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HARNESS THE POWER

RENTECH engineers build unmatched power and performance into every boiler we deliver. Our 80-acre manufacturing facility—the industry’s most

technologically advanced—includes heavy bay and light bay areas with direct access

to rail, cross-country trucking routes and shipping facilities. We master every detail to

deliver elemental power for clients worldwide. Take an expanded tour of our facilities

today at www.rentechboilers.com/facilities

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OF MANUFACTURING INNOVATION

HEAT RECOVERY STEAM GENERATORS

WASTE HEAT BOILERS

FIRED PACKAGED WATERTUBE BOILERS

SPECIALTY BOILERS

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HydrocarbonProcessing.com | NOVEMBER 2014

®

PETROCHEMICALSFCC can be used

to produce olefins and

aromatics on-purpose

MAINTENANCEProcess equipment may be

vulnerable to brittle fractures

REFINING DEVELOPMENTSUltra-fine solids need

aggressive treatment to protect

heat-transfer networks

SPECIAL REPORT:

Plant Safety and Environment

HARNESS THE POWER

RENTECH engineers build unmatched power and performance into every boiler we deliver. Our 80-acre manufacturing facility—the industry’s most

technologically advanced—includes heavy bay and light bay areas with direct access

to rail, cross-country trucking routes and shipping facilities. We master every detail to

deliver elemental power for clients worldwide. Take an expanded tour of our facilities

today at www.rentechboilers.com/facilities

HARNESS THE POWER WITH RENTECH.

OF MANUFACTURING INNOVATION

HEAT RECOVERY STEAM GENERATORS

WASTE HEAT BOILERS

FIRED PACKAGED WATERTUBE BOILERS

SPECIALTY BOILERS

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Select 52 at www.HydrocarbonProcessing.com/RS

NOVEMBER 2014 | Volume 93 Number 11HydrocarbonProcessing.com

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

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?

B. Macejko

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

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.

DEPARTMENTS 4 Industry Perspectives

10 News

19 Industry Metrics

91 Innovations

93 Events

94 Marketplace

96 Advertiser Index

98 People

COLUMNS

9 Editorial CommentWanted: Future leaders

21 ReliabilityCan integrally geared compressors be successfully used with variable speeds?

23 Automation StrategiesVirtualization in process automation systems

25 GlobalEuropean refining—Cornered, with no way out?

29 Automation SafetyIt is easier to sit on the couch than go exercise

31 Boxscore Construction AnalysisVietnam: Reversing the tide of refined imports

36

41

4�NOVEMBER 2014 | HydrocarbonProcessing.com

P. O. Box 2608

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Phone: +1 (713) 529-4301

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HPEditorial@HydrocarbonProcessing.comwww.HydrocarbonProcessing.com

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Vice President Ron Higgins

Vice President, Production Sheryl Stone

Editor-in-Chief Pramod Kulkarni

Business Finance Manager Pamela Harvey

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

Publication Agreement Number 40034765 Printed in USA

Industry PerspectivesPUBLISHER Bret Ronk

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Hydrocarbon Processing is indexed by Applied Science & Technology Index, by Chemical Abstracts and by Engineering Index Inc. Microfilm copies avail-able through University Microfilms, International, Ann Arbor, Mich. The full text of Hydrocarbon Processing is also available in electronic versions of the Business Periodicals Index.

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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.

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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 inter-nal reference use without express permission is prohibited. Requests for special permission or bulk orders should be addressed to the Editor. ISSN 0018-8190/01.

Cyber bullies continue to be a menace Cyber security is still a critical issue that the hydrocarbon pro-

cessing 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 Indus-trial Control System Cyber Emergency Response Team (ICS-CERT), US Department of Homeland Security, emphasized that cyber attacks are increasing and becoming more sophisti-cated. 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 outsid-ers probing for company information, including control systems.

While you were sleeping. Bristow stressed that such breach-es 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 at-tacks 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 in-fected 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.

FIG. 1. The HPI is still vulnerable to cyber attacks and must take precautions. Source: Hydrocarbon Processing, October 2013.

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HPI Market Data 2015 is the hydrocarbon processing industry’s most trusted forecast of capital, maintenance and operating expenditures for the petrochemical, refi ning 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 top-level insight into HPI market trends, spending and activity.

HPI Market Data 2015 features:• Global spending in the refi ning, 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 fi gures, 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

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• Discover how spending trends by sector will impact your company

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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 • Refi ning

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 refi neries 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 signifi cant expansions in the petrochemical sector will be in developing countries in Asia-Pacifi c, 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 refi neries 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]

Hydrocarbon Processing | NOVEMBER 2014�9

The hydrocarbon processing industry (HPI) has known for some time that a great shift change is eminent. The expe-rienced engineers, chemists and crafts hired in the 1970s and 1980s are reach-ing retirement age very soon, and they are ready to start their well-earned second chapters. Besides the loss of the experi-ence 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. Lead-ers can be developed within the organiza-tion. They do not need to have the high-est 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 achieve-ments over the long term.

Todd Monette, plant manager for Ly-ondellBasell’s facility in Houston, Texas, recently addressed the AFPM’s Q&A and Technology Forum in Denver, Colorado. Monette emphasized that HPI organiza-tions must create their own leadership within their facilities and they must be-gin now. The future leaders of the HPI are the new workers now entering the workforce. These young people have dif-ferent needs and expectations than the

seasoned veterans. Thus, new training/mentoring programs for young leaders must be developed.

All employees can contribute leader-ship 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.

Empowerment. As leaders, employees must be empowered to identify and re-port 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 meet-ings. However, it is more important that the staff believes that all members of the plant and company share, and work to-ward, the same goals daily.

An energized employee is more valu-able than any innovative device. Technol-ogy 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 main-tained.

INSIDE THIS ISSUE

36 Plant safety 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

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

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

for that purpose. However, the FCC

process can also be used to produce

petrochemicals. The authors discuss the

various FCC operational changes that

can enhance propylene yield.

Wanted: Future leaders

Maintenance, crafts and operators

Plantmanager

Process unit/shiftforeman

Craft foreman

Process/projectengineers

Superintendentoperations andmaintenance

Managers ofengineering

and technicalservice

FIG. 1. Leadership profile for HPI facility.

An expanded version of Editorial Comment can be found online at HydrocarbonProcessing.com.

| News

EPA: GHG emissions from refineries increase 1.6% in 2013The 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 corn-based 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 pro-duce 30 MMgpy of cellulosic ethanol, a process that DuPont claims has zero net carbon emissions.

The detergent, combined with cel-lulosic ethanol, will allow for the repur-posing 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 ap-prenticeship pilot program at various Dow sites across the nation in 2015. This pilot program supports a major initiative of the Advanced Manufacturing Partner-ship (AMP), an effort to secure US lead-ership in emerging technologies, create high-quality manufacturing jobs, and en-hance the US’ global competitiveness.

The launch advances the goals and national workforce development efforts of the AMP Steering Committee 2.0, a re-newed, cross-sector, public/private part-nership. 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 of-fering apprenticeship programs in Europe, Dow joined the coalition in committing to pilot key playbook concepts at company fa-cilities 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 busi-ness growth and advance skill develop-ment in manufacturing and engineering.

Dow’s US program will offer partici-pants 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 part-nerships between Dow and local commu-nity colleges, the program will combine classroom training and hands-on learning to build in-depth skills and experience. Upon completion of the program, appren-tices will be evaluated for employment op-portunities at Dow.

Dow says it will pilot its US Appren-ticeship Program at five of its manufac-turing sites in Texas (Freeport, Bayport, Deer Park, Seadrift and Texas City), as well as at its manufacturing sites in Cali-fornia; Pittsburgh, Pennsylvania; and Chicago, Illinois area. The company ex-pects to hire approximately 60 apprentic-es for the pilot program in 2015, training them for roles as chemical process op-erators, 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, an-nounced plans to expand their US opera-tions 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 challeng-es facing industry today is a shortage of candidates with the technical skills neces-sary 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 de-spite 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 pro-duction. Methanol plants and ammonia- or 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 In-formation 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 ser-vice, 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 facili-ties 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 fertil-izer 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 near-

News

12

ly 100 MMcfd of natural gas each, accord-ing to Bentek Energy estimates.

While most of the proposed methanol plants are on the Gulf Coast, two are pro-posed for 2018 in the Pacific Northwest. Northwest Innovation Works, a Chinese company, is planning two methanol facili-ties on the Columbia River in Washing-ton 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 Auto-mation (ISA) announced that ANSI/ISA-100.11a-2011, “Wireless Systems for Industrial Automation: Process Control and Related Applications,” has been unani-mously approved by the International Electrotechnical Commission (IEC) as an international standard and will be pub-

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 re-ported in 2012 and over 1 B hours of op-erational 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 stakehold-er groups, including end users in addition to suppliers—ensuring that all views and needs are taken into account. ISA100 vot-ing members, including those from end-user companies deploying wireless systems in real-world industrial applications, over-whelmingly voted to approve ISA-100.11a.

ISA-100.11a/IEC 62734 provides re-liable 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, gate-ways and security specifications for wire-less connectivity with devices supporting limited power consumption requirements. The focus is to address the performance needs of process manufacturing applica-tions, which include monitoring and pro-cess control where latencies on the order of 100 ms can be tolerated, with optional behavior for shorter latencies.

IEC 62734 utilizes Internet Proto-col version 6 (IPv6), adheres to the OSI model and uses object technology—all necessary to support the Industrial In-ternet 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-time-high fuel economy in 2013, according to data released from the US EPA. Model-year 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 diox-ide emissions are also at a record low of

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News

14

369 g/mi in model-year 2013. Some ad-ditional findings from the report:

• The recent fuel economy improve-ment is a result of automakers’ rapid adoption of more efficient tech-nologies, such as gasoline direct-injection engines, turbochargers and advanced transmissions

• Mazda vehicles averaged the highest fuel economy and lowest greenhouse gas (GHG) emissions

• 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 stan-dards projected to double fuel economy by 2025 and cut vehicle GHG emissions by half. The EPA estimates these standards

will save US families more than $8,000 in fuel costs per vehicle by 2025. The stan-dards are projected to reduce US oil con-sumption by more than 2 MMbpd by 2025.

The Major Economies Forum meets in New York

The Major Economies Forum on En-ergy and Climate met in New York City at the end of September. The meeting was chaired by US Deputy National Se-curity 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 En-hanced 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 read-out on the third Climate Finance Minis-terial meeting from Norwegian Minister of the Environment Kristine Sundtoft.

For the first time, the meeting includ-ed a foreign minister’s session, hosted by US Secretary of State John Kerry. For-eign ministers stressed the urgency of addressing climate change and noted the links between climate change and glob-al, national and energy security. They exchanged views on how best to build upon the momentum regarding climate change and how best to harness politi-cal will. They also stressed the need to approach the Paris agreement construc-tively 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 mitigat-ing 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 capac-ity, while others have reconfigured their fleets to make them more fuel efficient,

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News

16

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 air-line trade association identified other factors that contributed to these changes, such as a weak economy.

The GAO report cited aviation as-sociations and government officials that said fuel price increases have con-tributed 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

activity adversely affected general avia-tion 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 pric-es 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 macroeco-nomic variables, such as real gross domes-tic product (GDP), if fuel prices increased by 200% from 2010–2024 and the GAO provided these outputs to the US Fed-eral 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 indus-try is vital to the US economy. Passenger airlines directly generate billions of dol-lars in revenues each year, and communi-ties depend on passenger airlines to help connect them to the national transporta-tion system. Between 2002 and 2013, jet fuel prices more than quadrupled from $0.72/gal to $2.98/gal, and general avia-tion 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 car-go 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

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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 five-year period.

Some of this new power plant capacity is to meet the rising energy needs of the country. Some will replace existing coal-fired 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 Chi-nese 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 re-porting 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 im-ports. There are 20 large domestic produc-ers accounting for sales of just under $2 B.

Some of the JV international companies are exporting pumps from China. As a re-sult, the sales by this group are several bil-lion dollars per year.

The energy sector will contribute much of the growth in the coming years. China

has embarked on a huge coal-to-chemicals and fuels program. If all planned projects are completed, China would be convert-ing 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 coal-fired power plants at the rate of 50,000 MW/yr. Existing power plants are being retrofitted with NOx control. These retro-fits 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.

TABLE 1. China’s FGD, MW

Classifi cation 2014 2020

Existing FGD 659,971 896,555

FGD retirements –1,000 –1,000

New construction FGD 42,500 25,500

Retrofi ts 13,004 11,316

Total new FGD 55,504 36,816

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Industry Metrics

HP STAFF

[email protected]


Mid–October crude oil prices slumped as the International Energy Agen-cy (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.

Prod

uctio

n, Bc

fd

Gas p

rices

, $/M

cf

01020304050607080

01

2

3

4

5

6

7

Monthly price (Henry Hub)

12-month price avg.Production

AJJMAMFJDNOSAJJMAMFJDNOSA

Production equals US marketed production, wet gas. Source: EIA.2012 2013 2014

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

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

Oil p

rices

, $/b

bl

45

60

75

90

105

120

135

Dubai Fateh

W. Texas Inter.Brent Blend

AJJMAMFJDNOSAJJMAMFJDNOSA2013 20142012

Source: DOE

Selected world oil prices, $/bbl

Global refining margins, 2013–2014*

WTI, US Gulf Arab Heavy, US Gulf Brent, RotterdamDubai, Singapore LLS, US Gulf

-5

0

5

10

15

20

Marg

ins, U

S$/b

bl

Sept

13

Oct 1

3

Nov 1

3

Dec 1

3

Jan 1

4

Feb 1

4

Mar 1

4

April

14

May 1

4

June

14

July

14

Aug 1

4

Sept

14

Global refining utilization rates, 2013–2014*

50

60

70

80

90

100

Utiliz

ation

rate

s, %

USEU 16

JapanSingapore

Sept

13

Oct 1

3

Nov 1

3

Dec 1

3

Jan 1

4

Feb 1

4

Mar 1

4

April

14

May 1

4

June

14

July

14

Aug 1

4

Sept

14

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

-100

102030405060

Crac

king s

prea

d, US

$/bb

l Prem. gasoline unl. 93Jet/kero

Gasoil/diesel, 0.05% SFuel oil, 180c

Sept

13

Oct 1

3

Nov 1

3

Dec 1

3

Jan 1

4

Feb 1

4

Mar 1

4

April

14

May 1

4

June

14

July

14

Aug 1

4

Sept

14

Rotterdam cracking spread vs. Dubai, 2013–2014*

Prem. gasoline unl., 98Jet/kero

Gasoil, 10 ppm SFuel oil, 1% S

-20

-10

10

20

30

40

Crac

king s

prea

d, US

$/bb

l

0

Sept

13

Oct 1

3

Nov 1

3

Dec 1

3

Jan 1

4

Feb 1

4

Mar 1

4

April

14

May 1

4

June

14

July

14

Aug 1

4

Sept

14

Singapore cracking spread vs. Brent, 2013–2014*

-20

-10

0

10

20

30

Crac

king s

prea

d, US

$/bb

l

Prem. gasoline unl. 92Jet/kero

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

Sept

13

Oct 1

3

Nov 1

3

Dec 1

3

Jan 1

4

Feb 1

4

Mar 1

4

April

14

May 1

4

June

14

July

14

Aug 1

4

Sept

14

78808284868890929496

-1.5-1.0

-0.5

0.0

0.5

1.0

1.5

2.0Stock change and balanceWorld demandWorld supply

2015-Q12014-Q12013-Q12012-Q12011-Q12010-Q12009-Q1

Supp

ly an

d dem

and,

MMb

pd

Stock

chan

ge an

d bala

nce,

MMbp

d

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

Forecast

World liquid fuel supply and demand, MMbpd

* Material published permission of the OPEC Secretariat; copyright 2014; all rights reserved; OPEC Monthly Oil Market Report, October 2014.

Brent Dated vs. sour crudes

(Urals and Dubai) spread, 2013–2014*

Light

swee

t/med

ium so

urcru

de sp

read

, US$

/bbl Dubai

Urals

-4

-2

0

2

4

6

01 M

ay08

May

15 Ma

y22

May

29 M

ay05

June

12 Ju

ne19

June

26 Ju

ne03

July

10 Ju

ly17

July

24 Ju

ly31

July

07 Au

g14

Aug

21 Au

g28

Aug

04 Se

p11

Sept

18 Se

pt25

Sept

02 O

ct

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

© 2014 Baker Hughes Incorporated. All Rights Reserved. 41583 09/2014

DDoDoDoDDoD n’t mimiss the JJETETETETTITITITIT SOSOSOSOONNNN™ solidss rereremom vaavalllltechnology artrttrtr icicicclelee iinnn thththisis iissssssssue.

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process 30% PFT crude after a competitor could only help process this crude at less than 5%.



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-relat-ed questions. This same webinar also generated a few additional ones. A viewer thought that two statements from this presenta-tion were in contradiction, as proven by his correspondence.

Question 1. One slide from the webinar used the heading: “Sin-gle-shaft multi-impeller technology vs. integrally geared speed-optimized technology.” It was followed by a slide stating that in-tegrally 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 ar-rangement of integrally geared air and/or process gas compres-sors (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 typi-cally 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 de-sign, 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 pin-ions, 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 con-ventional 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 un-desirable 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 fre-quency, and these could be excited if VFDs were used.

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.

FIG. 1. Machining a semi-open 3D impeller. Source: Cameron Compression, Buffalo, New York.

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.

“Beneficial reuse” is defined by the EPA as reusing a material in a

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generally byproducts of a refinery or chemical process that would

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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

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caustic solutions.

Our beneficial reuse of caustic streams helps our customers achieve waste minimization goals and eliminates labor intensive waste handling protocols

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AutomationStrategies

HARRY FORBES

ARC Advisory Group, Burlington, Massachusetts

Virtualization in process automation systems

Virtualization involves separating an information technol-ogy (IT) resource from specific physical hardware. This is usually managed by a specialized software layer called a hyper-visor, which provides another abstraction layer. Virtualization can be applied to any IT resource, including servers, storage, desktops and networks. For example, server virtualization en-ables 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 solu-tions that use virtualization.

Benefits. Since virtualization can only be applied to some parts of process automation systems, it can be difficult to as-sign 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 sys-tem configurations that feature server consolidation. Multiple human machine interface (HMI) machines and other applica-tion 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 serv-ers 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 con-trol areas. Power requirements and system administration bur-den 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 automa-tion software from specific configurations of PC or server hardware. For years, many HMI and other automation sys-tem 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 prod-ucts. By virtualizing such a system, it can be more easily sup-ported once replacement hardware is no longer available. This higher degree of hardware independence helps extend auto-mation 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 pro-cess controllers or field devices) that are managed by a real-time 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 en-vironment. Most automation suppliers have developed prod-ucts 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 instal-lations, 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 re-quirements 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 re-quirements. 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.

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Global ALAN GELDER

Global Practice Lead for Refining & Marketing for Wood Mackenzie

European refining—Cornered, with no way out?

2013 was a dismal year for European refining in terms of re-cord low crude runs, which reflect weaked demand outlook and increasing competition from other regions. Out to 2020, we en-visage 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). Commer-cially, Europe is cornered by exports from these markets, with no apparent exit route.

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 advan-tage 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 re-finers 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 Rus-sia 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 die-sel/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

DemandCrude run

0

5,000

10,000

15,000

20,000

25,000

2000 2001

2002

2003

2004

2005

2006

2007

2008

2009

2010 2011

2012

2013

Dem

and a

nd cr

ude r

uns,

Mbpd

Source: Wood Mackenzie

FIG. 1. Historical greater European demand and crude runs.

-2

0

2

4

6

8

10

12

2009 2013 2018

Weig

hted

aver

age c

ash m

argin

, US $

/bbl

Coastal NWE comprises of refineries in Belgium, France, The Netherlands and the UKSource: Wood Mackenzie

USGCCoastal NWE

FIG. 2. USGC vs. NWE weighted average net cash margin (US$/bbl).

-1,000-750

-500

-250

0

250

500

750

1,000

2005 2010 2015 2020

Gaso

line a

nd di

esel

trade

balan

ce, M

bpd


Exports

ImportsGasolineDiesel/GO

FIG. 3. US gasoline and diesel trade balances.


Global

runs declining by a further 1 MMbpd (2014 to 2020). We fore-cast average refinery utilization to drop from 74% in 2013 to ap-proximately 65% in 2020. Given highly competitive assets typi-cally 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-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.

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 com-mercial performance.

-1,000-750

-500

-250

0

250

500

750

1,000

2005 2010 2015 2020

ME ga

solin

e and

dies

el tra

de ba

lance

, Mbp

d


Exports

ImportsGasolineDiesel/GO

FIG. 4. ME gasoline and diesel trade balances.

GREAT STANDARDS ARE REFINED HERE

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Washington, D.C. | Houston | Beijing | Singapore | Dubai | Rio de Janeiro877.562.5187 (Toll-free U.S. & Canada) | +1.202.682.8041 (Local & International) | [email protected] | www.api.org

Copyright 2014 – American Petroleum Institute, all rights reserved. API, the API logo, the “Onshore” slogan and the “Tough” slogan are either service marks, trademarks or registered trademarks of API in the United States and/or other countries.

It’s a tough business. Look to API. ®

Certifi cation | Training | Events | Standards | Statistics | Safety

SM

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.


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For more information about UOP modular solutions, visit www.uop.com/products/equipment/modular-units

to learn about all of the UOP modular solutions.© 2014 Honeywell International, Inc. All rights reserved.

From: Plant Manager

Sent: Tuesday, May 13, 2014

To: Process Engineer

Subject: Constant process trips

I know we’re wasting money on our process energy consumption,

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From: Process Engineer

Sent: Tuesday, May 13, 2014

To: Plant Manager

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Talked with CCC. 1 year payback with their

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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 watch-ing 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, includ-ing 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 mag-azine 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 commit-tee to provide a framework engineering process that allows engineers to design, innovate and optimize. In these stan-dards, companies may establish their own risk-reduction pro-cess 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 stan-dards, not prescriptions. What that means is simple: engi-neering 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 cur-tail learning. There is never a lack of new material to under-stand. 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 sim-ple electronic resistor? This has no chance of passing a rea-sonability 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 func-tional 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 dis-cipline 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.


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 petrochemi-cal sectors. At present, the country has only one operating refinery, located at Dung Quat. With oil consumption ris-ing steadily from 176 Mbpd in 2000 to nearly 400 Mbpd in 2012, the 146-Mbpd refinery is unable to satisfy do-mestic 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 large-scale refinery projects (TABLE 1). These projects have the potential to add 1.36 MMbpd of new domestic refining ca-pacity 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 vari-ables include the need to secure a mas-sive 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 govern-mental 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 PetroVi-etnam. 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 pro-cess 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 dis-tillation 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 refi nery expansion PetroVietnam 200 (expansion of 60) 2,000 2018

Nghi Son refi nery and petrochemical complex

Kuwait Petroleum, Idemitsu Kosan, PetroVietnam, Mitsui 200 9,000 2018

Vung Ro refi nery and petrochemical complex

Vung Ro Petroleum, Technostar Management 160 4,000 2018

Nhon Hoi refi nery and petrochemical complex

PTT, Saudi Aramco 400 20,000 2021

Nam Van Phong refi nery Vietnam National Petroleum Group, Daelim Industrial 200 8,000 N/A

Long Son refi nery and petrochemical complex

PetroVietnam 200 7,000–8,000 2021

TABLE 2. Process technology licensing awards for the Vung Ro refi nery and petrochemical project

Company Unit Process technology

UOP Multiple units Unionfi ning, Selectfi ning, Resid UOP FCC, Platforming, PENEX, Huels selective hydrogenation, UOP indirect alkylation, Sulfolan, Merox, Chlorsorb system

CB&I Lummus Ethylene recovery and olefi ns conversion units Ethylene and olefi ns conversion technologies

INEOS Polypropylene Innovene PP

Jacobs Engineering Sulfur recovery unit SUPERCLAUS, caustic scrubber, Shell’s sulfur degasifi cation


32

latest casualty was Japan’s largest refiner, JX Nippon, which announced in Novem-ber 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 be-gan 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 fund-ing 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 Ha-noi in Thanh Hoa province, the Nghi

Son refinery and petrochemical project will be Vietnam’s second domestic refin-ery. 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 pro-duce 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) facili-ties. Based on a detailed feasibility study conducted by ABB Lummus Global, to-tal 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 Geopro-duction. 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, Viet-nam will be able to satisfy 65% of domes-tic refined product demand by 2020.

Vung Ro. If completed, the Vung Ro re-finery will be Vietnam’s third domestic plant. The project is a $4-B oil refinery, petrochemical complex and seaport de-velopment in the Dong Hoa district of Phu Yen province. The Vung Ro refinery and petrochemical complex is being de-veloped 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 Stan-ley Commodities will be the main suppli-ers of crude oil to the refinery. The petro-chemical 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 equip-ment, technology, design and construc-tion 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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and control systems, as well as carry out basic engineering. Additional technolo-gy licensing contracts are shown in TABLE 2. Construction commenced in Septem-ber, with full construction operations set to begin in 1Q 2015. If completed, the plant is scheduled to begin commercial operations by 2018.

Nhon Hoi. Thailand’s state-owned en-ergy company, PTT, is developing the Nhon Hoi refinery and petrochemical complex with Saudi Aramco. Both com-panies 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 ca-pacity down to 400 Mbpd, decreasing the total capital cost to $20 B.

The project includes the construction of olefins and aromatics petrochemical

plants. These plants will be able to pro-duce 2.9 MMtpy of olefins and 2 MMt-py of aromatics. Although the refined products will be used to satisfy domestic demand for transportation fuels, the ma-jority of the petrochemical products will be exported. If greenlighted, the project is expected to be completed in 2021.

Khanh Hoa. The Nam Van Phong re-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 as-sessment soon followed, and an MOU for investment was signed by Korea’s Daelim Industrial Corp. and Vietnam National Petroleum Group, the local in-vestor in the project.

The project is still seeking capital in-vestment from foreign investors. How-ever, with the capital cost nearly dou-bling 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 south-ern 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 pet-rochemical plant will ultimately produce polyethylene, PP and vinyl chloride monomer for domestic sale.

A detailed feasibility study has been completed. At present, the project de-velopers are seeking financing, which should be secured by the end of 2014. If greenlighted, the project is scheduled to begin commercial operation in 2021.

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| Special Report

PLANT SAFETY AND ENVIRONMENTMaintaining 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 valu-able resources, an independent petroleum refiner began a two-year 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 sin-gle 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.

BACKSTORYIn 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 me-chanical 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 be-come very complex. All of these fired heater aspects must be managed effectively. Thus, there was a need to create clear lead-ership, 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. Hav-ing 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 im-proved and tailored specifically to heaters at each refinery. Final-ly, 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 per-sonnel in the specific operation of fired heaters. This curriculm was in addition to general fired heater training.

TRAINING PROGRAMThe goal is to train more than 900 operators at all six loca-

tions 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.



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 condi-tions 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 pre-test, 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

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 ques-tionnaire. One of the more important is, “What are the most sig-nificant items you learned during the training?” The most com-mon 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 appli-cable. 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 con-tinuous training on heater operation. It is very important for op-erators to know how heaters do what they do, why heaters are operated in a particular way and how they are monitored and ad-justed so they operate safely and correctly.

NOTABLE INSTANCESThere are some unique aspects of this training. The course

material focuses specifically on operators and maintenance per-sonnel and their responsibilities. The classes open with a mem-ber of the local senior management team emphasizing the impor-tance 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 pur-chased. These are used during the training for hands-on learn-ing. 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

FIG. 3. Operator field training.

FIG. 4. Plastic burner models. TABLE 1. Course section ratings for all 10 classes combined

Section 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 3.63FIG. 5. Burner parts used for training.

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40

if burners/heaters are not properly operated and maintained. Us-ing 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 tech-niques that they learned on their own. The simulator can be ac-cessed via the Internet. This allows newer operators to test their skills without worrying about being embarrassed if they make

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 hu-midity, 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 train-ing. 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.

RECOMMENDATIONSCustomized training for plant operators across a company can

effectively help improve operations, standardize procedures and enhance organizational performance. It also helps share best prac-tices 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 environ-mental concerns) helps determine training objectives. Collabora-tion 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 1 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 train-ing 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.

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.

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.

FIG. 6. Screen shot of the electronic heater simulator training tool.

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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 gen-erate 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 Protec-tion Agency (EPA) has increased compliance enforcement, en-acting 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 envi-ronment, 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 them-selves: “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 po-tential to drive capital expense on pollution controls and com-pliance management at the local, state and federal levels (FIG. 1). It is logical, therefore, for hydrocarbon processors to assume that environmental compliance activities (compliance moni-toring and record-keeping, emissions testing, etc.) are a very expensive proposition when scaled to a multi-asset operation.

Data collected about industry sentiment toward environ-mental 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 com-panies citing them as leading risks.

In responding to the cost analyses, many hydrocarbon pro-cessors have adopted outsized asset and risk-management pro-grams, or implemented premature or ineffective emission-re-duction systems, to use as methods of ensuring environmental compliance. Costs associated with a highly integrated compli-ance 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 num-ber of assets and emissions sources that an operator manages in any given year, the cost of maintaining this system can be astro-nomical. The expenditure does not always result in a particu-larly 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 de-viations lower than expected.

Cost of noncompliance. The costs associated with the “wait-and-see” compliance model (which is not uncommon through-out 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 indus-try 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 environmen-tal program obligations with community support, thus caus-ing 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.

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(GHGRP); Mercury and Air Toxics standards (MATs); Main-tenance, 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 emis-sions, 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 dramati-cally 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 organi-zations. According to the EPA’s Fiscal Year (FY) 2009 Final Re-port, 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 mon-umental. Using a conservative estimate, if 1% of companies men-tioned in the EPA’s FY 2009 Final Report are hydrocarbon pro-cessors, 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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One of the more common mistakes encountered by envi-ronmental professionals is processors relying entirely on en-vironmental 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. Environmen-tal compliance requires careful planning to collect informa-tion 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 or-ganizations, 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 priori-tizes 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 op-erational 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, es-pecially where program performance goals are high.

Be proactive. It is understandable that some owners/opera-tors wait until the last minute to conduct environment-related activities, including environmental permitting, remediation or negotiations with regulators. However, by waiting, these own-ers/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

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 get-ting 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 ref-erences, 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 pro-gram plans outline the entire compliance structure of an or-ganization. These plans name the environmental compliance team, outline compliance requirements, describe commit-ments, develop mitigation plans, create staff training plans and list environmental permits.

In addition, these plans demonstrate an organization’s com-mitment to compliance and to integrating verification proce-dures 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 ap-plicable regulatory program obligations. Owners/operators should not try to save resources in this step, as it will prove det-rimental in the long run.

Do not treat environmental activities as commodities. In recent years, some hydrocarbon processors have treated en-vironmental activities—from audits, investigations and nego-tiations—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 com-pared to site-specific investigations.

The biggest challenge with this method is that non-specific site investigations often do not incorporate the complex regu-latory environment that varies by region, city and county. Fur-thermore, these investigations do not take into account an op-eration’s unique objective. An incomplete, inaccurate or even overly comprehensive assessment can cause delays and add unexpected costs to a project.

FIG. 3. Do not wait until the last minute to conduct environmental activities, including remediation, permitting and negotiations.



Openly communicate. Generally speaking, owners/opera-tors who meet with regulators have a higher probability of posi-tive outcomes than those who do not, so it is highly encouraged that owners/operators, environmental consultants, and the ap-plicable 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 com-pliance process. This will help prevent misunderstandings in compliance communication, and it may help explain how mis-takes occurred in the first place.

Follow through, but be flexible. An effective environ-mental compliance plan is a living, breathing document. To be effective, it must become an integral part of an organiza-tion. Too often, these documents lay dormant until a regulator shows up for an audit, or until a violation occurs. Through ac-tive 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 imple-mented and verified corrective actions, as outlined in the com-pliance plan. Those who do not follow through with these ac-tions 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 competi-tive, 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 pres-ent. Comprehending the regulatory environment, understand-ing 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.

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.

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Consider true zero-emission packing for reciprocating compressors

Reciprocating compressors are es-sential machines in refineries. Especially when handling hydrogen, reciprocating compressors must provide ruggedness, operating flexibility and energy effi-ciency 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 compres-sor 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. Like-wise, the environmental and regulatory consequences of leaks—in terms of both greenhouse gases (GHGs) and toxic sub-stances—are also significant.

In particular, leakage rates can be-come unacceptable as the sealing rings approach the end of their service life. An-other 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 devel-oped 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 hydrody-namics has yielded an arrangement in

which the motion of the rod “pumps” oil back into the packing against the prevail-ing pressure gradient. Oil loss, in fact, is lower than with a conventional lubri-cated packing.

The design avoids the need for a sepa-rate packing cooling system, and con-tinuously monitors oil pressure and con-sumption. 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, low-speed 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 pipe-line, makes economic sense, especially in remote locations with no power grid.

In refineries, reciprocating compres-sors often handle hydrogen-rich gas mixtures for hydroprocessing and hy-drotreating operations, where their reli-ability and high-pressure performance are valued. Many of these machines have seen decades of service in a variety of ap-plications. Reciprocating compressors are inherently versatile, and they can gen-erally be adapted to handle new through-puts and pressures, different gases, and lubricated or oil-free operations.

Although reciprocating compressors have used the same underlying prin-ciples 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 predeces-sors, over a wide range of temperatures, pressures, moisture levels and gas char-acteristics. Modern sensors, actuators and electronic systems allow reciprocat-ing compressors to be controlled effi-ciently, and monitored continuously for best reliability.

Gas leaks. Any double-acting compres-sor cylinder requires a seal around the piston rod. Modern sealing rings and rod packings made from various combina-tions of PTFE, bronze, graphite and oth-er materials offer excellent performance. However, over the long term, there is al-ways 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 mak-ing the process more complex, however, the use of nitrogen adds cost, especially if purged-distance pieces are also required.

In sensitive applications, other tech-niques may reduce both leakage and gas


48

costs, but with the penalty of added capi-tal costs and complexity. An example is a pneumatically operated static seal used to prevent leakage when the compres-sor is at a standstill but is required to re-main pressurized. Elaborate gas recovery equipment also falls into this class.

Older compressors of the single-compartment type (API 618, 6.12.1.3 type B) have a direct-gas leakage path between cylinder and crankcase, allow-ing leaked gas to dissolve in the crank-case oil. This lowers the flashpoint of the oil and increases the fire hazard in the

event of an accident. Pressurized crank-cases 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 con-cern. Even the smell of gas may be un-desirable in some applications, such as compressed natural gas fueling stations.

Oil consumption. Conventional lubri-cated 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 rod-sealing 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-

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 oil-seal rings operate virtually without wear.

Even when the compressor shuts down, the oil volume maintains an ef-fective static seal. As a result, a com-pressor that must remain pressurized during shutdown needs no additional arrangements to ensure effective static sealing. The complete packing contains several other elements that together en-able a conventional pressure packing (FIG. 2). As well as oil-seal rings (3a, b and c), there are two or three conven-tional 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-

FIG. 1. The new packing design relies on a pressurized volume of oil held between two sealing rings.

FIG. 2. Section through a practical zero-emission packing. The cylinder is to the left and the crankcase to the right.

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what. Because the rings are single-acting, the pressure immediately falls again dur-ing the suction stroke.

In practice, the rings need only mod-est 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 cyl-inder 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 recov-ered via a drain line. The specific wiper arrangement depends on the compres-sor configuration, such as whether a dis-tance piece is used.

Understanding oil-film dynamics. The idea of using oil as an infinitely flexi-ble 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 corre-sponding 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 mo-tion 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 conven-tional 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 differen-tial 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.

Forces. All fluid flow is governed by the balance between inertia, pressure forces and viscous forces (the Navier-Stokes equation). For viscous oil flowing through a narrow gap, inertia can be ne-

glected. Thus, the problem reduces to a linear balance between pressure and vis-cous forces (Reynolds equation).

As shown in FIG. 3, oil flow can be treated as a combination of three fun-damental 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 con-tinuity 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 veloc-ity, U, pulls a lubricant into a stationary, wedge-shaped space (FIG. 4). Continu-ity dictates that the mean flow velocity, umean , increases in the x-direction. Accom-panying this increase is a buildup of hy-drodynamic pressure, p(x). Upstream of

FIG. 3. Fundamental lubrication flow cases: a) Couette shear flow, b) pressure-driven Poiseuille flow, and c) squeezing flow.

FIG. 4. Hydrodynamic pressure, p(x) (above), increases as the surface moving at velocity, U, pulls oil into a convergent gap (top).

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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 prevail-ing 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 con-stant 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 bar-rier pressure (at x = 0) to a peak at lo-cation x = x*

out. This pressure increase arises from the existence of a convergent gap, which, in turn, is created by the hy-drodynamic pressure buildup—both ef-fects 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 pres-sure and cavitation sets in. At x*

out, the ve-locity profile is of the Couette type, so the volumetric leakage rate per unit circum-ference during the out-stroke is given by

(U/2) h*out, where h*

out is the film thick-ness 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 pres-sure is of the same order of magnitude as during the out-stroke, and the film thick-ness, 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 in-stroke. 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 require-ments 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 char-acteristics. A comprehensive simulation model was developed to determine the effects of ring geometry and operating conditions on the behavior of the lubri-cation film.

The model’s predictions were then checked and refined using a purpose-built 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).


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After thousands of hours of tests, in the field as well as in-house, the result is a ro-bust seal profile that combines reliability with low oil loss.

With the components of the packing box defined, the next step was to en-sure a reliable supply of pressurized oil. This task involved a specially designed hydraulic unit that circulates oil at a de-fined 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 hydrau-lic unit should increase the oil pressure when the compressor stops.

In applications where the compressor must remain pressurized during stand-still periods, leaking discharge valves can allow the cylinder pressure—and even-tually the buffer pressure—to rise until it

reaches the full-discharge pressure. Un-der these conditions, raising the oil pres-sure 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 auto-matically 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 en-tirely 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 pres-sure, and the downstream oil seal ring (FIG. 2, 3c) works as a vent seal. For ap-plications where a purge system would

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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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 gath-ering and treatment plant in The Nether-lands, at a natural gas/biogas compres-sor station fueling a fleet of city buses in

Sweden, and on a propane refrigeration compressor in Egypt.

The demonstration units have record-ed over 30,000 hours of successful opera-tion (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 hun-dred 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 develop-ment 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 new system of sealing piston rods can of-fer 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 pack-ing 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. Lindner-Silwester 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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FIG. 7. Zero-leakage sealing system installed on a compressor.

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Special Report Plant Safety and Environment 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 exam-ined 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 ole-fins 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 compa-rable numbers of fatal and non-fatal injuries. The dense smoke shown in FIG. 1 is due to non-premixed combustion. The appro-priate probit equation1 could be applied to quantitatively exam-ine 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 hy-drocarbons 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 hydrocar-bons were released at Geismar and that 75% of the weight was ac-counted for by propylene, with smaller amounts of other hydro-carbons, 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 en-ergy released at Geismar can be calculated by Eq. 1:

14 × 103 kg × 49 MJ kg–1 = 690 MJ (1)

Approximately 5% of this heat will be blast energy,1 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 explo-sion at an LNG plant in Algeria in 2004.1 If steam was the lethal

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 tempera-ture 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 tempera-ture 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 en-thalpy 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 en-ergy, 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)

FIG. 1. The vapor cloud explosion at the Geismar olefins plant in 2013. Source: Reuters.



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 ac-cidental 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,

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 re-finery. 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 prin-ciples 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 stan-dards in the US oil industry.1

FIG. 2. The ruptured heat exchanger at the Anacortes refinery. Source: Chemical Safety Board.

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Moderator: BEN DUBOSEOnline EditorHydrocarbon Processing

57


Wider issues. Whenever an accident occurs like those dis-cussed herein, especially where loss of life results, certain ques-tions 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 mis-hap, 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 re-cords 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 fre-quency 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 in-volve 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 re-ferred to in the previous section. Here, conformity or other-wise 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 moni-tored. More knowledge and insight, drawing on recorded ex-perience, 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, oversimpli-fied questions, such as whether training is adequate, or if su-pervision 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. Further-more, those involved in making process safety decisions can reference the analyses contained in Hydrocarbon Process Safety when confronted with questions from junior personnel.

LITERATURE CITEDComplete 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 chemi-cal and petrochemical projects. The wide range of properties and regulatory con-straints 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 ware-house design has been developed, with the aim of identifying hazards, consider-ing regulatory requirements, assessing risks, addressing adequate design criteria and implementing all necessary mitiga-tion 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 vari-ous 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 Or-ganization, 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 re-ported. On January 4, 1977, in Renfrew, Scotland, the Braehead Container Clear-ance Depot chemical warehouse was de-stroyed 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 con-tainers, 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 igni-tion was the electrical system of a battery-operated forklift truck.

On December 14, 1984, a fire broke out in a very large furniture repository in Sheffield,5 which also contained hazard-ous chemicals that, fortunately, were not involved in the fire.

On November 1, 1986, a fire devel-oped 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-fight-ing, 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 explo-sions leading to an intense fire broke out in a storeroom in the raw materials ware-house 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 distri-bution facility owned by West Fertilizer caused 15 fatalities and hundreds of inju-ries 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 combus-tible seeds, which likely contributed to the intensity of the fire. The building lacked a sprinkler system or other systems to auto-matically detect or suppress fire.

US federal codes covering fire and safe-ty, such as OSHA’s Process Safety Man-agement standard (29 CFR, 1910.119) and the Environmental Protection Agen-cy’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 Vi-nyl Co. warehouse, which caused one fa-tality and injured five. According to police hazmat crews, a storage container in the building that held 20,000 gal of liquid in-explicably exploded. The storage contain-er 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 conclu-sion 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 com-mon 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



• 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 indi-rectly related to inadequate design. Accord-ingly, the safe design of a hazardous chemi-cal 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 hazard-detection 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

an additional spectrum of issues in the design.

These and many other reasons make the safe design of a hazardous chemical ware-house both challenging and demanding.

Methodology of a safe design. The methodology for a warehouse safe design has been summarized in FIG. 1. Rhombus-shaped boxes identify safety design phas-es, the rectangular boxes indicate design input/output, and the round boxes repre-sent the regulations, standards and com-pany work practices adopted in the design.

Hazmat table and process data col-lection. 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 nomencla-ture, reference will be made to validated sources, such as the European Regulation for Classification, Labeling and Packag-ing; the European Chemicals Agency; the classification and labeling database provided by the National Institute for Oc-cupational Safety and Health; the Pocket Guide to Chemical Hazards; and data from the Occupational Safety and Health Administration, the Occupational Chem-ical 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 require-ment, the design team may need to adopt particular standards and local regulations, or it can be free to select the most appro-priate 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 ref-erences, other international standards and validated sources can be adopted, such as NFPA 704 and NFPA 400.9 Proprietary material safety data sheets are not gener-ally 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 hazard-ous characteristics of the substances, with specific reference to their reactive poten-

Hazardous material table Process data

Chemical identification

Chemicalproperties and codes

identification

ChemicalHAZID/ENVID

Warehouse hazardclassificationand design

Maximum inventory

Compartmentalizationsegregation philosophy

Hazard analysis/classification input/outputStandard/regulation requirementDesign

Emergencyalarm measures

Escape andevacuation

Drainagestrategy

Fire rating Fire philosophy EmergencyHAVAC system

WH HSEdesign requirements

Regulation Literature

Literature

Companywork practice

Companywork practice

HAVAC/electrical data

Civil/structural data

Process data

Regulation

Standards

Standards

Regulation

Regulation

Standards

Standards

FIG. 1. Warehouse safe design flow chart.

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tial, as addressed by the relevant work prac-tice. Identification and classification rela-tive 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 interac-tions of chemical substances within the specific warehouse with respect to all site entities and constraints, such as other chemicals, adjacent buildings and equip-ment, environmental targets and the lo-cal community.

A typical categorization relative to the reactive hazard, according to the com-pany work practice, has been given in FIG. 3. Here, the NFPA 704 codes have been further investigated by means of a

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 Pro-tection 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 require-ments. The identification of the health, safety and environment (HSE) design re-quirements is the key phase of the design and the starting point of the multi-disci-plinary design approach. This approach typically involves process, civil, electrical, machinery, and health and safety-inte-grated competences.

On the basis of the design data, the haz-ard identification and classification, and

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 liq-uid or powder chemicals be present in the normal operation of the warehouse, de-pending on the standard, hazardous area classification will be performed in the AT-mosphères EXplosibles (ATEX) frame, or according to the American approach. Ac-cordingly, IEC-EN-60079-10-1/2, IP 15 or NFPA 497 can be adopted. Other im-portant codes are GOST-R and GOST-K.

On the basis of the hazard and regula-tion assessment, the following safety de-sign requirements will result:

• The maximum allowable inventory of chemical products, depending on their toxicity, flammability, combus-tibility and chemical reactivity

• Rules for the proper location of incompatible substances, or sub-stances 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 chemi-cal compatibility, heat generation, water reactivity, gas formation and any other potential issues

• Heating, ventilation and air condi-tioning, or mechanical or natural ventilation systems, which will need to account for any potential hazard-ous 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-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.

Intentionalchemistry?

Start

Design input

Anysubstances

mixing?

Any otherphysical

processing?

Storage handleof any potentially

reactivesubstrates?

Stop reactivityhazards unlikely

Any heatgenerated?

Peroxidesforming?

Waterreactive?

Anyoxidizer?

Any self-reactive?

Anyspontaneously

ignitable?

Incompatiblematerials

coming intocontact?No

No

No

No No No

MSDS

Lesson learned C. history Regulation

NFPA CLP NIOSH NPG

No No No NoYes

Yes

Yes Hazard Identification process

Yes Yes Yes Yes Yes Yes Yes

Reactive hazardsexpected

FIG. 2. Reactive hazard screening.

FIG. 3. Reactive hazard classification.

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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 re-spect 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

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 analy-sis 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.

TABLE 1. Design summary table for a typical solids and liquids warehouse

Chemical identifi cation Chemical properties HAZID/ENVID HSE design requirements

Multidisciplinary design activity

Project documents

• Physical properties of chemicals

• Process data

• Basic identifi cation • Warehouse plot plans• Warehouse storage rack views• Drum fi lling sketches

• Warehouse plot plans• Warehouse storage rack views• Drum fi lling sketches

• Hazardous area classifi cation summary

• Hazardous area classifi cation drawings

• Sprinkler system design

• Safe layout and spacing

• Architectural design

• Required egresses• No corridor dead

ends• Maximum travel

distances to exits• NFPA rack

maximum heights• Fire department

access door• Non-combustible

doors, sills, dikes, sumps

• Exterior walls• Distance to

property line• Mechanical

ventilation • Drain system• Separate sewer• Secondary

containment• Electrical• Outside manual

shutoff system

Regulations • CLP • CAS number

• CLP • Classifi cation, risk

phrases

• CLP• Water reactivity• Gas formation• Toxicity• Heat generation• Chemical incompatibility

Standards • NIOSH • F.P., B.P., IDLH

• International building code• Use and occupancy

classifi cation of fi lling center, packaging center, storage center, control room, mechanical room, battery room, MCC switchboard

• International building code• Fire barrier requirements

• ACGIH• TLV-TWA, TLV-STEL

• International fi re code• Sprinkler requirements

• NFPA 30 fl ammability/combustibility

• NFPA 400 hazard level • NFPA 1 protection levels

• NFPA 13 sprinkler system design

• NFPA 30 control area MAQ, drainage system requirements

• NFPA 400 hazmat code, MAQ exceedance, protection levels

• NFPA 5000 spill control

• NFPA 13 classifi cation of solids

• NFPA 497 fi lling station hazardous area classifi cation

• NEC 70/IEC 60079 equipment to be used in hazardous areas

Company work practice

• CLP (company chemicals classifi cation reference)

Literature • Bretherick• Yaws • CCPS

• Reactivity data • Physical chemical data• Overview information

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Maintenance and Reliability

B. MACEJKO, The Equity Engineering Group, Inc.,

Shaker Heights, Ohio

Is your plant vulnerable to a brittle fracture?

Much of the process equipment operating today was de-signed to construction codes that did not require a formal evaluation for low-temperature considerations. Metal tem-perature highly influences the fracture toughness of construc-tion materials of plant equipment. At low temperatures, some materials tend to behave in a brittle manner, making it much more susceptible to fracture. The author discusses methods to identify potential brittle-fracture conditions in process equip-ment before failures occur.

BACKGROUNDThe majority of pressure equipment used in the refining and

petrochemical industry is constructed of carbon or low-alloy steel. Metal temperature highly influences the fracture tough-ness of these materials. At low temperatures, construction ma-terials can behave in a brittle manner (i.e., like glass), making them more susceptible to fracture. At high temperatures, the materials tend to behave in a ductile fashion. Pressure vessels and piping may experience low temperatures from the ambient environment or from operating and upset conditions.

The potential for auto-refrigeration from depressuriza-tion of liquefied compressed gases can be particularly con-cerning due to the extremely low equipment metal tem-peratures (–55°F and below). An engineering evaluation is typically required to assess whether low-temperature operat-ing or upset conditions could result in a brittle-fracture fail-ure of pressure equipment.

Brittle fracture. This is the sudden and rapid propaga-tion of a crack-like flaw under stress (residual or applied) where the material exhibits little or no evidence of ductility or plastic deformation.1 Although rare, the consequences of a brittle fracture are typically catastrophic. Brittle-fracture failures experienced within industry have resulted in costly unplanned repairs, extensive production downtime and loss of life (FIG. 1).

There can be a large variation in the way owner-users as-sess the risk for brittle fracture. Owner-users that have pre-viously experienced such a failure may have detailed and comprehensive programs in place to evaluate susceptibility to future issues. Alternatively, owner-users fortunate enough to have avoided such a failures tend to be less cognizant of potential risks. Just because a failure has not occurred yet, it does not mean it will not happen tomorrow.

WHY EVALUATE BRITTLE FRACTUREMuch of the plant equipment operating today was designed

to codes of construction that did not require a formal evalua-tion for low-temperature considerations. However, catastrophic failures and subsequent root-cause investigations have revealed deficiencies in code requirements. Present process equipment design and post-construction codes and standards have taken action to address the industry need to assess for brittle fracture.

OSHA 1910.119 process safety management requirements do not allow owner-users to ignore deficiencies in the original code of construction:2

• 1910.119(d)(3)(ii)—The employer shall document that equipment complies with recognized and generally accepted good engineering practices.2

• 1910.119(d)(3)(iii)—For existing equipment designed and constructed in accordance with codes, standards or practices that are no longer in general use, the employer shall determine and document that the equipment is designed, maintained, inspected, tested, and operating in a safe manner.2

Owner-users should consider a brittle fracture evaluation for any pressure-retaining equipment item where:

• Original design did not consider susceptibility to brittle fracture

• A change in process operating conditions increases the possibility that low-metal temperatures has occurred

• A PHA or HAZOP identifies process or ambient temperatures lower than anticipated in the original design, i.e., depressurization/auto-refrigeration potential

• The owner-user desires to rerate using a lower design margin

• The owner-user desires to optimize the timing of startups or shutdowns

FIG. 1. Ductile vs. brittle fracture failures.a



• The owner-user intends to complete a hydrostatic pressure test at a temperature lower than the original test temperature.

KEY COMPONENTSThere are three key components that drive a brittle-frac-

ture failure:• Stress (residual and/or applied)• Material toughness• Crack-like defect/flaws.A combination of metallurgical structure, residual stress

and inherent defects that act as stress intensifiers (lack of fu-sion, lack of penetration, porosity, and slag inclusions make welds and weld-heat-affected zones critical locations for po-tential brittle fracture.

Stress. Stress provides the energy necessary to drive a defect to fracture. Typical stress sources include pressure, weight and thermal loads, in addition to residual stress from the welding processes. A post-weld-heat treatment (PWHT) operation will significantly reduce weld-residual stress.

Material toughness. Metal temperature greatly influences material toughness in carbon steel (CS) and low-alloy steels. At low temperatures, the construction materials can behave in a brittle manner, and they have a high susceptibility to frac-ture. Conversely, the materials act in a ductile fashion at high temperatures. The fracture-appearance-transition temperature (FATT) is defined as the temperature corresponding to 50% shear. In FIG. 2, the FATT may be approximated as point D in the plot of Charpy impact energy as a function of temperature. Additionally, the material chemistry, grain size and heat treat-ment all affect toughness. The brittle-to-ductile-transition temperature will decrease (i.e., improve) with:

• Decrease in material carbon content• Increase in manganese to carbon ratio• Decrease in sulfur content• Decrease in material grain size• Normalization heat treatment of material through

rapid cooling.Partly due to chemistry control issues, older (or dirty) steels

often have a moderate brittle-to-ductile-transition slope rela-tive to clean steels (FIG. 3). Most of the common steels used to construct pressure equipment in the 1970s, 1960s and earlier (such as A70, SA-212, SA-201, SA-283, SA-285 and SA-515-70) have exhibited relatively high FATT (i.e., low toughness). A number of environmental issues exist that can degrade mate-rial toughness or result in embrittlement. The adverse effects of any such potential damage mechanisms should be consid-ered in a brittle-fracture evaluation.

Crack-like defect. Brittle fracture typically initiates at a crack-like defect. These defects can result from environmental damage (such as exposure to wet hydrogen sulfide or caustic), mechanical damage (such as gouges or dents), or from original fabrication (such as laminations, lack of fusion, lack of penetration, slag inclu-sions, and porosity). Performing a detailed inspection including both surface examination techniques (dye penetrant or magnetic particle examinations) and volumetric examination techniques (angled-beam ultrasonic methods) can be used to detect and cat-egorize any crack-like defects present in pressure equipment.

ASSESSING SUSCEPTIBILITY TO BRITTLE FRACTURE IN PRESSURE VESSELS

Industry codes and standards assess susceptibility to brittle fracture by comparing a critical exposure temperature (CET) to a minimum allowable temperature (MAT). The CET rep-resents the driving force for fracture and consists of the low-est-potential metal temperature from all operating, upset or atmospheric conditions. The MAT represents the material resistance to fracture, either calculated through engineering evaluation techniques or assigned based on destructive testing (i.e., Charpy impact testing). Both the CET and the MAT can consist of a single temperature and coincident pressure or an envelope of temperature and pressure combinations.

ASME Section VIII Division 1. Most pressure vessels at petro-chemical facilities were designed to ASME Section VIII Division 1 (ASME S8D1).3 The 1987 Addenda to the 1986 Edition in-troduced drastic changes to Part UCS-66 due to brittle fracture concerns with CS and low-alloy steels. Prior to this, ASME S8D1

Char

py im

pact

ener

gy

Lower shelf

Lower shelf

Upper shelf

Upper shelfNew steel

Old steel

Temperature

FIG. 3. Brittle-to-ductile transition for “old” steels.

Ductile

Brittle

Lower shelf:A - B

Temperature

Char

py im

pact

ener

gy

B/C

B

B

C C

D

A

Upper shelf:A + B

Transition zone

FIG. 2. Plot of Charpy impact energy FATT.

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permitted operation of CS equipment to a temperature of –20°F without testing. Considering that no new refinery has been built in the US since the 1970s, the majority of pressure equipment operating today did not receive a formal assessment for suscepti-bility to brittle fracture. Currently, ASME S8D1 provides a series of impact-test exemption curves to assign a baseline MAT based on the material of construction and weld-joint governing thick-ness. ASME S8D1 also permits application of a temperature re-duction if the stress levels are below the design allowable stress.

API 579-1/ASME FFS-1 Fitness-For-Service. The API 579-1/ASME FFS-1 (API-579) Fitness-For-Service (FFS) standard provides procedures and criteria to evaluate equipment in post-construction service.4 The Part 3 Level 1 and Level 2 methods used to screen for the propensity for brittle fracture are consistent with the ASME S8D1 design philosophy. The Level 3 method (which references Part 9 of API-579) includes a detailed fracture mechanics evaluation. Characteristics of the three levels include:

Level 1:• Typically completed by an inspector or a plant engineer• Table or chart exemption curve lookup based on material

of construction and joint governing thickness.Level 2:• Typically completed by a plant engineer• Screening method extension of the Level 1 approach

with more detailed and prescriptive calculations• Three analysis method options are provided and

described here. However, typically, Method A is the only practical and reasonable option:o Method A. Calculation of a safe envelope based on

an evaluation of actual stress compared to design allowable stress (i.e., trade lower stress levels for lower permissible temperatures).

o Method B. Determine the MAT based on the metal temperature at time of hydrotest. This method is not practical or feasible for many instances. Substantial risks exist for fracture during the hydrotest.

o Method C. Grandfathering approach based on a proof-test argument. This method assumes that if it can be shown that the combination of worst-case applied stress, temperature and flaw size has already occurred and did not result in a failure, then other less-severe conditions will not result in a failure. This method requires detailed historical operating, inspection and repair information that is not available in many instances.

Level 3:• Completed by an engineering specialist with extensive

experience in FFS.• Most reliable and accurate method for establishing

a MAT because it involves a detailed fracture mechanics evaluation

• Required when the equipment operates in a service where brittle fracture is a legitimate concern or if a crack-like flaw is known to exist

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If the equipment has undergone PWHT at original construc-tion and all subsequent repairs or alterations have not adversely compromised the effectiveness of the PWHT, then the FFS anal-

ysis calculation procedures allow credit for the positive benefit from the stress-relief operation on the calculated MAT. PWHT is often critical for low temperature (below –55°F) acceptability.

CURRENT CODES AND STANDARDS DEFICIENCIES

A number of deficiencies and inconsistencies exist with the ASME S8D1 and API-579 Level 2 FFS methods. All of these items enforce the requirement to complete a Level 3 Part 9 fracture me-chanics evaluation if brittle fracture is a legitimate concern.

Applied stress threshold and impact testing of weld-ments. Both ASME S8D1 and the Part 3 Level 2 procedure in API-579 assign a MAT of –155°F to a component if the calcu-lated stress ratio falls below a certain threshold (that depends upon the original code of construction factor for safety). How-ever, Part UCS-67(c)(3) of ASME S8D1 requires mandatory impact testing of welds to qualify metal temperature below –55°F. This weldment impact test requirement applies regard-less of the stress ratio. It could be argued that the API-579 Level 2 procedure should also require the weldment impact test.

Additionally, API-579 implies that, for a component thick-ness less than 2 in. and a general primary membrane tensile stress less than 8 ksi, brittle fracture will not occur. Although this may be true for equipment that has had PWHT performed, failures of non-PWHT weld joints due to weld-residual stress alone have occurred. Therefore, the 8-ksi primary stress thresh-old may not be appropriate in all instances.

PWHT temperature credit. For P-1 Group 1 and P-1 Group 2 materials, both ASME S8D1 and API-579 (Level 1 or 2) al-low a temperature reduction of 30°F from the component MAT if PWHT was completed and the component thickness does

not exceed 1.5 in. The origin and engineering justification for the 30°F reduction are unknown. As noted in WRC 528, esti-mates of the weld-residual stress were directly considered in

the ASME Section VIII Division 2 (ASME S8D2) ex-emption curves development.5, 6 Thus ASME S8D2 provides different exemption curves for PWHT and non-PWHT materials. The ASME S8D2 approach appears more technically appropriate when com-pared to the general 30°F reduction.

NBIC alternative weld methods. The National Board Inspection Code (NBIC) provides a series of alternative welding methods without PWHT.7 These include various combinations of preheat tem-

peratures, weld-interpass temperatures and temper-bead pro-cedures. Although these welding methods may help to slightly temper the material, they do not significantly reduce weld-re-sidual stress when compared to a proper PWHT stress-relief operation. Therefore, without further study, it is difficult to jus-tify credit for a full PWHT in a brittle-fracture evaluation if one of these alternative welding methods were used.

CASE STUDY 1This example illustrates the use of the Level 2 FFS method-

ology for brittle-fracture screening of typical “pots and pans” pressure vessels that meet these limitations:

• Do not operate in cyclic service• Not susceptible to any shock-chilling event• Not susceptible to any environmental cracking• Do not operate in a service that may result in loss

of material toughness• Have no known crack-like flaws• Where excessive low-temperature operation

(below –55°F) is not feasible.In this case history, a service review identified that the

knockout (KO) drum has the potential under ambient condi-tions to reach a minimum metal temperature of –10°F. Because the Level 1 analysis for the vessel indicated a baseline MAT of 53°F, a Level 2 FFS evaluation was completed. TABLE 1 summa-rizes the construction criteria for this KO drum.

Analysis. Level 2 FFS calculations were performed in accor-dance with Part 3, Method A of API-579 using proprietary soft-ware. The Level 1 MAT for each component was obtained us-ing the component governing thickness and respective material curve. In the Level 2 calculations, credit was taken for any ad-ditional plate thickness, above the minimum required thickness, through the use of a stress ratio. The evaluation then assigned a temperature reduction based on the calculated stress ratio. The final MAT was determined as the Level 1 MAT minus the tem-perature reduction.

Results. A Level 2 FFS evaluation established the maximum per-missible pressure of 174 psig at the client-specified CET of –10°F. Additionally, the evaluation provided an envelope of permissible pressure-temperature combinations that the owner-user could compare against all operating and upset scenarios (FIG. 4). This enabled the owner-user to develop operational procedures to en-sure satisfactory protection from a potential brittle-fracture event.

TABLE 1. Material construction background for a KO drum

Code of construction ASME S8D1

Year of construction 1965

Material SA-212-B

Design pressure 300 psig

Joint effi ciency 100%

PWHT No

Inside diameter 60 in.

Thickness 0.75 in.

Metal temperature influences the fracture

toughness of construction materials for plant

equipment. At low temperatures, construction

materials can behave in a brittle manner, thus

making them more susceptible to fracture.



CASE STUDY 2This example illustrates the use of the Level 3 FFS method-

ology for brittle-fracture evaluation of a deethanizer column that operates in a service with auto-refrigeration potential. TABLE 2 summarizes the operating conditions for the deetha-nizer column.

Analysis. A rigorous, fracture mechanics-based assessment in accordance with the Level 3 procedures and criteria in Part 9 of API-579 was performed to establish the allowable pressure-temperature curve using proprietary software. The analysis performed assumed a detectible reference flaw size that could be compared to the results of detailed inspection for cracking. A comprehensive, 3D finite-element (FE) model was used to characterize operating stresses (FIG. 6).

The failure assessment diagram (FAD) fracture mechan-ics methodology presented in Part 9 of API-579 (FIG. 4) was used to calculate the allowable pressure-temperature curve. A

postulated semi-elliptical surface-breaking flaw with a depth of 1⁄4 of the nominal shell thickness and a length of six times the depth (i.e., 6:1 aspect ratio) was analyzed in various orien-tations at critical locations. The presence of such large flaws, while unlikely, should be reliably detected by modern inspec-tion techniques (including surface and ultrasonic inspection techniques). The calculated operating and weld-residual stress, along with the material strength and material fracture tough-ness, were used to determine a toughness ratio and a load ratio. These two quantities represent the coordinates of a point that was plotted on a 2D FAD to determine acceptability.

Results. A Level 3 FFS evaluation established the envelope of permissible pressure vs. temperature curves, as shown in FIG. 7. This enabled the owner-user to develop operational procedures to ensure satisfactory protection from a potential brittle-frac-ture event. The bottom curve in this figure shows the boiling point curve for the process fluid, ethane.

CASE STUDY 3This example illustrates the difference in results from a Level

2 FFS vs. a Level 3 FFS for brittle-fracture evaluation of a pres-sure vessel that did not receive a PWHT, but operates in a service with an auto-refrigeration potential. TABLE 3 summarizes details for a pressure vessel subject to auto-refrigeration with no PWHT.

FIG. 6. FEA stress results plot at local discontinuity.

0-160 -140 -120 -100 -80 -60 -40

Temperature, °F-20 0 20 40 60 80 100

20

40

60

80

100

Pres

sure,

psi

120

140

160

180

200

220

240

260

280

300

Acceptable regionPressure-temperature curveUser operating curve

FIG. 5. Level 2 MAT curve results for Case Study 1.

Stress intensity factorsolution, KI

Kr =KI

KMAT

Material toughness,KMAT

Failure assessmentdiagram envelope

Mixed mode – brittlefracture and plastic

collapse

Plastic collapse

Material yield stress,�ys

Reference stresssolution, �ref

Flaw dimensions Stress analysis

Assessmentpoint

Brittle fracture

Load ratio

Unacceptableregion

Acceptableregion

Lr =�ref�ys

Toug

hnes

s rat

io

Flaw dimensions Stress analysis

FIG. 4. API-579 Part 9 FAD diagram.

TABLE 2. Material construction background of the deethanizer column



Material SA-515-70



PWHT Yes


Thickness 1.5625 in.

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Analysis. The assessment included a Part 3 Level 2 FFS brit-tle-fracture screening evaluation in addition to a detailed Part 9 Level 3 FFS fracture mechanics evaluation using proprietary software. The methodologies for the Level 2 and Level 3 evalu-ations were consistent with those detailed in Case Studies 1 and 2, respectively.

Results. The results from the Level 2 FFS evaluation and the Level 3 FFS evaluation (for the recommended postulated flaw depth of 1⁄4 of nominal thickness) both indicate that the vessel does not satisfy the requirements for protection against brittle fracture, as shown in FIG. 8. However, the evaluation shows that the Level 2 results are more favorable than the Level 3 results for pressures below 350 psig. Even if the Level 3 analysis uses a flaw depth of 1⁄8 of nominal thickness, the Level 2 results remain more favorable than the Level 3 results below 230 psig. This ap-parent contradiction occurs because weld residual stress greatly influences the permissible MAT, and it completely drives the MAT at lower applied stresses (i.e., low pressure). These results highlight the importance of completing a detailed Level 3 eval-uation when brittle fracture is a legitimate concern.

However, if the system was re-evaluated to the Level 3 FFS using a postulated flaw depth of 1⁄16 of nominal thickness, as op-posed to the 1⁄4 or 1⁄8 of nominal thickness, then the calculated

MAT curve is above the process boiling point curve, thus indi-cating the acceptability of the 1⁄16 thickness flaw depth. There-fore, with a much more extensive and comprehensive inspec-tion plan, qualification for protection against brittle fracture may be justifiable so long as the inspection techniques are sen-sitive and thorough enough to ensure that no defects greater than 1⁄16 of the nominal shell thickness exist.

CASE STUDY 4This example illustrates the use of a Level 3 FFS brittle-frac-

ture evaluation to optimize the cool-down rate of a hydrodesul-furization (HDS) reactor.

Background. To expedite the cool-down process and limit downtime for an HDS reactor, owner-users often inject cold nitrogen into the reactor upstream piping system. To deter-mine the rate limits for the cool-down process, a formal FFS evaluation was conducted.

Analysis. The study of the cooling process used a rigorous Part 9 Level 3 fracture mechanics assessment to establish the allow-able pressure-temperature curve. The analysis was performed for a reference flaw size that could be readily detected in de-tailed inspections for cracking. A comprehensive, 3D FE model determined the stresses due to internal pressure and thermal transient effects during the cooling process, as shown in FIG. 9.

Results. The results of the Level 3 FFS evaluation (FIG. 10) were used to optimize the cool-down procedure and enable the

FIG. 9. Thermal and stress plots at reactor quench nozzle.

0255075100125150175200225250275300325350375400425450475500525550

-160

-150

-140

-130

-120

-110

-100

-90

-80

-70

-60

-50

-40

-30

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

Inter

nal p

ressu

re, p

sig

Temperature, °F

Level 3 (Part 9) MAT curve w/o PWHT

Ethane boiling point curve Part 3 Level 2 - shell Part 9 Level 3 - shell (t/4 flaw) Part 9 Level 3 - shell (t/8 flaw) Part 9 Level 3 - shell (t/16 flaw) Part 9 Level 3 - shell (t/4 flaw) Annex E

FIG. 8. Level 2 and Level 3 MAT curve results for Case Study 3.

0255075100125150175200225250275300325350375400425450475500

-160

-150

-140

-130

-120

-110

-100

-90

-80

-70

-60

-50

-40

-30

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

Inter

nal p

ressu

re, p

sig

Temperature, °F

Level 3 (Part 9) MAT curve (t/4 flaw)

Ethane boiling point curve Level 3 - shell away from nozzles Level 3 - shell @ M1/M2


TABLE 3. Details for a pressure vessel subject to auto-refrigeration with no PWHT



Material SA-515-70



PWHT No


Thickness 1.1875 in.

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owner-user to minimize downtime without adversely affecting the mechanical integrity of the equipment.

OVERVIEWThere have been a number of catastrophic brittle-fracture

failures in the petrochemical industry. Deficiencies in histori-cal 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-

chanics evaluation should be completed. The Part 9 Level 3 eval-uation, coupled with PWHT and a detailed inspection plan, can be used successfully to qualify low-temperature acceptability.

ACKNOWLEDGMENT a 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 1 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.

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 Fitness-For-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.

Speaker:Lee Nichols, Director, Data DivisionGulf Publishing Company

Moderator:Adrienne Blume, Managing Editor, Hydrocarbon Processing and Gas Processing

Register Today at:HydrocarbonProcessing.com

Global Downstream Constructionand Investment are at an All-time High!The Boxscore Global Construction Activity webcast will highlight current trends in construction activity in the refi ning, gas processing and petrochemical industries around the globe. This includes a detailed breakdown of active and new project construction numbers by region, sector, and status; growing regions of activity; leaders in the industry; and the future of downstream construction activity moving forward.

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150 °F/hr - quench nozzle 100 °F/hr - quench nozzle 75 °F/hr - quench nozzle Prior limit Recommended limit

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PetrochemicalsW. 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. On-going changes in ethane cracking operations do not produce suf-ficient propylene to meet growing demand. Petrochemical yields from the FCCU is an area of increasing interest as more compa-nies try to integrate refining and petrochemical operations.1

PROPYLENE MAXIMIZATIONIn the last 10 years, the FCCU has typically been designed to

produce large amounts of propylene. This has been true for cat-alytic crackers running both conventional and hydrotreated gas-oils (GOs) and atmospheric resids. Several factors are contrib-uting 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 con-versions 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 ob-tained 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 activ-ity. 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 ef-fluents 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 poly-mer-grade products. This design option allows for different op-erating 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 con-versions 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 includ-ed in the gas concentration to produce chemical- or polymer-grade propylene. If this is the case, additional processing units are included for treating propylene for contaminant removal.

Performance. 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 maxi-mum 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


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 de-signed 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 ZSM-5 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 paraffin-ic 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 lim-ited 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 gaso-line is highly aromatic, and it is preferentially a petrochemical

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 alkyla-tion 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 pro-pylene production, and the concerns regarding unit operation.

Operating at elevated reactor temperatures is a key to pro-ducing 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 consid-erations and to help achieve the required high conversions. Higher reactor temperatures require increased catalyst circu-lation 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 pro-ducing propylene. This is achieved from lowering reactor pres-sure 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 HOFCCU

FCC FCC + ZSM-5 HSFCC HSFCC + ZSM-5

C3= yield 3 wt%–5 wt% 6 wt%–8 wt% 10 wt%–13 wt% 15%–20% + wt%

TABLE 1. Typical product yields for conventional gasoline vs. HOFCC comparison

Typical product ranges Gasoline FCC HOFCC

Wt% on fresh feed

Dry gas 1.5–3 3–12

Ethylene 0.5–1.5 2–7

Total LPG 16–22 32–44

Propylene 4–7 12–22

Butylenes 4–8 8–14

Gasoline 47–53 30–40

TABLE 2. Eff ects of variables on propylene yield

Adjustment Concerns

Reactor temperature 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

Hydrocarbon partial pressure

Unit pressure Decrease Higher gas make, larger compressor product recovery section

Steam rate Increase Increase sour water recovery

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

Feedstock

Higher quality More hydrogen Low Δ coke

Hydrotreated severity Increase Capital costs, lower coke precursors

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Petrochemicals

TABLE 5. Light-olefi ns comparison

ProcessCatalytic

olefi ns FCC HOFCCSteam

cracking

Feedstock 70% VGO + 30% VTB

85% VGO + 15% VTB

AGO

Reaction temperature 1,150°F (620°C)

1,010°F (545°C)

1,470°F(800°C)

Light-olefi n yield wt%

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

TABLE 4. Typical light olefi n 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

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 con-tact 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 de-sired 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 go-ing 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 regen-erator temperature when the Δ coke is too low due to the lack of

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 emis-sions, 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 hy-drotreated 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 re-duces the sulfur and nitrogen but also saturates the diolefins and many of the aromatics. This also reduces the downstream fin-ishing 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.

CATALYSTSFor 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 appli-cation, use high concentrations of a shape-selective zeolite with a pentasil crystal structure that has medium-sized pores (ZSM-5), 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 ver-ified 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 un-derstood 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 pro-pylene, ZSM-5 additive concentrations of 3 wt%–5 wt% are in the circulating inventory. With the HSFCC mode, the ad-ditive concentration can be as high as 10% before dilution of the base cracking catalyst occurs. The HOFCC processes fre-quently uses proprietary catalysts, zeolites, and zeolite addi-

80 wt% conversion at 566°C riser temperature

16

15

14

12

13

11

10

9

8

76

0 5 10 15 20 25 3530ZSM-5 in inventory, wt%

C 3= , wt%

FIG. 1. Effect of ZSM-5 concentration on propylene yield.


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 crack-ing of light straight-run naphtha, condensate naphtha, tight oils and olefinic feedstocks from other refinery and petro-chemical processes, research is developing different zeolites and catalysts for cracking these lighter components. The ZSM-5 additives are being investigated for higher gasoline se-lectivity 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 al-pha olefins (C12

+) for producing more propylene and ethylene. There is additional catalyst development to crack C10

+ and high-er 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 OLEFINSThe FCC process is used to produce propylene and eth-

ylene 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 eth-ylene as the primary product. These FCC processes combine carbenium ion catalytic cracking with its β-scission mecha-nism 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 re-spectively 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 de-mands. 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 tem-peratures 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 pen-tasil 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 oper-ation 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 ethyl-ene and propylene compared to the HOFCC. Thus, this pro-cess uses both thermal and catalytic cracking mechanisms to produce desired olefins. The high yields of ethylene and buta-diene 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 car-bon 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 steam-cracker pyrolysis gasoline, and other selectively hydrogenated raffinates from refinery and petrochemical complexes into pro-pylene and ethylene.14

Catalytically cracking paraffinic naphtha to produce light olefins, propylene and ethylene, and aromatics as a liquid by-product 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 ra-tios of 0.55 P/E ratios are being produced.

AROMATICSThe HOFCC produces high yields of light olefins, resulting

in reduced gasoline yields with very high aromatic composi-tions. 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

C9+ aromatics 5–10 25–35 16–30 12–18 32–40

Total 65–70 60–75 75–90 20–40 60–80


Petrochemicals

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. Hydrotreat-ing 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-ole-fins production from ZSM-5.16 The key for producing xylenes is to maximize the conversion for propylene, which will concen-trate 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 gas-oline that is becoming a concern in gasoline-blending pools to meet the current 1 vol% specification found in many coun-tries. 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 pro-duced. Higher conversions will produce more benzene and to-tal aromatics in addition to concentrating them in the naphtha fraction. Benzene can increase due to cyclohexane dehydro-genation or alky benzene dealkylation. Higher RE-exchanged zeolites provide higher hydrogen transfer, and moderate zeolite-to-matrix ratios that favor benzene production. Tolu-ene production is not as affected by reactor temperatures as benzene formation as shown by an increase in the benzene-to-toluene 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 prod-uct 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 feed-stock is lighter, resulting in more benzene, and, as shown pre-viously, high ethylene and butadiene yields are due to thermal cracking reactions. However, the catalytic olefins process does show acceptable BTX, especially xylenes, for petrochemicals.

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 die-sel, 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

+ re-covery 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 1 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.

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.

TABLE 7. BTX process comparison9

ProcessCatalytic

olefi ns FCC HOFCCSteam

cracking

Feedstock 70% VGO + 30% VTB

85% VGO + 15% VTB

AGO

Reaction temperature 1,150°F (620°C)

1,010°F (545°C)

1,470°F (800°C)

C6–C8s in naphtha, wt%

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


Refining DevelopmentsG. 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 produc-tion 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 dem-onstrated 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. Re-fineries that process high-solids-content crude oils effectively, without experiencing operating and integrity issues, can in-crease the volume of opportunity crudes processed, and, con-sequently, 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 down-grading of product value. Poor desalter operation can also strain wastewater treatment units (WWTUs) and lead to non-compliance issues. These attractively priced crude oils, how-ever, 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 SOLIDSCrude oil contains a wide range of naturally occurring sol-

ids 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 re-mains 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., sili-con 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 be-fore 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) becom-ing 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 work-ing 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 vulner-able to fouling includes heat exchangers, furnaces, towers, FCC unit diplegs and expanders. There are many causes for fouling, including organic fouling (asphaltene deposition and sodium-catalyzed 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 tempo-rary 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, conse-quently, problems for the WWTU. Transition metals such as iron (Fe), nickel and zinc can also harm WWTUs. These is-sues 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 re-turned 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 de-salted crude. The higher salt content can lead to higher corro-sion 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 cata-lyst’s effectiveness and service life.


Refining Developments

Loss of product value. Because solids tend to concentrate in bottom streams, they can introduce ash and metals into re-sidual 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 manage-ment 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. Miss-ing 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 en-hance 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 re-moval. However, experience shows that only marginal increases in solids removal are achieved via these steps.

Demulsification. Primary demulsifier chemistries are routine-ly 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 sol-ids. 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 re-duce 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

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 sol-ids, thus making the process more effective.

Greater residence time enables the agents to associate effec-tively 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, es-pecially with the higher incidence of “micro-fine” solids (small-er 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 need-ed to remove these solids, using the desalter equipment.

A NEW APPROACHCanadian oil sands are high-solids crude oils. They often

contain higher-than-average solids loadings due to the produc-tion 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 characteriza-tion methods, pretreatment chemicals, and a desalter chemical additive to help transport solids (including sub-µ-diameter sol-ids) 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-

TABLE 1. Pretrial desalter profi le

Sample Filterable solids, PTB Solids, % Water, % Oil, %

Raw 64 0.1 0.2 0.0

Desalted 44 0.05 0.5 0.0

Tryline #5 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

Effl uent 11 0 100 0.0

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ter, and sometimes with an emulsion layer at the bottom try-line. 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 sam-ple 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 sol-ids 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 il-lustrated 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 read-ily 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 with-out free oil was achieved.

Normal operationsUsing SRA

Pre-trial

Filte

rable

solid

s rem

oval,

%

010

20

30

40

50

60

70

80

90

100

Day 0 Day 1 Day 2 Day 3

FIG. 5. Solids removal efficiency improved by more than 50% with customized SRA.a

Pretrial100% emulsion

Day 1 Day 2

SRA treatmentBaseline

Brine

TR1

TR2

TR3

TR4

TR5

Day 3

FIG. 2. Descent of solids in desalter trylines with and without SRA treatment.a

Day 1 Day 2

SRA treatmentBaseline

Brine

solid

s, PT

B

Day 3 Day 4

1,3671,472

1,297

245

60

200

400

600

800

1,000

1,200

1,400

1,600

11

FIG. 3. Brine solids increase (PTB) with the new customized SRA.a

FIG. 4. Brine sample containing more than 30% solids and no oil.

FIG. 1. Tryline #1 sample and visual appearance before and after treatment.



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 emul-sion band and significant oil undercarry, which upset its WWTU.

The new owner of the PFT crude parcel had previous suc-cess running low-percentage blends of this same crude after the implementation of a crude management program.b, c How-ever, 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 estab-lished 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 pre-vious heavy crude operations, the use of new the SRA increased removal to 80%–85%, as shown in FIG. 5. Additionally, the down-ward 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% with-out 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 long-term returns on this PFT crude oil by using SRA technology.a

Case 2: Iron reduction in FCC unit feed. An ongoing appli-cation of the new technology was initiated in response to prob-lems 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 vibra-

tion events and reduce Fe loading on the catalyst.a Improved Fe control would reduce catalyst-makeup costs. The treatment re-sulted 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 leav-ing in the desalted crude and brine. In a typical desalter pro-cessing 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

Day 0 Day 3 Day 4

01

2

3

4

5

1

2

3

4

5

1

2

3

4

5

5 10Filterable solids content, %

Desa

lter t

rylin

es

15 20 0 5 10Filterable solids content, %

15 20 0 5 10Filterable solids content, %

15 20

FIG. 6. Downward migration of solids from the emulsion layer into the brine with customized SRA.

Program optimizationsolids = 106 PTB average

Fe = 69 ppm average

Baselinesolids = 4 PTB average

Fe < 1 ppm average

Program maintenancesolids = 388 PTB average

Fe = 161 ppm average

01 2 3 4 5 6 7

Time in operation, months

Brine solids, PTBBrine Fe content, ppm

8 9 10 11 12

100

0

100

200 Iron,

ppm

Solid

s, PT

B

300

400

200

300

400

500

600

700

800

FIG. 7. Solids and iron content in the brine rose significantly with the use of the new SRA technology.a

Baseline Program maintenanceProgram

optimization

1 2 3 4 5 6 7 8 9 10 11 12Time in operation, months

0.25

0.35

0.45

0.55

0.65

0.75

Fe on

FCC c

ataly

st, w

t %

FIG. 8. With the use of the new SRA technology, e-cat Fe loading was significantly reduced, helping to prolong catalyst life.a


90

cases, the measured brine solids often represent only a small percent of the solids removed from the raw crude. If solids re-lease 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

Fe loadings on (and extended the life of) the FCCU catalyst. These excellent results were achieved while maintaining out-standing desalter performance (salt removal and dehydration) and oil-free brine—with no increase in wastewater chemical oxygen demand (COD).

Options. The new SRA technology can greatly enhance the re-lease and removal of solids from crude oils. It provides a strik-ing 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 en-able 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-lim-its. Solids management is a viable action.

ACKNOWLEDGMENTThis article is based on an earlier presentation at the 2014 AFPM Annual

Meeting in Orlando, Florida, March 23–25, 2014.

NOTES a 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.

LITERATURE CITED 1 “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 refer-ence, 1990, Baker Hughes.

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.

1 2 3 4 5 6 7 8 9 10 11 12Time in operation, months

0.25

Solid

s mat

erial

balan

ce, %

Program optimizationAverage closure = 17%

BaselineAverage closure = 2%

Program maintenanceAverage closure = 98%

FIG. 9. Solids material balance: Removal from crude vs. contained in effluent brine.



Innovations

ADRIENNE BLUME, MANAGING EDITOR

[email protected]

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 in-dicators (EnPI) to track how energy is consumed in a plant. The tool identifies gaps between EnPI targets and actual per-formance, and it helps identify counter-measures to improve energy performance. The EP-Analytics software is powered by the Soteica Visual MESA energy manage-ment and optimization solution.

Manufacturers around the world are working to improve their energy perfor-mance and protect the environment by reducing greenhouse gas emissions. Re-leased in 2011, the ISO50001 standard provides a framework of requirements that help companies in the process indus-try effectively manage their energy perfor-mance and achieve regulatory compliance.

By visualizing and tracking the energy consumption of each unit in a plant, in-efficiencies 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, tem-perature, flowrate and other plant data.

Based on the Visual MESA simula-tion engine, the EP-Analytics software uses first-principle models to track en-ergy 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 oth-er imbalances in the overall system. This information can then be used to plan spe-cific 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.


Bioreactor removes bulk contaminants from wastewater

UOP’s XCeed bioreactor is an ad-vanced biological treatment process for the bulk removal of organic and inor-ganic 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 reme-diation applications.

The system’s plug-flow configura-tion (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 sys-tem, promoting high removal efficiency

in a compact reactor. Compartmentaliza-tion 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 biocata-lysts—or microbes—to grow. More complex generations of microbial growth result from biomass retention times of nearly 100 days. This biological ecosys-tem promotes the growth of microbes such as protozoa, nematodes, rotifers or oligochaeta that reduce biomass produc-tion by predation of the primary trophic microorganisms. As a result, the process produces up to 80% less sludge than al-ternative systems. In addition, the nature of the microbial population results in re-sistance to upstream process changes and allows the bioreactor to quickly reach a steady state after a restart (typically with-in 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.


Innovations

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

• 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 in-stallations 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.


Communications system enables remote gas detection

Dräger’s new communications sys-tem, 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 oc-curring is always present.

Connecting gas detection systems to the X-zone Com communications de-vice means that data can be transferred wirelessly to mobile devices or to control

rooms. The X-zone Com works by send-ing 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 communica-tions system offers a holistic solution cov-ering 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.


Moisture transmitter introduces integral display

Michell Instruments’ Easidew PRO XP explosion-proof dewpoint transmit-ter is now available with an optional in-tegral 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 trans-mitter is housed in an epoxy-coated alu-minum casing as standard; an alternative 316 stainless steel casing is available for offshore applications.

The transmitter uses ceramic mois-ture 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 mea-surement 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.


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.

FIG. 3. The X-zone Com communications system enables users to track gas detection levels from outside areas being monitored.

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

HELEN MECHE, ASSOCIATE [email protected]

Events


NOVEMBER

Sulphur 2014 International Conference & Exhibition, Nov. 3–6, Paris Marriott Rive Gauche Hotel & Conference Center, Paris, FranceP: +44 207 903 [email protected]

Gulf Publishing Company Events, 2014 Women’s Global Leadership Conference in Energy, Nov. 4–5, Hyatt Regency Houston, Houston, Texaswww.wglnetwork.com(See box for contact information)

5th World Shale Oil & Gas Summit, Nov. 4–7, Fairmont Dallas Hotel, Dallas, TexasP: +44 (0) 207 978 [email protected]

Latin American Petrochemical and Chemical Association (APLA) 34th Latin American Petrochemical Annual Meeting, Nov. 8–11, Hotel Sofitel, Rio de Janeiro, BrazilP: [email protected]

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., CanadaP: +1 (613) [email protected]

American Fuel and Petrochemical Manufacturers (AFPM) International Lubricants & Waxes Meeting, Nov. 13–14, Hilton Post Oak, Houston, TexasP: +1 (202) [email protected]

CORCON 2014—Corrosion Conference & Expo, Nov. 12–15, Hotel Grand Hyatt Mumbai, Mumbai, IndiaP: +91-22-2579 79 30F: +91-22-6692 15 [email protected]

American Society of Mechanical Engineers (ASME) 2014 International Mechanical Engineering Congress & Exposition, Nov. 14–20, Palais des Congres, Montreal, Quebec, CanadaP: +1 (973) [email protected]

American Institute of Chemical Engineers (AIChE) Annual Meeting, Nov. 16–21, Atlanta Marriott Marquis & Hilton, Atlanta, Ga.P: +1 (203) 702-7660F: +1 (203) [email protected]

Asian Nitrogen + Syngas 2014, Nov. 17–19, Ritz Carlton, Jakarta, IndonesiaP: +44 (0) 20 7903 [email protected]

ERTC 19th Annual Meeting, Nov. 18–20, Corinthia Hotel Lisbon, Lisbon, PortugalP: +44 (0) 207 484 [email protected]/ertc-annual-meeting

North American Pipeline Congress, Nov. 19–20, The Westin Chicago River North, Chicago, Ill.P: +1 (403) [email protected]

DECEMBER

Valve World 2014 Expo and Conference, Dec. 2–4, Messe Düsseldorf, Düsseldorf, GermanyP: +49 (0) 211 45 60 01F: +49 (0) 211 45 [email protected]

Shanghai 9th International Petroleum Petrochemical Natural Gas Technology Equipment Exhibition (SIPPE), Dec. 4–6, Shanghai New International Expo Center, Shanghai, ChinaP: [email protected]/en/

CATCON2014, Dec. 8–9, Hyatt North Houston, Houston, TexasP: +1 (215) [email protected]

Institution of Mechanical Engineers (IMechE) Piping and Pipeline Risk-Based Inspection, Dec. 9, Aberdeen Marriott Hotel, Aberdeen, Scotland, UKP: +44 (0) 20 7222 [email protected]

LPG Asia, Dec. 9–11, Traders Hotel, Singapore, SingaporeP: +65 6508 [email protected]

Center for Chemical Process Safety (CCPS) 2014 Global Summit on Process Safety, Dec. 15–16, Lalit Hotel, Mumbai, IndiaP: +1 (646) [email protected]

American Society of Mechanical Engineers (ASME) Gas Turbine India Conference, Dec. 15–17, New Delhi, IndiaP: +1 (973) [email protected]

JANUARY 2015

The Future of Aromatics, Jan. 14–15, Amsterdam, The NetherlandsP: +44 (0) 203 141 [email protected]

API 2015 Inspection Summit, Jan. 26–29, Galveston Island Convention Center,Galveston, Texas(See box for contact information)

8th Annual European Gas Conference 2015, Jan. 27–29, Vienna, AustriaP: +44 (0) 207 384 8015botting@theenergyexchange.co.ukwww.europeangas-conference.com

FEBRUARY 2015ARC’s 19th Annual Industry Forum, Feb. 9–12, Renaissance Orlando at SeaWorld, Orlando, Fla.P: +1 (781) [email protected]

Middle East Turbomachinery Symposium, Feb. 15–18, Sheraton Doha Resort & Conference Hotel, Doha, QatarP: +1 (979) [email protected]/

Society of Plastics Engineers (SPE) South Texas Section, International Polyolefins Conference 2015, Feb. 22–25, Hilton Houston North, Houston, TexasP: +1 (713) [email protected]/conference.php

CORROSION 2015, Mar. 15–19, The Kay Bailey Hutchison Convention Center, Dallas, TexasP: +1 (281) [email protected]

MARCH 2015Gulf Publishing Company Events, Energy Construction Forum, Mar. 3–4, Moody Gardens Convention Center, Galveston, TexasEnergyConstructionForum.com(See box for contact information)

Hydrocarbon Processing/Gulf Publishing Company EventsP: +1 (713) 529-4301F: +1 (713) [email protected] [email protected]

American Petroleum Institute (API)P: +1 (202) [email protected]

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ADVERTISER INDEX / HydrocarbonProcessing.com

The first number after the company name is the page on which an advertisement appears. The second number, appearing in parentheses, after the company name, is the Reader Service Number. There are two ways readers can obtain product and service information:

1. Go to www.HydrocarbonProcessing.com/RS. Follow the instructions on the screen, and your request will be forwarded for immediate action.

2. Go online to the advertiser's Website listed below.

Company Page RS# Website



Air Liquide ................................................................. 8 (101)www.info.hotims.com/51002-101

American Petroleum Institute ................................... 26 (155)www.info.hotims.com/51002-155

Ametek Process Instruments ......................................35 (74)www.info.hotims.com/51002-74

Ametek Process Instruments ...................................... 51 (164)www.info.hotims.com/51002-164

ARC’s Collaborative Mfg ............................................. 71 (62)www.info.hotims.com/51002-62

AW Chesterton Company ...........................................14 (152)www.info.hotims.com/51002-152

Axens .....................................................................100 (51)www.info.hotims.com/51002-51

Baker Hughes ......................................................... 20 (67)www.info.hotims.com/51002-67

Baldor Electric Company ........................................... 24 (64)www.info.hotims.com/51002-64

Bete Fog Nozzle ....................................................... 65 (73)www.info.hotims.com/51002-73

Borsig GmbH ........................................................... 49 (162)www.info.hotims.com/51002-162

Catalyst Group Catcon ................................................73 (57)www.info.hotims.com/51002-57

CB&I .........................................................................33 (56)www.info.hotims.com/51002-56

Clariant .................................................................... 12 (151)www.info.hotims.com/51002-151

Compressor Controls................................................. 28 (69)www.info.hotims.com/51002-69

Cudd Energy Services ............................................... 43 (159)www.info.hotims.com/51002-159

Dechema ..................................................................57 (165)www.info.hotims.com/51002-165

Emcor ...................................................................... 13 (97)www.info.hotims.com/51002-97

Exida.com ................................................................ 15 (61)www.info.hotims.com/51002-61

Flexitallic LP .............................................................. 5 (93)www.info.hotims.com/51002-93

Flir Systems, Inc ........................................................32 (156)www.info.hotims.com/51002-156

Friedrich Air Conditioning Co ......................................16 (153)www.info.hotims.com/51002-153

Gulf Publishing Company Boxscore Database ............................................... 87 Events—ECF ..........................................................52 Events—EMGC ...................................................... 97 Events—IRPC ........................................................77 HPI Market Data 2015 .......................................... 6–7 Webcast ....................................................56, 70, 78 US Gas Processing Plant Directory ...........................81 Hytorc ...................................................................... 17 (154)

www.info.hotims.com/51002-154KBC Advanced Technologies Inc ................................. 39 (81)

www.info.hotims.com/51002-81LAR Process Analysers .............................................. 40 (158)

www.info.hotims.com/51002-158Linde Process Plants ................................................. 99 (82)

www.info.hotims.com/51002-82Mangan Software Solutions ...................................... 58 (80)

www.info.hotims.com/51002-80Merichem Company ...................................................22 (84)

www.info.hotims.com/51002-84NAES Corporation ................................................... 50AOil Careers ................................................................75

Paharpur Cooling Towers, Ltd. ................................... 30 (95)www.info.hotims.com/51002-95

Paratherm Heat Transfer Fluids ................................. 48 (161)www.info.hotims.com/51002-161

Plymouth Tube Company .......................................... 50 (163)www.info.hotims.com/51002-163

Rentech Boiler System ................................................ 2 (52)www.info.hotims.com/51002-52

Samson GmbH ......................................................... 45 (160)www.info.hotims.com/51002-160

Sherwin Williams ..................................................... 46 (85)www.info.hotims.com/51002-85

Spraying Systems Co .................................................61 (66)www.info.hotims.com/51002-66

Team Industrial Services ............................................53 (99)www.info.hotims.com/51002-99

Teikoku USA ............................................................. 34 (157)www.info.hotims.com/51002-157

TLV Corporation........................................................ 69 (63)www.info.hotims.com/51002-63

Trachte USA ............................................................. 90 (166)www.info.hotims.com/51002-166

UOP LLC ....................................................................27 Veolia Water Solutions & Technologies ....................... 54 (71)

www.info.hotims.com/51002-71Weir Minerals Lewis Pumps ....................................... 42 (91)

www.info.hotims.com/51002-91Zeeco .......................................................................18 (94)

www.info.hotims.com/51002-94Zeeco ...................................................................... 63 (96)

www.info.hotims.com/51002-96ZymeFlow Decon Technology .................................... 66 (92)

www.info.hotims.com/51002-92

Bret Ronk, PublisherPhone/Fax: +1 (713) 520-4421E-mail: [email protected]

SALES OFFICES—NORTH AMERICA

IL, LA, MO, OK, TXJosh MayerPhone: +1 (972) 816-6745, Fax: +1 (972) 767-4442E-mail: [email protected]

AK, AL, AR, AZ, CA, CO, FL, GA, HI, IA, ID,

IN, KS, KY, MI, MN, MS, MT, ND, NE, NM,

NV, OR, SD, TN, TX, UT, WA, WI, WY,

WESTERN CANADA Ryan AkbarPhone/Fax: +1 (713) 520-4449Mobile: +1 (832) 691-6053E-mail: [email protected]

CT, DC, DE, MA, MD, ME, NC, NH,

NJ, NY, OH, PA, RI, SC, VA, VT, WV,

EASTERN CANADAMerrie LynchPhone: +1 (617) 357-8190, Fax: +1 (617) 357-8194Mobile: +1 (617) 594-4943E-mail: [email protected]

CLASSIFIED SALES

Gerry MayerPhone: +1 (972) 816-3534, Fax: +1 (972) 767-4442E-mail: [email protected]

DATA PRODUCTS

Lee NicholsPhone/Fax: +1 (713) 525-4626E-mail: [email protected]

SALES OFFICES—EUROPE

FRANCE, GREECE, NORTH AFRICA,

MIDDLE EAST, SPAIN, PORTUGAL,

SOUTHERN BELGIUM, LUXEMBOURG,

SWITZERLAND, GERMANY, AUSTRIA, TURKEYCatherine WatkinsPhone: +33 (0) 1 30 47 92 51Fax: +33 (0) 1 30 47 92 40E-mail: [email protected]

Jim WatkinsPhone: +33 (0) 1 30 47 92 51Fax: +33 (0) 1 30 47 92 40Cell: +33 (0) 6 76 35 11 [email protected]

ITALY, EASTERN EUROPEFabio PotestáMediapoint & Communications SRLPhone: +39 (010) 570-4948Fax: +39 (010) 553-0088E-mail: [email protected]

RUSSIA/FSULilia FedotovaAnik International & Co. Ltd.Phone: +7 (495) 628-10-333E-mail: [email protected]

UNITED KINGDOM/SCANDINAVIA,

NORTHERN BELGIUM, THE NETHERLANDSMichael BrownPhone: +44 161 440 0854Mobile: +44 79866 34646E-mail: [email protected]

SALES OFFICES—OTHER AREAS

AUSTRALIA—PerthBret RonkPhone: +1 (713) 529-4301Fax: +1 (713) 520-4421E-mail: [email protected]

CHINA—Hong KongIris YuenPhone: +86 13802701367 (China) Phone: +852 69185500 (Hong Kong)E-mail: [email protected]

BRAZIL—São PauloAlfred BilykPhone/Fax: 11 23 37 42 40Mobile: 11 85 86 52 59 E-mail: [email protected]

INDIAManav KanwarPhone: +91-22-2837 7070/71/72Fax: +91-22-2822 2803Mobile: +91-98673 67374E-mail: [email protected]

INDONESIA, MALAYSIA, SINGAPORE, THAILANDPeggy ThayPublicitas Singapore Pte LtdPhone: +65 6836-2272Fax: +65 6634-5231E-mail: [email protected]

JAPAN—TokyoYoshinori IkedaPacific Business Inc.Phone: +81 (3) 3661-6138Fax: +81 (3) 3661-6139E-mail: [email protected]

KOREAYoung-Seoh ChinnJES Media, Inc.Phone: +82 (2) 481-3411/3Fax: +82 (2) 481-3414E-mail: [email protected]

REPRINTS

Rhonda Brown, Foster Printing ServicePhone: +1 (866) 879-9144 ext. 194E-mail: [email protected]

This Index and procedure for securing additional information is provided as a service to Hydrocarbon Processing advertisers and a convenience to our readers. Gulf Publishing Company is not responsible for omissions or errors.


Statement of Ownership, Management and Circulation (Required by 39 U.S.C.).

1. Title of publication: HYDROCARBON PROCESSING2. Publication number: ISSN 0018-81903. Date of filing: October 1, 20144. Frequency of issue: Monthly5. Number of issues published annually: 126. Annual subscription price: $239.007. Complete mailing address of known office of publication: Gulf Publishing

Company, P. O. Box 2608 (2 Greenway Plaza, Suite 1020, 77046), Houston, Harris County, Texas 77252-2608.

8. Complete mailing address of the headquarters or general business offices of the publishers: Gulf Publishing Company, P. O. Box 2608 (2 Greenway Plaza, Suite 1020, 77046), Houston, Texas 77252-2608, Contact person: Alice Murrell; Telephone (713) 529-4301.

9. Names and complete addresses of publisher, editor and managing editor: Publisher—Bret Ronk, 2 Greenway Plaza, Suite 1020, Houston, Texas 77046; Editor—Stephany Romanow, 2 Greenway Plaza, Suite 1020, Houston, Texas 77046; Vice President, Production—Sheryl Stone, 2 Greenway Plaza, Suite 1020, Houston, Texas 77046.

10. Owner: Euromoney Institutional Investor PLC, Nestor House, Playhouse Yard, London EC4V 5EX, United Kingdom

11. Known bondholders, mortgagees and other security holders owning or holding 1 percent or more of total amount of bonds, mortgages or other securities: Euromoney Institutional Investor PLC, Nestor House, Playhouse Yard, London EC4V 5EX, United Kingdom

12. Tax Status has not changed13. Publication title: Hydrocarbon Processing14. Issue date for circulation data below: September 201415. Extent and nature of circulation—Average number of copies each issue dur-

ing preceding 12 months. (A) Total number of copies (net press run)—22,922. (B) Legitimate paid and/or requested distribution: (1) Outside County Paid/Requested Mail Subscriptons stated on PS Form 3541—10,080; (2) In-County Paid/Requested Mail Subscriptions stated on PS Form 3541—0; (3) Sales through dealers and carriers, street vendors, and counter sales, and other

paid or requested distribution outside USPS—10,943; (4) Requested Copies distributed by other mail classes through the USPS—32. (C) Total paid and/or requested circulation (sum of 15B1,2,3 and 4)—21,055. (D) Nonrequested distribution (by mail and outside the Mail): (1) Outside County nonrequested Copies Stated on PS Form 3541—0; (2) In-County Nonrequested copies Stated on PS Form 3541—0; (3) Nonrequested copies distributed through the USPS by Other Classes of Mail—0; (4) Nonrequested Copies Distrib-uted Outside the Mail—830. (E) Total Nonrequested Distribution (sum of 15d)—830. (F) Total distribution (sum of 15C and E)—21,885. (G) Copies not distributed—1,037. (H) Total (sum 15F and G)—22,922. (I) Percent paid and/or requested circulation (15C/F x 100)—96.21%. Actual number of copies of single issue published nearest to filing date: (A) Total number of copies (net press run)—22,408. (B) Legitimate Paid and/or requested distribution: (1) Outside County Paid/Requested mail Subscriptions stated on Form 3541 (include advertiser’s proof and exchange copies)—10,803; (2) In-County Paid/Requested mail Subscriptions stated on PS Form 3541—0; (3) Sales through dealers and carriers, street vendors, and counter sales, and other paid or requested distribution outside USPS—10,115; (4) Requested copies distributed by other mail classes through the USPS—30. (C) Total paid and/or requested circulation (sum of 15B1,2,3 and 4)—20,948. (D) Nonrequested distribution (by mail and Outside the mail): (1) Outside County Nonre-quested copies stated on PS Form 3541—0; (2) In-County Nonrequested copies distributed as stated on PS Form 3541—0; (3) Nonrequested copies distributed through the USPS by Other Classes of mail—0; (4) Nonrequested Copies Distributed Outside the Mail—456. (E) Total Nonrequested distribu-tion (sum of 15 D)—456. (F) Total distribution (sum of 15 C and E)—21,404. (G) Copies not distributed—1,004. (H) Total (sum15 F and G)—22,408. (J) Percent paid and/or requested circulation (15C/F x 100)—97.87%.

16. This statement of ownership will be printed in the November 2014 issue of this publication. Publication required.

17. Signature and Title of Editor, Publisher, Business Manager, Or Owner

I certify that the statements made by me above are correct and complete. /s/ Sheryl Stone, Vice President, Production

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People

Philip K. Asherman, CB&I’s CEO, has been elected to the board of directors of the National Safety Council. CB&I is a charter member of the National Safety Council, and the two organizations have been partners for nearly 100 years.

Founded in 1913, the National Safety Council is a nonprofit organization whose mission is to save lives by preventing injuries and deaths at work, in homes and communities, and on the roads through leadership, research, education and advocacy.

The National Safety Council advances this mission by partnering with businesses, government agencies, elected officials and the public to make an impact where the most preventable injuries and deaths occur.

Virent has appointed Edgar Steenwinkel asthe company’s vice president of research and development. Mr. Steenwinkel joins Virent from Albemarle, where he served as global business director for alterrnative fuels technologies. At Albemarle, he led multiple global development and commercialization efforts for catalysts and other new products for bio-based transportation fuels. Steenwinkel has over 20 year of experience in manufacturing and building new global business groups.

Patricia Vega is the new president and CEO of GE Oil and Gas for Latin America. She has 20 years of experience in the oil industry, including technical, operational and leadership positions in the US, Mexico, Colombia and Brazil. Based in Rio de Janeiro, she will be responsible for developing regional capabilities. Ms. Vega has a master’s degree in engineering management from Oklahoma State University and an MBA degree from the Thunderbird School of Global Management.

Chevron has named Mary A. Francis corporate secretary and chief governance officer, effective May 1, 2015. In her new role, Ms. Francis will counsel the board of directors and senior management of Chevron on corporate governance matters, manage the corporate governance department and serve on the Law Function Executive Committee. She succeeds Lydia I. Beebe, who is retiring from Chevron after 37 years with the company. Ms. Francis joined Chevron in 2002 as a trademark senior counsel. She was appointed to lead senior counsel in Chevron Shipping. In 2009, she was appointed general counsel of the Chevron Asia Pacific, Exploration and Production Co. She was appointed chief corporate counsel in 2012.

Golar LNG has appointed Frank Joseph Chapman to its board of directors. He will act as the company’s Chairman. Mr. Chapman has worked 40 years in the oil and gas industry culminating in a 12-year period as CEO of BG Group. Under his leadership, BG Group grew into an international integrated oil and gas major. Operating profits grew from some $50 million in 1996 to more than $8 billion in 2012. He is currently a non-executive director of Rolls-Royce and chairman of its safety and ethics committee. He was knighted in 2011 by the Queen of England.

Deutsche Bank has hired Kristina Kazarian as a director and lead research analyst covering the master limited partnerships (MLPs) and natural gas sectors within the bank’s markets division. She is based in New York and reports to Steve Pollard, head of research for the Americas. Ms. Kazarian joined Deutsche Bank after more than seven years at Fidelity Management and Research. During her tenure at Fidelity, she covered several energy verticals. Most recently, she was the senior analyst responsible for the MLP and midstream sector, which has become one of the largest sub-sectors in energy with over $700 billion market cap.

Andatee China Marine Fuel Service Corp. (AMCF), an independent operator engaged in the production, storage, distribution and trading of blended marine fuel oil for cargo and fishing vessels, as well as research and development of clean energy solutions in China, has appointed Shao-Hua Chu as a new independent director. Mr. Chu is chairman of the Chinese Petroleum Institute and is the board director for Taiwan Green Productivity Foundation and CTCI Foundation. Mr. Chu has over 40 years of management and operational experience in the petroleum industry. Until his retirement in 2012, he served as chairman and president of CPC Corp., a state-owned petroleum, natural gas and gasoline conglomerate in Taiwan. Mr. Chu started his career in the petroleum industry in early 1970s with CPC and advanced to various senior level management positions.

Willbros Group has announced that Robert R. Harl, who joined Willbros in 2006 and has served as CEO of the company since January 2007, is retiring as CEO and director when his current employment agreement expires on January 2, 2015. John T. McNabb, II, non-executive chairman of the board, has been elected by the Willbros board of directors as executive chairman of the board on an interim basis, effective immediately. Additionally, the company announced that S. Miller Williams has been elected as lead independent director. The Willbros board of directors is continuing its search to identify a successor to Mr. Harl. It is anticipated that Mr. McNabb will step down as executive chairman of the board and continue to serve as a director, once a successor has been selected and is in place.

FGE has welcomed two new consultants to its Singapore office: Reza Simchi and Tushar Bansal. Mr. Simchi joins as a principal consultant, working within FGE’s oil and gas services. Mr. Bansal joins as a senior consultant, and will be leading FGE’s East of Suez Oil service. Mr. Simchi has a decade’s worth of experience working at Nexen, where he managed risk and quantitative analysis, along with commodity structuring and analytics. He has a PhD in mathematics from the University of Calgary, Canada. Mr. Bansal has experience in petroleum analytics from his former roles as an analysis manager with Koch Supply and Trading, a downstream oil consultant at Wood Mackenzie and an oil market analyst with Shell Trading. He has a bachelor’s degree from Nanyan Technological University, Singapore.

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