene
4–7
12–22
Butylenes Gasoline
4–8
8–14
47–53
30–40
feedstock. However, it can be used in unique gasoline-blending pools. For example, if a refinery has isobutane available, then the HOFCCU can produce enough mixed butylenes for an alkylation process. In this case, the HOFCC gasoline may be blended with alkylate to meet fuel specifications. TABLE 2 summarizes the directional changes in the operating variables to raise propylene production, and the concerns regarding unit operation. Operating at elevated reactor temperatures is a key to producing higher propylene and other olefin yields from maximum gasoline operations. Gasoline modes have reactor temperatures ranging from 920°F to 1,000°F, while HSFCCUs require riser temperatures above 1,020°F and a cold-wall riser reactor design.7 Higher cat/oil ratios are needed from heat balance considerations and to help achieve the required high conversions. Higher reactor temperatures require increased catalyst circulation rates, as does the higher endothermic heat of cracking common to propylene processes.7 Catalyst circulation is a dependent variable; however, it is set by the heat load and Δ coke. This can limit the quality of the feed for units designed for c/o ratios above 12. If the feed quality is very high, a fired heater may be desirable. Hydrocarbon partial pressure should be minimized for producing propylene. This is achieved from lowering reactor pressure and/or by increasing steam usage. A riser steam usage of 10 wt% on fresh feed is not uncommon, and it can be as high as 30 wt%. Main fractionators need to be packed to achieve the lowest TABLE 3. Propylene yields for FCC designs and ZSM-5 Conventional FCCU FCC
FCC + ZSM-5
HOFCCU HSFCC
TABLE 2. Effects of variables on propylene yield
Reactor temperature
Adjustment
Concerns
Increase
Metallurgy
Cat/oil ratio
Increase
Cat circulation, slide valve Δ Ps
Residence time, space velocity
Increase
Δ coke
Preheat
Increase
Furnace limit, regenerator temperature control
Unit pressure
Decrease
Higher gas make, larger compressor product recovery section
Steam rate
Increase
Increase sour water recovery
Hydrocarbon partial pressure
Recycle Recycle cracked-light naphtha
Increase
Increase in product recovery
Recycle heavy oil
Increase
May back out feed, not enough to meet heat requirements
Catalyst Catalyst activity (circulating)
Increase
High cat additions, less metal tolerant, high hydrogen transfer
High Z/M ratio
Increase
High H2 transfer
High catalyst ZSM-5 additives
Increase
Lower cracking catalyst activity
Unit cell size
Decrease
Low cat activity
Higher quality
More hydrogen
Low Δ coke
Hydrotreated severity
Increase
Capital costs, lower coke precursors
Feedstock
80NOVEMBER 2014 | HydrocarbonProcessing.com
HSFCC + ZSM-5
C3= yield 3 wt%–5 wt% 6 wt%–8 wt% 10 wt%–13 wt% 15%–20% + wt%
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Petrochemicals pressures. The vessels will be larger, but less feed will need to be processed to produce an equivalent amount of propylene. Higher residence time in the reactor refers to the vapor contact time. Extra residence time is needed for riser configurations. Some control of the time is achieved by varying the riser length and diameter. Plug flow of the reactants and products is still desired to prevent unwanted reactions of the desired olefins. Additional residence time can also be facilitated by adding a second riser, recycling hydrocarbons to the reactor, or putting a catalyst bed downstream of the riser. The velocity of the oil going through the catalyst bed is normally 2 ft/sec to 3 ft/sec, so an extra 5 sec to 15 sec can be obtained with this configuration. Recycling of the cracked naphtha will produce additional propylene due to light-olefin cracking over pentasil (ZSM-5) zeolites. Additional 2 wt%–3 wt% propylene can potentially be obtained.8 Recycling of slurry may be practiced to increase the regenerator temperature when the Δ coke is too low due to the lack of TABLE 4. Typical light olefin yields for steam cracking Feedstock
Ethylene, wt%
Propylene, wt%
P/E
Ethane
80
3
0.04 (0.0375)
Propane
44
15
0.34
Naphtha
30
16
0.53
GO
23
15
0.65
coke precursors in the feed. Other techniques for increasing Δ coke have been discussed in papers and presentations covering the FCCU heat balance. Blending resid into these low-concarbon feeds can help with the unit heat balance, as both the heat of reaction and operation severity are elevated over conventional FCC operation. The feed contaminants should be considered with regard to emissions, product qualities, and impact on the catalyst.9 Feedstocks. FCCU feeds can play a significant role in deter-
mining the propylene yields. Propylene contains about 14.3% hydrogen; therefore, feedstocks that contain more hydrogen can, and will, make more propylene. Severely hydrotreated GO feeds are typically used, and crudes with high °API gravity, such as tight/shale oils, are ideal as propylene feedstocks. For HOFCCUs, the typical feedstocks are extremely hydrotreated VGOs. Resid units primarily crack hydrotreated residue in one riser and add recycle and other feedstocks to a second reaction zone. This high degree of hydrotreating has additional advantages with regard to product post-treating for producing chemical- and polymer-quality products. Coker GOs can be processed. However, these feeds should be pretreated by a high-pressure hydrotreater that not only reduces the sulfur and nitrogen but also saturates the diolefins and many of the aromatics. This also reduces the downstream finishing required to make chemical- or polymer-grade propylene. NGLs. The latest propylene-producing feedstocks being
cracked are olefinic naphthas and paraffinic naphthas derived from NGLs and tight oils. Crudes from tight oils are also being used in gasoline/diesel-mode FCCUs.
TABLE 5. Light-olefins comparison Catalytic olefins FCC
HOFCC
70% VGO + 30% VTB
85% VGO + 15% VTB
AGO
1,150°F (620°C)
1,010°F (545°C)
1,470°F (800°C)
Ethylene
24.29
3.59
31.30
Propylene
14.70
22.91
15.21
Butylenes
6.77
17.36
5.49
Butadiene
2.40
0.05
5.0
Process Feedstock Reaction temperature
Steam cracking
Light-olefin yield wt%
16 15 14 13 C3=, wt%
12 11
10 9
80 wt% conversion at 566°C riser temperature
8 7 6
0
5
10
20 15 ZSM-5 in inventory, wt%
25
FIG. 1. Effect of ZSM-5 concentration on propylene yield.
82NOVEMBER 2014 | HydrocarbonProcessing.com
30
35
CATALYSTS For producing light olefins, the cracking catalysts are a solid acidic catalyst comprising one or more active ingredients and a matrix component. The base USY cracking catalyst has a low unit cell size and is less than 50% rare earth (RE) exchanged for minimal hydrogen transfer. Depending on the feedstock, a moderate matrix activity is used. Catalyst systems, in this application, use high concentrations of a shape-selective zeolite with a pentasil crystal structure that has medium-sized pores (ZSM5), along with the typical ultra-stable Y-zeolites. The pentasil zeolites preferentially crack C6–C10 linear/near-linear gasoline olefins into predominately propylene and butylenes and yield less gasoline, which is more concentrated in aromatics. FIG. 1 shows the effect of ZSM-5 additive concentration on propylene yield is based on pilot-plant data, and it has been verified in commercial applications As illustrated, the propylene yield increases as the ZSM-5 additive concentration increases until the propylene yield reaches a plateau.10 It should be understood that a single set of tests, as presented in FIG. 1, does not necessarily define the maximum propylene yield from the feed. In gasoline/diesel mode, operations to produce more propylene, ZSM-5 additive concentrations of 3 wt%–5 wt% are in the circulating inventory. With the HSFCC mode, the additive concentration can be as high as 10% before dilution of the base cracking catalyst occurs. The HOFCC processes frequently uses proprietary catalysts, zeolites, and zeolite addi-
Petrochemicals tives to achieve the high-pentasil crystal concentrations in the circulating inventory to maximize propylene. Catalysts are a key for HOFCC processes. Due to cracking of light straight-run naphtha, condensate naphtha, tight oils and olefinic feedstocks from other refinery and petrochemical processes, research is developing different zeolites and catalysts for cracking these lighter components. The ZSM-5 additives are being investigated for higher gasoline selectivity and for producing propylene. This application may be suitable for producing more propylene in a diesel-model FCC operation.11 Other research is aimed at light-olefin cracking of larger alpha olefins (C12+) for producing more propylene and ethylene. There is additional catalyst development to crack C10+ and higher carbon numbers for increased C3=/C4=. These zeolites and catalysts apply in cracking the tail end of paraffinic naphthas in stand-alone naphtha cracking processes.12 In addition, kinetic catalytic cracking models of light feeds based on this research are being developed to gain better understanding of yields and operating conditions for cracking these light feedstocks.13
CATALYTIC OLEFINS The FCC process is used to produce propylene and ethylene from various feedstocks in specially designed catalytic cracking units. These new processes are directly competing with steam cracking of GOs and naphtha. Steam cracking is a thermal process, operating at 1,400+°F (800°C), and it is based on a free-radical-reaction mechanism for producing ethylene as the primary product. These FCC processes combine carbenium ion catalytic cracking with its β-scission mechanism with minimal thermal cracking to provide high yields of propylene with some ethylene. TABLE 4 lists light-olefin yields for steam cracking and is based on general industry knowledge. This table shows the typical ethylene and propylene yield in wt% for a pound of feed as it varies per a particular feedstock. The propylene/ ethylene (P/E) ratio indicates the selectivity of the cracking conditions to produce propylene. The P/E ratios of 0.65 and 0.53 for GO and naphtha respectively indicate that heavier feeds produce a higher ratio of propylene to ethylene. Globally, GO steam cracking is being reduced due to the GO feedstocks being diverted to produce more diesel and other fuels to meet these higher-product demands. More ethane and less naphtha are being used in steam cracking due to increased natural gas production in the US. To produce high quantities of ethylene and propylene, both thermal and catalytic cracking conditions must occur. These
units operate with reactor temperatures as high as 1,150°F. The reactor temperature is lower than steam-cracker furnace temperatures of 1,470°F (800°C). The regeneration temperature must be controlled to prevent excessive catalyst deactivation. The key to this process is the catalyst, which provides both cracking (free radical and carbenium ion) mechanisms. This catalyst has the pore size distribution to ensure secondary C5– C12 olefin cracking in the gasoline range material. A second pentasil zeolite additive may not be needed, as is typical for most propylene processes. This catalyst has robust hydrothermal and attrition properties to successfully operate at these severe operation conditions. Severely hydrotreated/mildly hydrocracked, high-H2-content VGO and resid feedstocks are required. TABLE 5 lists a comparison of light olefin yields based on pilot-plant data for catalytic olefins, FCC, HOFCC and a steam cracking unit all processing heavy oils. The catalytic olefins processes produce high levels of ethylene and propylene compared to the HOFCC. Thus, this process uses both thermal and catalytic cracking mechanisms to produce desired olefins. The high yields of ethylene and butadiene are hallmarks of the purely thermal steam cracking. The propylene and butylenes are produced in the HOFCC process due to the carbenium ion mechanism in catalytic cracking. One observation is that some of the amylenes in the HOFCC process are converted in the propylene and ethylene.9 Converting catalytically low-value olefins in the C4–C8 carbon number in a separate riser on an existing FCCU or a stand alone design can achieve significant propylene and ethylene yields. Potential olefinic feedstocks are mixed butanes, FCC light naphtha, coker and visbreaker naphthas, naphtha steamcracker pyrolysis gasoline, and other selectively hydrogenated raffinates from refinery and petrochemical complexes into propylene and ethylene.14 Catalytically cracking paraffinic naphtha to produce light olefins, propylene and ethylene, and aromatics as a liquid byproduct is competing with naphtha-steam cracking to produce propylene. The severe operating conditions with high reactor temperatures of +1,100°F mean different catalysts are required. P/E ratios of 0.7–2.4 compared to naphtha-steam cracking ratios of 0.55 P/E ratios are being produced.
AROMATICS The HOFCC produces high yields of light olefins, resulting in reduced gasoline yields with very high aromatic compositions. TABLE 6 summarizes characteristics of high-aromatic gasoline against other gasolines produced from steam cracking and continuous catalytic reforming (CCR) reformate.
TABLE 6. Concentration ranges of aromatics in gasolines11 SC pyrolysis gasoline
Reformate, low-severity
Reformate, high-severity
Conventional FCC gasoline
HOFCC gasoline
Vol% Benzene
30–40
2–6
9–12
0.5–1.5
2–5
Toluene
15–20
15–19
22–28
5–10
12–18
Xylenes, EB
5–10
16–22
22–28
2–12
22–30
+
5–10
25–35
16–30
12–18
32–40
Total
65–70
60–75
75–90
20–40
60–80
C9 aromatics
Hydrocarbon Processing | NOVEMBER 201483
Petrochemicals TABLE 7. BTX process comparison9 Catalytic olefins FCC
HOFCC
70% VGO + 30% VTB
85% VGO + 15% VTB
AGO
1,150°F (620°C)
1,010°F (545°C)
1,470°F (800°C)
Benzene
4.6
1.57
37.75
Toluene
16.56
5.69
14.85
Xylene
23.73
9.96
2.92
Styrene
1.09
—
3.55
Process Feedstock Reaction temperature
Steam cracking
C6–C8s in naphtha, wt%
The HOFCC naphtha has been characterized as high-sulfur reformate. The HOFCC gasoline, as shown, is high in BTX and would require additional refining extraction and treating if the BTX is to be recovered as a petrochemical feedstock. Hydrotreating the 160°F plus-naphtha would remove most of the sulfur, and the raffinates could be recycled to the FCCU or sent to a reformer. There are discussions in the industry for further increasing xylene production in the HOFCC gasoline. At this stage, there is limited flexibility in increasing HOFCC xylenes. Increasing catalyst RE content will only slightly increase aromatics through hydrogen-transfer reactions, which is detrimental to light-olefins production from ZSM-5.16 The key for producing xylenes is to maximize the conversion for propylene, which will concentrate the aromatics in the naphtha fraction, as shown in TABLE 6. Benzene content in HOFCC is in the 2 vol%–5 vol% range compared to the 0.5 vol%–1.5 vol% in conventional FCC gasoline that is becoming a concern in gasoline-blending pools to meet the current 1 vol% specification found in many countries. In the US, the specification is 0.62 vol%, which makes benzene-reduction technology a must. Alkylating the benzene with ethylene may be the most cost-effective way of handling this problem. If the benzene is recovered for BTX production, then it becomes an asset rather than a concern. Benzene production is very feedstock dependent. With higher aromaticity, more benzene and total aromatics are produced. Higher conversions will produce more benzene and total aromatics in addition to concentrating them in the naphtha fraction. Benzene can increase due to cyclohexane dehydrogenation or alky benzene dealkylation. Higher RE-exchanged zeolites provide higher hydrogen transfer, and moderate zeolite-to-matrix ratios that favor benzene production. Toluene production is not as affected by reactor temperatures as benzene formation as shown by an increase in the benzene-totoluene ratio. In addition, high zeolite/matrix zeolite catalysts tend to suppress additional toluene formation.15, 17 A comparison of BTX composition in the light naphtha product from a catalytic ethylene and propylene unit, an HOFCCU, and a steam cracker—all processing heavy oil—is shown in TABLE 7. Pilot-plant data is the source. The steam cracking feedstock is lighter, resulting in more benzene, and, as shown previously, high ethylene and butadiene yields are due to thermal cracking reactions. However, the catalytic olefins process does show acceptable BTX, especially xylenes, for petrochemicals. 84NOVEMBER 2014 | HydrocarbonProcessing.com
Options. A refinery that has a continuous catalytic reformer and a high-olefin FCCU can produce large amounts of C2 to C4 olefins and BTX. Middle distillates can be sold as valuable diesel, and the bottom of the barrel can be coked or hydrotreated and fed to cracking processes depending on the market needs. If a steam cracker for ethylene production is included, then C2+ recovery vs. the typical C3+ recovery of refined products provides a much more versatile and profitable refining platform. The FCC process will continue to play a central role in future refineries due to its ability to process a wide range of feedstocks, greatly reduce heavy fuel production, and make a very wide range of products including transportation fuels and petrochemicals. LITERATURE CITED Letzsch. W. S. and C. Dean, “How to make anything with a catalytic cracker,” Hydrocarbon Processing, July 2014. 2 Pinho, A., et al., “Double Riser FCC: An Opportunity for the Petrochemical Industry,” 2006 NPRA Annual Meeting, March 2006, Paper AM-06-13. 3 “Milos Shell’s Ultimate Flexible FCC Technology in Delivering Diesel/ Propylene,” 2008 NPRA Annual Meeting, San Diego, March 9–11, 2008. 4 Golden, S. et. al, “Catalyst changes, downstream improvements increase FCC propylene yields,” Oil & Gas Journal, Oct. 4, 2004. 5 Kapur, S. and R. Anil, “Catalytic Routes to Olefins Shaping the Integrated Complex Configuration,” AIChE National Meeting, New Orleans, April 2008. 6 Couch, K. A., et al., “FCC Propylene Production—Closing the Market Gap by Leveraging Existing Assets,” 2007 NPRA Annual Meeting, San Antonio, Texas, March 2007, Paper AM-07-63. 7 Lambert, O., et al., “HS-FCC for propylene: Concept to commercial operation,” Petroleum Technology Quarter, 1Q, 2014. 8 “Evolution of resid to propylene Axens,” Technip S&W Axens 10th FCC Forum, May 2013. 9 Swaty, E., et al., “Catalytic pyrolysis process (CPP) and it integration with a refinery and petrochemical plant,” PetroTech, 2003. 10 Xhao, X. and T. Roberie, “ZSM-5 Additive in Fluid Catalytic Cracking, Effect of Additive Leveland Temperature on Light olefins and Gasoline Olefins,” Industrial & Engineering Chemistry, 1999. 11 Buchana, et al., “Gasoline selective ZSM-5 FCC additives; effects of crystal size, SiO2 /Al2O3 . Steaming and other treatments on ZSM-5 diffusivity and selectivity in cracking of hexene/octene feed,” Applied Catalysts, 2001. 12 Le Van, M., et al., “Catalytic Cracking of Heavy Olefins into Propylene Ethylene and Other Light Olefins,” Catalyst Letter, March 4, 2009. 13 Longstaff, D., “Development of Comprehensive Naphtha Catalytic Cracking Kinetic Model,” Energy & Fuels, American Chemistry Society, 2012. 14 Len, A. S. and T. Pavone, “An alternative option for producing light olefins,” Petroleum Technology Quarter, Winter 2004. 15 Dean, C. F., “Naphtha catalytic cracking for propylene production,” Petroleum Technology Quarter, Processing Shale Feedstocks, 2013. 16 Petroleum Technology Quarter, 4Q, 2013,” p. 6. 17 Yatsu, et al., “Benzene Levels in Fluid Catalytic Cracking Gasoline,” Chapter 3, Fluid Catalytic Cracking, Vol. III, 1994. 1
WARREN S. LETZSCH has 46 years of experience in petroleum refining including petroleum catalysts, refining, and engineering and design. His positions have included R&D, technical service and sales, which have led to senior management positions in sales, marketing, and technology development and oversight. He was one of the developers of the Technip/Axens R2R process, and has authored over 80 technical papers. Mr. Letzsch holds eight patents in the field of fluid catalytic cracking. He was the FCC/DCC program manager at Stone & Webster for 10 years and is now a senior refining consultant for Technip, as well as a private consultant to the refining industry. CHRISTOPHER DEAN is an independent process engineering consultant with over 37 years in the worldwide refining business with an emphasis on high olefin fluid catalytic cracking (HOFCC) with petrochemical integration. He is the founder and principal consultant for High Olefins FCC Technology Services LLC. His worldwide refining background includes the development and commercialization of the High Severity-FCC Process, the development of several integrated refinery and petrochemical projects, catalyst technical service, process engineering, design and unit operations on a variety of refinery units. He has published or presented over 30 papers and has been issued two patents on FCC gasoline desulfurization and has three other FCC pending process patents.
Refining Developments G. HOFFMAN and D. LONGTIN, Baker Hughes, Sugar Land, Texas
Manage the impacts of high-solids crude oil more effectively Solids in crude oils present refiners with many challenges. Processing higher-solids-content crude oils increases the need for the management of such solids even more. The Canadian Association of Petroleum Producers forecast that oil production from the country’s oil sands will rise from 1.8 MMbpd to 5.2 MMbpd by 2030.1 These high-viscosity crudes tend to carry high solids loadings due to their extraction methods. The shale crudes being produced in large quantities also have demonstrated high solids loadings. The problems associated with high-solids crude oils will continue to pose major challenges. Traditional treatment. The refining industry has been seek-
ing a means to increase solids removal via the desalter for more than 40 years, but with minimal consistent success. Refineries that process high-solids-content crude oils effectively, without experiencing operating and integrity issues, can increase the volume of opportunity crudes processed, and, consequently, raise profitability. When present in the crude, these constituents can cause many problems, including fouling of crude tanks, desalter unit upsets, increased energy use, catalyst deactivation, and downgrading of product value. Poor desalter operation can also strain wastewater treatment units (WWTUs) and lead to noncompliance issues. These attractively priced crude oils, however, remain desirable feedstocks. The alternative is to avoid processing these challenging crudes and to miss significant profits. A new method is needed to effectively remove solids, and thus enable the processing of opportunity crudes.
NATURE AND IMPACT OF SOLIDS Crude oil contains a wide range of naturally occurring solids and contaminants, and is co-produced with large volumes of brine/water, which is largely removed at the production site. However, a small proportion of the produced water remains in refinery crude receipts, carrying dissolved salts with the crude. The first step in the refining process is the desalter; it is a process designed to remove salts and water from the crude oil. Crude oils also contain inorganic solids, e.g., silicon and aluminum oxides, iron sulfides/oxides, carbonates, sulfates and basic sediment (BS). These solids are typically coated with oil and are not easily separated from the oil by the desalter. Instead, they accumulate in emulsion layers before being carried downstream with the crude oil, or released (with entrained crude oil) into the effluent brine stream.
Solids are quantified by a filtration using (in most cases) 0.45-µ pore filter media. A more-recent concern arises with the size of solids, with finer particulates (less than 0.45 µ) becoming more prevalent. If not removed in a controlled and oil-free fashion in the effluent brine, the solids and other contaminants can cause various issues that cascade through the downstream oil and WWTU: Tank fouling, emulsions and sludge. Solids can stabilize emulsions that accumulate as a layer of sludge in the bottom of crude storage tanks. These layers reduce the effective working tank volume. If the sludge is disturbed and released into the crude oil, it can negatively impact the desalter operation. Sludge must also be handled and processed as hazardous waste during tank cleaning, which adds to the refinery maintenance burden. Fouling of downstream equipment. Equipment vulnerable to fouling includes heat exchangers, furnaces, towers, FCC unit diplegs and expanders. There are many causes for fouling, including organic fouling (asphaltene deposition and sodiumcatalyzed coke formation) and inorganic fouling (solids carrying over with desalted crude). Inorganic constituents can be a major contributor in the fouling process. Desalter unit upsets. Slugs of high-water or high-solids crudes from tankage, or the addition of slop oil (which is inherently high in emulsion and solids) can upset the desalter and cause temporary loss of performance, translating into negative consequences for downstream process units and WWT processes. Wastewater noncompliance. Emulsions containing oily solids can lead to oil undercarry in the desalter and, consequently, problems for the WWTU. Transition metals such as iron (Fe), nickel and zinc can also harm WWTUs. These issues can make it difficult to maintain final effluent water quality and achieve environmental compliance. Furthermore, the oil and emulsions contained in these excursions are frequently returned to the crude charge unit as refinery slop oil. Corrosion. Poor oil/water separation in the desalter leads to higher levels of water (along with dissolved salts) in the desalted crude. The higher salt content can lead to higher corrosion incidences of the crude tower overhead system. Up to half of refinery maintenance costs are spent on corrosion issues. Increased energy use. Fouling can cause heat transfer loss and increase energy use. Catalyst poisoning. Iron and other transition metals can deactivate downstream catalyst systems, thus reducing the catalyst’s effectiveness and service life. Hydrocarbon Processing | NOVEMBER 201485
Refining Developments Loss of product value. Because solids tend to concentrate in bottom streams, they can introduce ash and metals into residual products, which downgrade the value of delayed coker “coke” products. Removing solids at the desalter is a highly desirable goal. It provides substantial benefits for downstream processing units and the WWTU. More importantly, effective solids management can enable refiners to maximize profit opportunities by processing challenging crude oils.
CONVENTIONAL DESALTING AND SOLIDS MANAGEMENT The desalting process mixes water with crude oil and then uses time, electrical fields and chemicals to separate the oil and water. The goal is to produce desalted crude that contains minimal salt and water, and oil-free effluent brine water. Missing in this scenario is what happens to the inorganic solids. The oil-coated solids tend to accumulate at the oil/water interface (often called the emulsion or rag layer) in the desalter. Various primary demulsifying agents are applied to enhance oil/water separation, and adjunct chemicals (such as wetting agents) may be applied to aid in de-oiling the solids. The larger-size solids will fall to the bottom of the desalter and are, ultimately, removed via periodic or continuous mud washing. Smaller solids are neutral-buoyant, especially if the residual oil remains on the surface; thus, they do not drop out of the oil/water interface. The desalter operation can be optimized to meet salt removal targets. Increased mixing energy, higher wash-water rates, and improved level control are variables that can optimize salt removal. However, experience shows that only marginal increases in solids removal are achieved via these steps. Demulsification. Primary demulsifier chemistries are routinely applied at the suction side of the desalter unit charge pump. Demulsifiers can effectively break emulsions.2 The formulations include chemistries designed to strip oil from the surface of solids. Injecting adjunct chemistries with the emulsion breaker is often practiced using surfactants designed to water-wet the solids (“wetting” agents). These conventional chemistries can help reduce the emulsion-stabilizing impact of oily solids. They do not readily allow the solids to be released from the oil/water interface. Treatments. In the 1980s, new pretreatment or precondition-
ing technologies were developed to address the challenges of TABLE 1. Pretrial desalter profile Sample
Filterable solids, PTB
Solids, %
Water, %
Oil, %
Raw
64
0.1
0.2
0.0
Desalted
44
0.05
0.5
0.0
3,715
5
73.3
21.7
Tryline #4
6,484
6.5
76.8
16.7
Tryline #3
26,744
28
48.7
23.3
Tryline #2
20,365
25
50.0
25.0
Tryline #1
4,907
6.6
86.7
6.7
11
0
100
0.0
Tryline #5
Effluent
86NOVEMBER 2014 | HydrocarbonProcessing.com
desalting West Coast crudes.3 The principle is simple. Chemical reactions rely on molecular interactions that can be relatively slow when the treatment chemicals and emulsion-stabilizing solids are present in ppm levels. Consequently, when chemical agents are added to the desalter, insufficient time prevents the agents from achieving their full potential. Adding the chemicals early in the tankage can provide more time to react with the solids, thus making the process more effective. Greater residence time enables the agents to associate effectively with, and water-wet, the solids; stabilize the asphaltenes; and reduce the emulsion-stabilizing impact of solids. The agents also break up micro-emulsions above and within the sludge blankets found in crude storage tanks. Preconditioning technology has been refined and applied as the most effective solution for desalting heavy crudes and recovered oils, resulting in improved solids removal. However, efficient removal of solids remains a challenge, especially with the higher incidence of “micro-fine” solids (smaller than 0.45 µ). Conventional technology, including advanced pretreatment, can help manage the emulsion-stabilizing impact of solids. As solids loadings rise, however, more tools are needed to remove these solids, using the desalter equipment.
A NEW APPROACH Canadian oil sands are high-solids crude oils. They often contain higher-than-average solids loadings due to the production methods. These oil-sand-derived crude oils are processed in a significant number of North American refineries, and the impact of solids from these crude oils is well documented.4, 5 In 2011, a research and development project was conducted to generate an improved method to manage solids in the desalter. The project focused on developing new emulsion characterization methods, pretreatment chemicals, and a desalter chemical additive to help transport solids (including sub-µ-diameter solids) from the emulsion layer into the brine. Phase 1 of the project was a critical starting point because the conventional testing methods were judged to fall short in accurately assessing micro-fine solids stabilization mechanisms and removal capabilities. The new test methods focused on measuring solids in various phases (oil, water and emulsion) and clearly distinguishing the efficacy of various chemistries to promote solids release. In Phase 2, product development led to several new product formulations. Phase 3 used chemical screening to ensure that new solids-release chemistry would not interfere with the primary function of the desalter (salts and water removal from crude oil). In Phase 4, pilot testing was designed and conducted to test the top product candidates and chemical strategies, and to confirm potential options for field tests. In Phase 5, an actual field test was undertaken to confirm project learnings. Through the project, an innovative solids release agent (SRA) was developed to remove solids from the oil phase and then to be removed in the brine water.a Initial field application. In 2012, a trial was conducted on a
desalter processing 100% high-solids, heavy Canadian crudes. The desalter routinely operated with excellent salt removal and oil-free effluent brine water. However, the desalter vessel also operated with a large emulsion layer between the oil and wa-
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Refining Developments ter, and sometimes with an emulsion layer at the bottom tryline. This emulsion layer was very high in solids concentration (> 2 wt%), which could negatively impact downstream units. TABLE 1 summarizes the desalter profile before SRA injection. The data indicate that the solids content in the effluent brine was low, but the tryline solids loadings were very high. This is a common result when processing high-solids crude oils. After
four hours of the new SRA, the impact was visually apparent; solids settled in the tryline samples and solids-free oil rose in the desalter.a FIG. 1 shows the appearance of the bottom tryline sample before chemical injection and after four hours of treatment. Within three days of the new SRA treatment, the solids profile in the desalter showed very clear downward migration of solids.a FIG. 2 demonstrates the descent of the solids to the lower trylines.6 During this same period, the total filterable solids volume in the trylines fell from 60,000 lb/1,000 bbl (PTB) or 171,000 mg/l to 38,000 PTB (108,000 mg/l). The solids content in the effluent brine also increased markedly from < 11 PTB, or 31 mg/l, to more than 1,400 PTB (4,000 mg/l), as illustrated in FIG. 3. As shown in FIG. 4, the effluent brine sample exhibits significant accumulation of solids on the bottom and no free oil in the sample. The trial demonstrated that the new SRA technology readily released solids from the emulsion/interface and enabled the solids to move into the brine, which remained oil-free.a The original project objective of releasing solids to the brine without free oil was achieved.
FIG. 1. Tryline #1 sample and visual appearance before and after treatment. TR5 Pretrial 100% emulsion
TR4 TR3 TR2 TR1 Brine
Day 1
Day 2
Baseline
Day 3
SRA treatment
FIG. 2. Descent of solids in desalter trylines with and without SRA treatment.a FIG. 4. Brine sample containing more than 30% solids and no oil. 1,600 1,472 1,400
1,367
100
1,297
90
1,200 1,000
Filterable solids removal, %
Brine solids, PTB
80
800 600 400 245 0
6 Day 1 Baseline
70 60 50 40 30 20
200 11
Normal operations Using SRA
Day 2
Day 3
Day 4
10 0 Pre-trial
Day 0
Day 1
Day 2
Day 3
SRA treatment
FIG. 3. Brine solids increase (PTB) with the new customized SRA.a
88NOVEMBER 2014 | HydrocarbonProcessing.com
FIG. 5. Solids removal efficiency improved by more than 50% with customized SRA.a
Refining Developments
Desalter trylines
5
Day 3
5
cation of the new technology was initiated in response to problems seen at a refinery fluid catalytic cracking unit (FCCU). The FCCU feed includes crude unit tower bottoms, which brings solids to the unit. These solids are high in Fe content. The impact at the FCCU is two-fold: • Buildup of deposits on the regenerator expander blades leads to vibrations and requires periodic cleanup. • High Fe content impacts catalyst activity. The goal of the new SRA program was to reduce the vibration events and reduce Fe loading on the catalyst.a Improved Fe control would reduce catalyst-makeup costs. The treatment resulted in a substantial increase in solids releasing into the brine, where solids content increased from < 10 PTB (90 mg/l) to an average of 380 PTB (>1,000 mg/l). Of equal importance, the Fe content in the brine increased in conjunction with the solids (FIG. 7), along with a comparable reduction in Fe loading on the FCC catalyst (FIG. 8). Program success was also indicated in the data by a mass balance of the solids entering the desalter, with the solids leaving in the desalted crude and brine. In a typical desalter processing high-solids crude oil, it is not uncommon to see a 40% to 60% reduction in solids from the raw crude to the desalted crude oil. However, the solids measured in the effluent brine often do not reflect the solids removed from the crude, which indicates that the solids are accumulating inside the desalter (in the “rag” layer and/or on the bottom of the desalter). In these 800
400 300
400
Iron, ppm
500 Baseline solids = 4 PTB average Fe < 1 ppm average
300
200
200
100
Brine solids, PTB Brine Fe content, ppm
100 0
0 1
2
3
4
5 6 7 8 9 Time in operation, months
10
11
12
FIG. 7. Solids and iron content in the brine rose significantly with the use of the new SRA technology.a 0.75
Day 4 0.65
4
4
4
3
3
3
2
2
2
0.35
1
1
1
0.25
0
Program maintenance solids = 388 PTB average Fe = 161 ppm average
Program optimization 700 solids = 106 PTB average Fe = 69 ppm average 600
Fe on FCC catalyst, wt %
Day 0
5
Case 2: Iron reduction in FCC unit feed. An ongoing appli-
Solids, PTB
Case 1: 30% paraffinic-froth-treatment crude. A US Gulf Coast refinery took possession of paraffinic-froth-treatment (PFT) crude cargo when a nearby refinery, whose desalters were treated with a different chemical treatment could only process the heavy Canadian crude at less than 5% feed. Even at such low levels, the sister refinery still experienced a large desalter emulsion band and significant oil undercarry, which upset its WWTU. The new owner of the PFT crude parcel had previous success running low-percentage blends of this same crude after the implementation of a crude management program.b, c However, the refinery wanted to maximize the blend percentage of the PFT crude and determine the long-term potential to fully exploit the lower-priced opportunity crude. To achieve the ambitious goal, a new SRA technology was recommended and developed specifically to handle the ultrafine solids in PF-treated tar-sand crudes.a The active chemistries in the new SRA remove oil from the fine solids, releasing them from the emulsion layer to the brine, allowing them to be properly and easily handled through the refinery’s WWTU. The maximum rate test was initiated with the PFT crude at 12% of crude charge and ramped up to 30% over the course of several days, ultimately limited only by crude availability and product yields. Throughout the run, brine quality remained exceptional, and oil and grease levels were kept below established limits, thus preventing any detrimental impact on the refinery WWTU. The use of new SRA technology was successful in reducing the size of the desalter emulsion layer and improving the solids removal efficiency by more than 50%.a While normal filterable solids removal at this refinery had averaged 50%–60% during previous heavy crude operations, the use of new the SRA increased removal to 80%–85%, as shown in FIG. 5. Additionally, the downward migration of solids from the emulsion layer into the brine was confirmed by filterable solids measurements of each of the desalter trylines before and during the test run, as shown in FIG. 6. As a result of the implementation of this new combined crude management approach together with SRA, the refinery was able to increase the blend percentage of the PFT crude to 30% without any detrimental impacts to the brine handling system or wastewater treatment plant.a, c Given publicly available data on crude margins at the time of this case study, the refiner captured more than $350,000 in opportunity crude profits during the four-day run and identified the potential for even greater longterm returns on this PFT crude oil by using SRA technology.a
5 10 15 20 0 5 10 15 20 0 5 10 15 20 Filterable solids content, % Filterable solids content, % Filterable solids content, %
FIG. 6. Downward migration of solids from the emulsion layer into the brine with customized SRA.
0.55 0.45
Program optimization
Baseline 1
2
3
4
5 6 7 8 Time in operation, months
Program maintenance 9
10
11
12
FIG. 8. With the use of the new SRA technology, e-cat Fe loading was significantly reduced, helping to prolong catalyst life.a Hydrocarbon Processing | NOVEMBER 201489
Refining Developments cases, the measured brine solids often represent only a small percent of the solids removed from the raw crude. If solids release is truly successful, a mass balance of the solids should be reflected in the solids leaving with the brine water. During the trial, the solids content in the brine was minimal during the baseline period. After optimizing the SRA treatment, the solids in the brine demonstrated excellent agreement with the solids removed from the crude oil, as shown in FIG. 9.a The new SRA program results were clear and sustainable.a Increased solids and Fe released with the desalter effluent brine water stopped the expander vibration events and improved
Solids material balance, %
Program optimization Average closure = 17%
Options. The new SRA technology can greatly enhance the re-
lease and removal of solids from crude oils. It provides a striking improvement in solids removal and control, and reduces the impact of solids and contaminants on refining processing equipment. This new technology is another tool that can enable the refiner to process opportunity crudes and maximize refinery profitability.a, b, c High-solids crudes, including those prone to contain micro-fine-sized solids, are no longer off-limits. Solids management is a viable action. ACKNOWLEDGMENT This article is based on an earlier presentation at the 2014 AFPM Annual Meeting in Orlando, Florida, March 23–25, 2014.
Program maintenance Average closure = 98%
Baseline Average closure = 2%
Fe loadings on (and extended the life of) the FCCU catalyst. These excellent results were achieved while maintaining outstanding desalter performance (salt removal and dehydration) and oil-free brine—with no increase in wastewater chemical oxygen demand (COD).
NOTES A customized solids-release agent offered by Baker Hughes under the JETTISON trademark. b A heavy oil demulsifier offered by Baker Hughes under the XERIC trademark. c The refiner used the Baker Hughes Crude Oil Management program and XERIC heavy-oil demulsifiers. a
0.25
1
2
3
4
5 6 7 8 Time in operation, months
9
10
11
12
FIG. 9. Solids material balance: Removal from crude vs. contained in effluent brine.
LITERATURE CITED “Crude Oil Forecast, Markets & Transportation,” June 2013, The Canadian Association of Petroleum Producers (CAPP). 2 “Chemical inventions that revolutionized the hydrocarbon processing industry, Downstream Innovations, 1922 to Present,” Hydrocarbon Processing, July 2012, pg. D-140. 3 Kremer, L. and S. Bieber, “Strategies for Desalting Heavy Western Canadian Feedstocks,” NPRA Annual Meeting, San Diego, California, March 9–11, 2008, Paper AM-08-36. 4 Kremer, L. and S. Bieber, “Rethink desalting strategies when handling heavy feedstocks,” Hydrocarbon Processing, September 2008, pp. 113–120. 5 Cornelius, S., D. Jackson and D. Longtin, “Baker Hughes Assault on Salt,” Hydrocarbon Engineering, 2012. 6 “Desalter Solids Release Agent Test Results,” Customer Report—Review with Baker Hughes, Sept. 20, 2012. 7 “A Strategy to Reduce Operating Costs and Increase Throughput,” Internal reference, 1990, Baker Hughes. 1
GERALD HOFFMAN II is currently the senior separations technologist for the Baker Hughes Separation Technology Group. During his nearly 30 years of experience in the oil and gas industry, he worked for Exxon for 15 years in roles including manufacturing, management and sales in the refining sector; prior to becoming the technical manager for BJ Services from 1996 until Baker Hughes purchased BJ in 2011. His expertise includes the midstream sector, as well as desalting, corrosion and fouling mitigation in the refining sector, and finished fuel treatment. Mr. Hoffman II holds a BS degree from the University of Southwestern Louisiana and an MBA from the University of Houston. DOUG LONGTIN, technical manager for the Baker Hughes Downstream Division, has more than 30 years of experience in the hydrocarbon processing industry. For more than 10 years, he has focused on and addressed refinery desalting issues to improve customer operations, reliability and profits while processing difficult opportunity crude oils. He has championed Baker Hughes EXCALIBUR contaminant removal technology and has recently worked in the development and implementation of Baker Hughes JETTISON solids release agents technology, addressing emulsion resolution and desalter solids management. Mr. Longtin holds a BS degree in pulp and paper engineering from SUNY College of Environmental Science and Forestry, Syracuse University.
90
Select 166 at www.HydrocarbonProcessing.com/RS
ADRIENNE BLUME, MANAGING EDITOR
[email protected]
Innovations
Software helps optimize energy performance In November, Yokogawa Electric Corp. is releasing Energy Performance Analytics (EP-Analytics), a software tool (FIG. 1) that uses energy performance indicators (EnPI) to track how energy is consumed in a plant. The tool identifies gaps between EnPI targets and actual performance, and it helps identify countermeasures to improve energy performance. The EP-Analytics software is powered by the Soteica Visual MESA energy management and optimization solution. Manufacturers around the world are working to improve their energy performance and protect the environment by reducing greenhouse gas emissions. Released in 2011, the ISO50001 standard provides a framework of requirements that help companies in the process industry effectively manage their energy performance and achieve regulatory compliance. By visualizing and tracking the energy consumption of each unit in a plant, inefficiencies can be easily identified and located. The EP-Analytics software runs on a workstation that is connected via an open connectivity interface to the control system, giving it access to pressure, temperature, flowrate and other plant data. Based on the Visual MESA simulation engine, the EP-Analytics software uses first-principle models to track energy flows throughout the plant and to calculate the energy performance for each individual process unit and piece of equipment, including turbines, boilers, and other plant systems and equipment. It also calculates the mass balance of the steam and other forms of energy that are supplied to the production processes, and it can quantify energy losses and other imbalances in the overall system. This information can then be used to plan specific countermeasures. EP-Analytics is designed to support manufacturers’ rollout of ISO50001. The EP-Analytics software supports ISO50001 methodologies, such as the
plan-do-check-act (PDCA) cycle, as well as activities like management reviews. Select 1 at www.HydrocarbonProcessing.com/RS
Bioreactor removes bulk contaminants from wastewater UOP’s XCeed bioreactor is an advanced biological treatment process for the bulk removal of organic and inorganic contaminants, making it suitable for industrial wastewater treatment and groundwater remediation applications. Based on Honeywell’s immobilized cell bioreactor technology, the XCeed bioreactor system has been proven in more than 50 worldwide installations, including refining and petrochemicals, food and beverage, chemical and textile manufacturing and groundwater remediation applications. The system’s plug-flow configuration (FIG. 2) uses a series of packed beds for contaminant removal. Water flows through the bioreactor, cascading from one section to another via hydraulic head. This compartmentalization simulates quasi-plug-flow characteristics in the system, promoting high removal efficiency
in a compact reactor. Compartmentalization also promotes the spatial separation of specific metabolic processes, such as organics removal and nitrification. The absence of mechanical equipment in the design minimizes energy consumption and reduces overall process complexity. Proprietary packing media provides surface area for immobilized biocatalysts—or microbes—to grow. More complex generations of microbial growth result from biomass retention times of nearly 100 days. This biological ecosystem promotes the growth of microbes such as protozoa, nematodes, rotifers or oligochaeta that reduce biomass production by predation of the primary trophic microorganisms. As a result, the process produces up to 80% less sludge than alternative systems. In addition, the nature of the microbial population results in resistance to upstream process changes and allows the bioreactor to quickly reach a steady state after a restart (typically within two days). The XCeed bioreactor system can be delivered as a skid-mounted package or as a retrofit to an existing basin. Each system is designed and installed based on site-specific requirements and incor-
FIG. 1. The EP-Analytics software uses energy performance indicators to track how energy is consumed in a plant. Hydrocarbon Processing | NOVEMBER 201491
Innovations rooms. The X-zone Com works by sending all data and alarms to users by email, by text message and by a central Cloud application, meaning that hazardous-area monitoring can be accessed across a wider range of channels. Up to 15 Dräger X-zone Com systems can automatically connect to a wireless alarm chain, which will accurately and comprehensively monitor large areas. Only one X-zone Com is subsequently required to transmit the data of the entire chain, including the exact location of the hazard, in a matter of seconds. Due to the wide storage capability of the Cloud, ongoing analysis of data and trends is also possible. The communications system offers a holistic solution covering all important measures related to evacuation and protection, as well as the elimination of the problem and the quick, efficient and safe resumption of work. Select 3 at www.HydrocarbonProcessing.com/RS
FIG. 2.The XCeed biological treatment process for bulk contaminants removal has a plug-flow configuration that uses a series of packed beds for contaminant removal.
• Biomass loading: up to 10 kg BOD5 per m3/day • Energy consumption: approximately 0.1 kw/hr/kg BOD removed Results from more than 50 full-scale installations have demonstrated reductions of organic and inorganic contaminants by up to 98%, helping various industrial facilities meet regulatory requirements and internal standards for quality, reuse or other processing operations. Select 2 at www.HydrocarbonProcessing.com/RS
FIG. 3. The X-zone Com communications system enables users to track gas detection levels from outside areas being monitored.
porated into the overall treatment train to provide a total solution that meets water quality goals. Typical operating parameters include: • Mixed-liquor suspended solids: 7,000 ppm to 10,000 ppm • Biomass retention time: approximately 100 days • Sludge yield: approximately 0.08 kg biomass/kg biological oxygen demand (BOD) consumed 92NOVEMBER 2014 | HydrocarbonProcessing.com
Communications system enables remote gas detection Dräger’s new communications system, the X-zone Com (FIG. 3) system, enables users to track gas detection levels from outside the areas being monitored. Within all chemical and petrochemical plants, workers often find themselves in confined spaces and hazardous areas, where the danger of a hazardous gas occurring is always present. Connecting gas detection systems to the X-zone Com communications device means that data can be transferred wirelessly to mobile devices or to control
Moisture transmitter introduces integral display Michell Instruments’ Easidew PRO XP explosion-proof dewpoint transmitter is now available with an optional integral display, for improved ease of use. The local display provides engineers with readings of moisture at the point of installation, enabling them to carry out checks and make adjustments without referring to the control room. The Easidew PRO XP with display is capable of measuring moisture in both gases and non-polar liquids. The transmitter is housed in an epoxy-coated aluminum casing as standard; an alternative 316 stainless steel casing is available for offshore applications. The transmitter uses ceramic moisture sensing technology from Michell, and it is capable of measuring dewpoints in gases from −110°C to 20°C and from 0 ppmv–3,000 ppmv. In liquids, the measurement range is from 0 ppmw–3,000 ppmw. With a 450-bar pressure rating, EN10204 3.1 material-certified parts and an NPL/NIST 13-point calibration certificate, the transmitter meets existing demands of the process industry. Select 4 at www.HydrocarbonProcessing.com/RS
An expanded version of Innovations can be found online at HydrocarbonProcessing.com.
HELEN MECHE, ASSOCIATE EDITOR
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Events
NOVEMBER Sulphur 2014 International Conference & Exhibition, Nov. 3–6, Paris Marriott Rive Gauche Hotel & Conference Center, Paris, France P: +44 207 903 2444
[email protected] www.crugroup.com Gulf Publishing Company Events, 2014 Women’s Global Leadership Conference in Energy, Nov. 4–5, Hyatt Regency Houston, Houston, Texas www.wglnetwork.com (See box for contact information) 5th World Shale Oil & Gas Summit, Nov. 4–7, Fairmont Dallas Hotel, Dallas, Texas P: +44 (0) 207 978 0025
[email protected] www.world-shale.com Latin American Petrochemical and Chemical Association (APLA) 34th Latin American Petrochemical Annual Meeting, Nov. 8–11, Hotel Sofitel, Rio de Janeiro, Brazil P: +54-11-4325-1422
[email protected] www.apla.com.ar API Fall Refining and Equipment Standards Meeting, Nov. 10–13, Sheraton Denver Downtown Hotel, Denver, Colo. (See box for contact information) 9th Annual API Cybersecurity Conference & Expo, Nov. 11–12, Westin Houston Memorial City, Houston, Texas (See box for contact information) Chemical Institute of Canada (CIC) Industrial Chemistry Conference, Nov. 12–14, Edmonton. Alta., Canada P: +1 (613) 232-6252
[email protected] www.cic2014.ca American Fuel and Petrochemical Manufacturers (AFPM) International Lubricants & Waxes Meeting, Nov. 13–14, Hilton Post Oak, Houston, Texas P: +1 (202) 457-0480
[email protected] www.afpm.org
CORCON 2014—Corrosion Conference & Expo, Nov. 12–15, Hotel Grand Hyatt Mumbai, Mumbai, India P: +91-22-2579 79 30 F: +91-22-6692 15 72
[email protected] www.corcon.org American Society of Mechanical Engineers (ASME) 2014 International Mechanical Engineering Congress & Exposition, Nov. 14–20, Palais des Congres, Montreal, Quebec, Canada P: +1 (973) 882-1170
[email protected] www.asme.org American Institute of Chemical Engineers (AIChE) Annual Meeting, Nov. 16–21, Atlanta Marriott Marquis & Hilton, Atlanta, Ga. P: +1 (203) 702-7660 F: +1 (203) 775-5177
[email protected] www.aiche.org Asian Nitrogen + Syngas 2014, Nov. 17–19, Ritz Carlton, Jakarta, Indonesia P: +44 (0) 20 7903 2444
[email protected] www.nitrogenasia.com ERTC 19th Annual Meeting, Nov. 18–20, Corinthia Hotel Lisbon, Lisbon, Portugal P: +44 (0) 207 484 9700
[email protected] events.gtforum.com/ ertc-annual-meeting North American Pipeline Congress, Nov. 19–20, The Westin Chicago River North, Chicago, Ill. P: +1 (403) 209-3555
[email protected] pipelinecongress.com
DECEMBER Valve World 2014 Expo and Conference, Dec. 2–4, Messe Düsseldorf, Düsseldorf, Germany P: +49 (0) 211 45 60 01 F: +49 (0) 211 45 60-668 valveworldexpo@ messe-duesseldorf.de www.valveworldexpo.com
Shanghai 9th International Petroleum Petrochemical Natural Gas Technology Equipment Exhibition (SIPPE), Dec. 4–6, Shanghai New International Expo Center, Shanghai, China P: +86-21-65929965
[email protected] www.sippe.org.cn/en/
8th Annual European Gas Conference 2015, Jan. 27–29, Vienna, Austria P: +44 (0) 207 384 8015
[email protected] www.europeangas-conference.com
FEBRUARY 2015 ARC’s 19th Annual Industry Forum, Feb. 9–12, Renaissance Orlando at SeaWorld, Orlando, Fla. P: +1 (781) 471-1000
[email protected] www.arcweb.com
CATCON2014, Dec. 8–9, Hyatt North Houston, Houston, Texas P: +1 (215) 628-4447
[email protected] www.catalystgrp.com Institution of Mechanical Engineers (IMechE) Piping and Pipeline Risk-Based Inspection, Dec. 9, Aberdeen Marriott Hotel, Aberdeen, Scotland, UK P: +44 (0) 20 7222 7899
[email protected] events.imeche.org LPG Asia, Dec. 9–11, Traders Hotel, Singapore, Singapore P: +65 6508 2401
[email protected] www.lpgasiaconference.com Center for Chemical Process Safety (CCPS) 2014 Global Summit on Process Safety, Dec. 15–16, Lalit Hotel, Mumbai, India P: +1 (646) 495-1371
[email protected] www.aiche.org American Society of Mechanical Engineers (ASME) Gas Turbine India Conference, Dec. 15–17, New Delhi, India P: +1 (973) 882-1170
[email protected] www.asmeconferences.org
JANUARY 2015
Middle East Turbomachinery Symposium, Feb. 15–18, Sheraton Doha Resort & Conference Hotel, Doha, Qatar P: +1 (979) 862-1012
[email protected] mets.tamu.edu/ Society of Plastics Engineers (SPE) South Texas Section, International Polyolefins Conference 2015, Feb. 22–25, Hilton Houston North, Houston, Texas P: +1 (713) 829-9226
[email protected] spe-stx.org/conference.php CORROSION 2015, Mar. 15–19, The Kay Bailey Hutchison Convention Center, Dallas, Texas P: +1 (281) 228-6200
[email protected] nacecorrosion.org
MARCH 2015 Gulf Publishing Company Events, Energy Construction Forum, Mar. 3–4, Moody Gardens Convention Center, Galveston, Texas EnergyConstructionForum.com (See box for contact information) Hydrocarbon Processing/ Gulf Publishing Company Events P: +1 (713) 529-4301 F: +1 (713) 520-4433
[email protected] [email protected]
The Future of Aromatics, Jan. 14–15, Amsterdam, The Netherlands P: +44 (0) 203 141 0605
[email protected] www.wplgroup.com API 2015 Inspection Summit, Jan. 26–29, Galveston Island Convention Center, Galveston, Texas (See box for contact information)
American Petroleum Institute (API) P: +1 (202) 682-8000
[email protected] www.api.org
Hydrocarbon Processing | NOVEMBER 201493
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Why Should You Filter Your Water?
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