HP_2012_11

PLANT SAFETY AND ENVIRONMENT

速

Best practices and new equipment mitigate operating risks

REFINING DEVELOPMENTS HydrocarbonProcessing.com | NOVEMBER 2012

Processing flexibility is needed to respond to changing fuel and market needs

Reliability has no quitting time

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NOVEMBER 2012 | Volume 91 Number 11 HydrocarbonProcessing.com

40

60 8 SPECIAL REPORT: PLANT SAFETY AND ENVIRONMENT

41 Relief valve and flare action items: What plant engineers should know D. Smith and J. Burgess

47 Surviving and thriving in the era of enhanced OSHA PSM audits C. Reese and B. Taylor

51 Keep it simple: Three key elements to fighting complex flammable liquid fires E. LaVergne

55 Update on the greenhouse gas regulation by the US EPA R. Crum and B. Broberg

BONUS REPORT: REFINING DEVELOPMENTS

61 Consider new technologies to increase diesel yield

DEPARTMENTS

4 8 11 15 23 28 100 104

Plant economics with incentives M. Tellini and F. Manenti

Reliability Closed-oil-mist systems and maintenance cost avoidance

33

Integration Strategies The energy water nexus

35

Engineering Case Histories Case 71: Statistical visual data can be useful in troubleshooting—Part 1

37

Viewpoint Age of turbulence: Charting a course for refiners toward a profitable future Control What’s new with FOUNDATION fieldbus—Part 1

J. Zhou, S. Vaidyanathan and S. Kapur

T-84 How do project management practices guide turnaround execution?

L. Amendola, M. A. Artacho and T. Depool

Innovations Construction Construction Boxscore Update Marketplace Advertiser index

31

77 Improve integration opportunities for aromatics units—Part 1 NORTH AMERICAN TURNAROUND AND MAINTENANCE— SUPPLEMENT

Brief Impact

COLUMNS

from bottom-of-the-barrel products L. Wisdom, J. Duddy and F. Morel

71 Low-pressure absorption of CO2 from flue gas:

Industry Perspectives

106

Cover Image: The Repsol refinery in Cartagena, Spain, was inaugurated in 1951. With an approximate area of 190 hectares, the Cartagena refinery, with 5.5 million tpy of production capacity, is divided into two large areas: fuel production and other specialty products, which includes lubricant bases, asphalts, paraffins and aromatic oils. In 2011, a €3.2 billion expansion project was completed at the Cartagena refinery. This project doubled processing capacity to 220,000 bpd, making it Repsol’s most modern and efficient refinery.

P. O. Box 2608 Houston, Texas 77252-2608, USA Phone: +1 (713) 529-4301 Fax: +1 (713) 520-4433 www.HydrocarbonProcessing.com Editorial@HydrocarbonProcessing.com

Industry Perspectives Key industry officials answer a poll question from HydrocarbonProcessing.com Has your HPI company addressed cyber security at its operating facilities?

“ARC Advisory Group believes that the poll results reflect a reasonably accurate picture of the current degree of cybersecurity preparedness in HPI plants. Our research indicates that most HPI plants lean heavily on their automation suppliers, who—for the most part—have beefed up their cyber-security-related services and developed dedicated global centers of excellence. However, as the survey results also indicate, end users in HPI plants also look to the US Computer Emergency Readiness Teams (CERT) and other government entities to come up with specific guidelines that help fill in the inevitable cyber-security gaps.”

—PETER REYNOLDS, ARC Advisory Group Senior Consultant, ARC Advisory Group “In my opinion, security suffers from an identity crisis.

Security as it pertains to preventing live hacks or attacks is only a fraction of the concern in running electronic networks. While external ‘bad actors’ looking to break in and disrupt/steal/shut down our networks and systems are always a concern, the real challenge is to manage our electronic assets in such a way as to protect the safe, reliable, expected operation of the facilities we run.

Any threats, from inadvertent virus outbreaks to faulty hardware/software to nation state attacks, are all a risk and need to be protected against. Security also needs to become ingrained in our culture the same way safety has become second nature to manufacturers. In other words, the notion of security needs to be ‘baked into’ every decision, action and purchase we make from HR to procurement to administration to operators, IT, engineers and so on. It is our collective responsibility—not limited to technology or corporate IT. The future of better security lies in the management of existing security tools and techniques. The technology exists to protect ourselves better than we have been. What is missing is the people, the time and the motivation.”

—RICK KAUN, Global Business Manager, Industrial IT Solutions, Honeywell Process Solutions “HPI companies in North America should continue to review and understand national standards already being applied and enforced in other industries, particularly standards being developed by the US Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corp. (NERC) and their Critical Infrastructure Protection programs for the power industry. We believe these will eventually become enforced standards for the hydrocarbon processing industry as well. For refiners, it’s a good time to look at their systems, their culture and their suppliers to understand new risks and what they need to do to overcome them.”

—CHRIS LYDEN, Senior Vice President, Business Development, Invensys Operations Management

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

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Periodicals postage paid at Houston, Texas, and at additional mailing office.

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Copyright © 2012 by Gulf Publishing Company. All rights reserved.

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See INDUSTRY PERSPECTIVES on page 102.

HydrocarbonProcessing.com reader response:

President/CEO Vice President Vice President, Production Business Finance Manager

John Royall Ron Higgins Sheryl Stone Pamela Harvey

Yes, we are prepared ................................................................................................ 47% Somewhat, we are considering new software ...........................................25% No, waiting on guidelines from regulators ................................................ 28%

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

Visit HydrocarbonProcessing.com to participate in future polls.

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Strategic Planning | Market Analysis and Trends | New Growth Opportunities

HPI MARKET DATA 2013 Your Guide to Profitable Planning in 2013 and Beyond Produced by the editorial staff of Hydrocarbon Processing, HPI Market Data 2013 is the industry’s most trusted source of forecast spending and trends analysis. The report features detailed information about expenditure and industry trends for the local and global HPI broken out by: Refining, Petrochemicals, Natural Gas/LNG, Health, Safety and Environment, HPI Economics, and Maintenance/Equipment.

Order online at GulfPub.com/2013HPI ub.com/2013HPI or call +1 (713) 520-4426

HydrocarbonProcessing.com

HPI MARKET DATA 2013 Now Available!

Get reliable, accurate information to drive your strategic decision making for 2013 and beyond. Hydrocarbon Processing’s editors forecast that total spending on capital, maintenance and operating budgets in the HPI is expected to exceed $230 billion in 2013. In HPI Market Data 2013, expert analysis of data provided by governments and private organizations offers exclusive information detailing where and how this spending will take place. With this report, you will have access to: • Capital, maintenance and operating spending broken out by geographical regions • Expanded editorial analysis of worldwide economic, social and political trends driving HPI activity across all sectors • An exploration of the changing markets and demand within the global HPI, with discussion of growing markets.

The 2013 Edition This year, hundreds of detailed tables and figures appear in HPI Market Data 2013. The book contains 100 pages of data, tables, figures and editorial analysis—the largest forecast to date. See why HPI leaders, executives and decision-makers throughout the world have come to rely upon this analysis and data for valuable strategizing information.

Order Today Order your copy of HPI Market Data 2013 today and make profitable planning a part of your company or organization’s success in 2013 and beyond.

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“

The hydrocarbon processing industry (HPI) is a global business with a 100-year history. Much has changed since the early days. The world order for the global HPI is changing; demand is shifting to emerging nations. Available hydrocarbon resources are likewise shifting. New discoveries of shale gas and tight oil are changing resource supplies and pricing. Flexibility to adapt to changing markets and economic conditions will separate the top-performing companies from the followers.

These are just some of the events that are reshaping the global HPI in 2013 and beyond.

”

– Stephany Romanow, Editor, Hydrocarbon Processing

| Brief Marathon Petroleum Corp. plans to purchase BP’s Texas City refinery and related assets Marathon Petroleum Corp. (MPC) has signed a definitive agreement to purchase BP’s 451,000-bpcd Texas City, Texas, refinery and associated natural gas liquids pipelines and four marketing terminals in the southeastern US. The base purchase price is $598 million, plus inventories estimated at $1.2 billion. The agreement also contains an earnout provision under which MPC could pay up to an additional $700 million over six years, subject to certain conditions. The acquisition is expected to be funded with cash on hand, and is anticipated to close early in 2013, subject to customary closing conditions and regulatory approvals. The BP Texas City refinery is one of the largest and most complex in the US, with a Nelson complexity index of 15.3. The refinery operates a 63,000-bpcd hydrocracker and a 29,700-bpcd coking unit. The facility is strategically positioned to provide products throughout the US Gulf Coast, Midwest and Southeast, as well as into export markets. The refinery has the flexibility to process a wide range of crude oils, and it has access to price-advantaged mid-continent and Canadian crudes.

With the Texas City refinery, MPC will operate 1.64 million bpcd of refining capacity.

BILLY THINNES, TECHNICAL EDITOR / Billy.Thinnes@HydrocarbonProcessing.com

Brief The European Commission intends to limit the use of biofuels derived from food crops to 5% for transport

fuel. This would be a substantial change to its present biofuels policy. According to the EU’s climate-change and energy commissioners, Europe wants to cap the share of energy in the transport sector from food crop-based biofuels at current levels.

The proposal, a draft of which was reported by Dow Jones Newswires, clashes with the target of having 10% of the energy used in transport coming from renewable sources by 2020. This goal was set by the EU three years ago because food crop-based biofuels account for most biofuels available in volumes at the moment. New types of alternative fuels are being developed, but they are mostly at the laboratory stage. At the same time, biofuels are expected to be the main renewable energy source used in transport in 2020.

State-owned oil company Pemex is working with Mexico’s federal government to manage limited

natural gas supplies in the wake of a September 18 plant explosion near the northern border city of Reynosa that killed 30 workers. Pemex executives plan to increase gas imports from the US to maximum levels. The company is also working on a bypass that will reestablish gas flows from the Burgos fields to the central part of the country. The facility damaged by the blast is a new plant. The cause of the accident is still under investigation, although Pemex said it has no evidence to believe the explosion was intentional. The explosion initially halted production of about 800 million cfpd of natural gas from the Burgos fields.

ExxonMobil will spend more than $200 million to expand its Baton Rouge chemical and lubricants plants

in Louisiana to raise capacity for synthetic lubricant base stocks manufacturing and lubricants blending, packaging and storage.

The expansion will increase ExxonMobil’s global capacity of synthetic esters and alkylated naphthalene by more than 25% to meet demand for high-performance lubricants. The project will include construction of a blending center for synthetic aviation oil at the company’s lubricant blending plant in Port Allen, Louisiana. The new facilities in Baton Rouge will replace existing base stock manufacturing and aviation lubricants blending, packaging and storage operations in Edison, New Jersey, which will cease production when the new Louisiana facilities begin operation.

INEOS Europe has completed supply and infrastructure agreements that will secure a significant volume of

ethane feedstock from the US for use by European cracker complexes. The company has agreed to a long-term deal with Range Resources for the lifting of ethane from the Marcus Hook facility in Pennsylvania, starting in 2015. Formerly

a Sunoco refinery, the Marcus Hook facility is being used as a terminal operated by Sunoco Logistics Partners. The agreement is effective upon US Federal Energy Regulatory Commission (FERC) approval of the Mariner East project.

INEOS also finalized pipeline transportation services and terminal services agreements for the shipping of ethane from western Pennsylvania to Marcus Hook with subsidiaries of Sunoco. The agreements will be valid for 15 years, and it will provide INEOS Olefins & Polymers Europe with significant supply options for the future, according to the company. It is expected that, when completed, the Mariner East project will transport approximately 70,000 bpd of ethane and propane from Houston, Pennsylvania, to the Marcus Hook terminal facilities.

Westlake Chemical will do planned maintenance and expand its Petro 2 ethylene unit in Lake Charles,

Louisiana, in the first quarter of 2013. The company earlier said the turnaround would occur in the 2012 fourth quarter.

This expansion will increase ethane-based ethylene capacity from 230 million lb/y to 240 million lb/y, targeting an ethylene integration strategy, company officials said. The unit is expected to be down approximately 50 days while the work is completed.

Valero Energy has restarted ethanol plants in Albion, Nebraska, and Linden, Indiana, amid improving

margins. Valero idled operations in Nebraska and Indiana in June 2012, citing unprofitable returns. Each plant has the capacity to produce 120 million gpy of ethanol. A Valero spokesperson indicated that ethanol margins improved to the point where it became feasible to operate the plants again. A total of 120 employees work at the two plants. All of them remained on the payroll and at their jobs during the shutdown.

Valero is now operating all 10 of its US ethanol plants, with a total capacity to produce 1.2 billion gpy.

BP has agreed to sell all of its Malaysian interests in purified terephthalic acid (PTA) production to India’s

Reliance Industries, including the 610,000-tpy plant in Kuantan on Malaysia’s east coast. Reliance has agreed to purchase BP’s interest in the plant for $230 million in cash. Both parties anticipate completing the transaction in 2012. A BP executive said it made sense to sell this facility to Reliance because the company is already a significant feedstock supplier to the Kuantan plant. All plant staff are expected to transfer to the new owners under equivalent terms and conditions, according to officials involved with the sale. BP’s acetic acid manufacturing and marketing business in Malaysia is unaffected by this sale.

BP’s net global PTA capacity is 7.5 million tpy from eight sites. BP’s PTA facility at Zhuhai, China, which is now under expansion, will add 1.25 million tpy by 2014, making it one of the world’s largest PTA manufacturing sites.

Hydrocarbon Processing | NOVEMBER 2012 9

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Š Copyright 2012. All rights reserved. Invensys, the Invensys logo, Avantis, Eurotherm, Foxboro, IMServ, InFusion, Skelta, SimSci-Esscor, Triconex and Wonderware are trademarks of Invensys plc, its subsidiaries or affiliates. All other brands and product names may be trademarks of their respective owners.

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BILLY THINNES, TECHNICAL EDITOR / Billy.Thinnes@HydrocarbonProcessing.com

Impact

Investing in growth. The highest-priority investment areas

are new products or services (35%) and the acquisition of a business (33%), according to the survey.

US executives (42% products; 45% acquisitions) indicate that they plan to be much more aggressive investing in these respective areas than their Asia-Pacific (26% products; 23% acquisitions) and European (36% products; 32% acquisitions) peers, KPMG said.

“Overall, chemical executives are telling us that they intend to put their money to work and boost investment in key areas,” Mr. Shannon said. “With the struggling global economy, organic growth is a challenge, and input prices continue to impact production costs. All of these factors set the stage for aggressive merger and acquisition (M&A) and product development strategies as companies look to gain an edge.”

Ninety percent of executives indicate that their companies are likely to be involved in a merger or an acquisition in the next two years, which is up from 83% in KPMG’s 2011 survey.

100 Projections for greatest sales volumes, %

Chemical industry executives plan to soon use the significant cash on their balance sheets to pursue strategic acquisitions and new product developments to spur company growth, according to a survey released by US advisory firm KPMG. The growth comes despite escalating input costs, stiffer competition, and a struggling global economy, KPMG said.

In the survey of 156 senior-level chemical executives in the US, Europe and Asia-Pacific, 72% of industry executives indicate that their companies have significant cash on the balance sheet—up from 70% in KPMG’s 2011 survey.

More than half (51%) say their companies’ cash positions have improved from last year.

“Despite economic headwinds, the chemicals sector has experienced some positive momentum in the past year,” said Mike Shannon, global leader of KPMG’s chemicals and performance technologies practice. “The improved cash positions at many of these companies will allow them to be more aggressive to drive growth and innovation, both organically and inorganically.”

Among executives, 63% plan to increase capital spending over the next year, including 81% of respondents in the AsiaPacific region. This compares with 48% in the US and 58% in Europe.

Most of the executives polled looked to 2013 or 2014 for a peak in chemical sales volume (FIG. 1). However, this subject indicated a developing and sustained trend, which was that US executives were consistently more pessimistic across the board than their counterparts in the rest of the world. Many of the US executives expected it to take at least three years before their companies could return to previous sales volumes.

Once again, respondents in the US were most bullish on being buyers (48%), while European respondents were the most likely sellers (52%).

Executives also identified technology (29%) and geographic expansion (27%) as significant areas of investment for their companies, according to the survey.

Respondents in Asia-Pacific had the highest expectations for investment in technology (42%), and European executives (36%) plan to increase investment in geographic expansion the most.

As for where they intend to deploy that capital over the next two years, global chemical executives cite China, the US and

80

32%

10% 6%

19%

28% 45%

57% 11%

60

27%

35%

29%

28% 28%

10%

11% 22%

20%

18% 40

13%

39%

34%

34%

21%

49%

35%

31%

13% 3% 2011

16% 4% 2012 2011 Asia-Pacific

8% 2012

2011

20

21%

0

9%

13%

10%

2012

2011

2012

US

2011

Europe

2012

2013

2014

11% Total

2015 and beyond

Source: KPMG International 2012

FIG. 1. Projections for greatest sales volumes; survey responses from 2011 to 2015 and beyond.

100 Modest expectations for the economy, %

Chemical industry execs look to the future

15%

6% 26% 2% 14%

26%

18%

80

8% 26%

3% 19% 2%

6%

17% 51%

4% 2% 16% 1% 19% 21%

60 40

56%

42%

60%

42%

54%

46%

58%

20

41% 17%

12%

0 2012

8%

15%

20%

5% 2011

2012 2011 2012 2011 Europe Asia-Pacific Total Significantly improved Moderately improved About the same Moderately worse Significantly worse 2011

US

22% 2012

Source: KPMG International 2012

FIG. 2. Chemical company executives were asked, “A year from now, what are your expectations for the economy?” Their answers from 2011 and 2012 are presented in Fig. 1.

Hydrocarbon Processing | NOVEMBER 2012 11

Impact Europe as the geographic regions that will be the focus of investment.

However, when analyzing individual regional responses, US and European executives showed a much stronger preference for domestic investment. China remained a favored investment location for executives in all three regions, according to the survey.

Fragile economic fundamentals. Despite the strong focus

on growth and expansion, the macroeconomic environment Expectations for hiring US

Europe

Asia-Pacific

Total

08% 09% 13% 26% 21% 09% 06% 02% 04% 02%

00% 12% 34% 12% 24% 08% 04% 04% 02% 00%

09% 28% 17% 23% 13% 04% 02% 02% 00% 02%

06% 17% 21% 21% 19% 07% 03% 03% 02% 01%

Increase by more than 10% Increase by 7% to 10% Increase by 4% to 6% Increase by 1% to 3% About the same Decrease by 1% to 3% Decrease by 4% to 6% Decrease by 7% to 10% Decrease by more than 10% Not sure/don't know

Source: KPMG International 2012

FIG. 3. Expectations for hiring: Results of how the executives expected companies’ headcounts to change in one year.

is more of a worry for executives than at this time last year, KPMG reported.

“Executives in Europe and the US are more concerned about the state of the global economy (FIG. 2) than their counterparts in Asia,” said Paul Harnick, KPMG’s global chief operating officer for the chemicals and performance technologies practice.

“Balancing potential global economic risks with the need to expand into new products and markets to capture growth will be key to success.”

Overall, 45% of respondents worldwide stated that the global economy would improve moderately in 2013. Surprisingly, the greatest optimism was in Europe, with 54% of the respondents looking forward to a moderate improvement.

Less optimistic views on revenue and hiring. Among

executives surveyed, 68% expect revenue to increase next year—down from 85% in the 2011 survey. Executives in the US were the most bullish in their revenue projections, with 73% expecting revenue to increase next year, down slightly from 77% in 2011.

Expectations for increased revenue among the Asian-Pacific and European executives decreased substantially in the 2012 survey—Asia-Pacific (69% vs. 96% in 2011) and Europe (60% vs. 82% in 2011).

“Ongoing business challenges, such as the prolonged economic crisis, volatile input prices and increased pricing pressures are dampening executives’ expectations,” Mr. Harnick said.

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Impact Executives also appear less optimistic on hiring, with 65% saying headcount will increase next year (FIG. 3), down from 73% in 2011. Asia-Pacific was most bullish, with 77% expecting to add headcount, followed by Europe at 58% and the US at 56%. In the US, 21% of executives actually expect to decrease headcount in the next year, up from 14% in 2011.

Energy firms must acknowledge cyber security as more than an IT problem Energy firms have spent vast sums on the security of their information systems, but they must reorient from a reactive, tactical posture regarding intrusions and attacks to a more strategic, holistic view that expands beyond the categorization of the issue as an IT problem, according to a new paper from Rice University’s Baker Institute for Public Policy.

The paper, “Cyber Security Issues and Policy Options for the US Energy Industry,” investigates how energy companies involved in the production and delivery of hydrocarbons, as well as companies that generate and transmit electricity, face new risks posed by malicious software. These risks can affect the continuity of operations, the capacity to deliver products and services, and the ability to protect investments (particularly in R&D) from theft or unauthorized disclosure.

The paper comes against the backdrop of the US Congress’ failure this summer to pass significant cyber-security legislation for the protection of commercial and government information technology infrastructure.

“For the energy industry, cyber security is not just a technology problem, but, rather, is one that includes the larger dynamics of information and operations,” said Christopher Bronk, the paper’s principal author and a Baker Institute fellow in information technology policy. “How public policy can form components of the response to cyber-security issues pertaining to the energy industry and the critical infrastructure that it builds, operates and maintains requires considering both the complexity of the issue and the nuance in potential policy prescriptions.”

The paper details examples of major oil and gas companies that have suffered a significant data breach or disruption of IT service, the latest being Saudi Aramco. In August, Saudi Aramco saw as many as 30,000 computers on the company’s network compromised by a malicious piece of “malware,” possibly the one labeled “Shamoon” by the computer malware community.

“The issues of cyber espionage and true cyber attacks—the ability to achieve kinetic outcomes by manipulation of computer systems—represent significant challenges for the energy industry, the United States government and the international community,” Mr. Bronk said.

Mr. Bronk hosted a range of international cyber security experts from business, government and academia at the Baker Institute in September to discuss the latest information on how to detect, defend against and respond to emerging cyber threats.

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ADRIENNE BLUME, PROCESS EDITOR Adrienne.Blume@HydrocarbonProcessing.com

Innovations Neste Oil makes progress on microbial oil plant Finland’s Neste Oil recently completed the first phase of a pilot plant for producing microbial oil. The €8 million plant is expected to be completed in the second half of 2012. Commercial-scale production is anticipated by 2015, at the earliest.

The first phase will enable the growth of oil-producing microorganisms, and the following phases will concentrate on raw material pretreatment and oil recovery. The goal is to develop the technology so that it is capable of yielding commercial volumes of sustainable, efficient microbial oil for use as a feedstock for NExBTL renewable diesel.

The technology uses yeast and fungi in bioreactors to efficiently convert sugars from waste and residues into oil. A wide range of different materials can be used, such as straw and sidestreams from the pulp and paper industry, which makes feedstock optimization possible.

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Honeywell enhances cyber defense software Honeywell has announced a certified application control and whitelisting solution to help prevent viruses and malware from attacking its Experion Process Knowledge System (PKS) control system platform. Whitelisting (FIG. 1) protects from unwanted intrusions by permitting only applications and executable files that are considered safe and on an “approved list” to run, while blocking everything else.

Whitelisting solutions have been deployed in business IT environments for years, but their introduction into automation control systems is relatively new.

Two major Honeywell control systems customers have been extensively piloting the solution through rigorous testing in specialized, mission-critical environments and providing feedback on their experiences.

FIG. 1. Honeywell’s whitelisting solution circle chart.

The solution is the result of an agreement between Honeywell Process Solutions and technology partner Bit9. Additionally, Honeywell’s Industrial IT Solutions offers a full spectrum of indepth defense solutions and services to protect automation manufacturers.

Select 2 at www.HydrocarbonProcessing.com/RS

Netherlocks offers online valve testing Netherlocks’s Fail Action Integrity Test Handling (FAITH) Partial Stroke Test system (FIG. 2) is now able to remotely conduct online tests of emergency shutdown (ESD) and high-integrity pressure protection system (HIPPS) valves. Operators can reduce degradation and ensure the proper operation of emergency valves from the safety of the control room.

The FAITH system uses a simple design for reliable operation, and it integrates into a valve’s static and dynamic couplings. To eliminate the risk of overshoot or process interruption, the system’s mechanical steel blocking pins ensure that valves cannot be operated past the preset test angle. With the new remote testing feature, operators can conduct and monitor partial stroke tests of emergency valves without the need to manually access the FAITH system.

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FIG. 2. The FAITH system conducts online tests without process interruptions.

AbTech wins innovator award AbTech Holdings Inc., a developer and manufacturer of technologies addressing issues of water pollution and contamination, was recently honored as the 2012 Technology Innovator at the Third Annual World Shale Oil and Gas Summit in Houston, Texas. The award was presented in partnership with the American Gas Association and International Gas Union at the 2012 summit, held September 18–21.

AbTech’s produced water pretreatment systems combine available technologies with systems engineering and AbTech’s Smart Sponge de-oiling technology to remove oil and other contaminants from frac and produced water at natural gas production sites.

Hydrocarbon Processing | NOVEMBER 2012 15

120,000+ rental items 173 suppliers largest rental eet in the industry

on our watch Total Safety pioneered the In-Plant Service Center (IPSC) concept in response to customer safety needs. An IPSC allows for a wide range of onsite safety services and equipment backed by trained technicians at your disposal— day or night. Enhance the safety of workers in your facility with a Total Safety IPSC.

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Innovations The pretreatment system employs a three-stage process for oil recovery, deoiling and VOC air stripping, offering natural gas producers a complete solution that works with and protects any downstream produced water treatment systems being employed in the field.

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Servomex installs combustion analysis for Shell

process monitoring “hot” wavelength.

With two LaserSP analyzers installed in-situ on each ethylene furnace for the measurement of 0%–10% O2 and 0 ppm to 1,000 ppm CO, respectively, the combined solution is helping Shell Netherlands Chemie BV optimize process efficiency by reducing fuel consumption and process emissions, as well as by reducing installation and operational costs.

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Software upgrade optimizes crude oil buying Aspen Technology Inc. recently introduced a new assay management functionality in Aspen PIMS software that optimizes crude oil feedstock purchasing decisions and increases profitability.

Aspen PIMS is part of the aspenONE Petroleum Supply Chain software suite.

Traditionally, refinery planners main-

Servomex recently installed a solution for combustion analysis on ethylene cracker furnaces at Shell Netherlands Chemie BV. The new flue gas analysis solution, which coincides with a furnace refurbishment program, enables optimization of the combustion control process, leading to improved fuel efficiency and reduced CO emissions.

SERVOTOUGH LaserSP 2900 crossstack analyzers (FIG. 3) were installed across the 13-meter radiant sections of the ethylene cracker furnaces to monitor both O2 and CO within the flue gas. The LaserSP employs the Tuneable Diode Laser Spectroscopy (TDLS) technique to make a path-averaged measurement of the process gas concentrations close to the burners, enabling rapid process optimization.

To protect the analyzer optics, it is common practice to flow purge gas over the windows of TDLS in-situ analyzers.

In flue gas measurements, it has been necessary to employ dry N2 as the window purge gas as opposed to instrument air.

However, in partnership with Shell Moerdijk, the infrared scan range of the LaserSP was extended to include additional absorption lines that only appear at temperatures greater than 600°C. By using one of these “hot lines” to monitor the process O2 , it is possible to use instrument air as the window purge gas, since the O2 in the instrument air, being colder than 600°C, is no longer detected at the

FIG. 3. The SERVOTOUGH LaserSP 2900 cross-stack analyzer.

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17

Innovations tain their own assay libraries and use disparate technologies, which can lead to inaccurate and inefficient planning. The new functionality from Aspen Technology now allows planners to add, modify and recut assays directly in Aspen PIMS, thereby enabling them to quickly evaluate more scenarios with greater accuracy.

Aspen PIMS’ assay management capabilities allow users to import assay data from external sources and more ef-

ficiently manage their crude feedstocks.

Guided, automated workflows increase productivity, while alerts notify planners for the next step in the process to shorten their learning curve.

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Portable analyzer aids in gas quality measurement In response to requests from customers, Michell Instruments has developed

COMPLIANCE! Leak prevention, not detection Meet today’s low leakage regulatory requirements with Chesterton® 1622 low emission valve packing. 1622 is an easy-to-install, single spool block valve packing designed to reduce fugitive emissions to below 100 ppm.

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a transportable version of its hydrocarbon dewpoint analyzer (FIG. 4). The key function of the new version is to enable engineers to provide a fast response for investigations into the quality of natural gas, wherever it is needed. It is also certified for use in hazardous areas.

The Transportable Condumax II measures hydrocarbon and water dewpoint— key indicators of the quality of natural gas—in the same way and to the same accuracy as the online version. The analyzer is fitted into a robust transport case with a rudimentary sampling system suitable for performing supervised measurement sequences. The ease of use reduces the reaction time of test measurements, as well as the cost.

A typical application for the Transportable Condumax II is an investigation into the performance of hydrocarbon reduction processing by natural gas producers.

Gas pipeline transmission operators usually have online hydrocarbon dewpoint analyzers installed at the entry and delivery points of their pipeline network. However, the analyzer allows for quality checks to be made at any point within the pipeline.

Additionally, electricity companies that operate gas turbines need to be sure of the superheat margin between the dewpoint and delivery temperature of the fuel gas to avoid damage caused by liquid condensate in the gas and to avoid environmental levies on emissions. The Transportable Condumax II enables checks of the hydrocarbon and water dewpoint of the natural gas entering the fuel gas system.

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Flame detector obtains certification The Multi-Spectrum Infrared (MSIR) FL4000H flame detector from General

Certified Low Leaking Valve Packing Technology Independently emissions tested to API 622 and Chevron standards Fire safe, passed API 607 Fire Test

Achieve your low emissions goals—choose Chesterton.

Visit us at Valve World Expo 2012 in Düsseldorf.

Booth: Hall 3 G29 22034 ©A.W. Chesterton Company, 2012. All rights reserved.

18

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FIG. 4. Michell Instruments’ transportable hydrocarbon dewpoint analyzer.

TWO GREAT COMPANIES. ONE BRIGHT FUTURE. How do you create a global company built for the future? By combining two powerful histories in pursuit of a bold vision—to help companies around the world contribute to healthier, safer environments.

Building on the achievements of Pentair and Tyco’s Flow Control businesses, comprised of Valves & Controls, Thermal Controls and Water & Environmental Systems, the new Pentair delivers exceptional depth and expertise in filtration and processing, flow management, equipment protection and thermal management.

From water to power From energy to construction From food service to residential We’re 30,000 employees strong, combining inventive thinking with disciplined execution to deploy solutions that help better manage and utilize precious resources and ensure operational success for our customers worldwide. Pentair stands ready to solve a full range of residential, commercial, municipal and industrial needs.

PENTAIR.COM Select 64 at www.HydrocarbonProcessing.com/RS

Innovations Monitors (FIG. 5) has been certified by the Building Research Establishment Group (BRE Group) to the EN 54-10 standard of the European Construction Products Directive (CPD), a standard recognized worldwide to represent the highest levels of quality for flame-detection devices.

Certification to the EN 54-10 standard of the European CPD assures General Monitors’ customers that the FL4000H flame detector has undergone

rigorous testing and has been determined to meet the highest quality standards. It also makes the FL4000H eligible for use in countries that conform to European safety standards.

Featuring a next-generation MSIR sensor that incorporates neural network technology, the FL4000H provides reliable flame monitoring with false-alarm immunity, a wide field of view, and one of the longest detection ranges available.

The flame detector’s algorithm is based on artificial neural networks that are mathematical models that correlate certain patterns of infrared radiation with the incidence of flame. The optical IR sensor array and the neural network function together as an adaptive and intuitive decision-making mechanism, resulting in a reliable scheme for discrimination between actual flames and false-alarm sources.

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Paralloy to cut petrochemical furnace costs Doncasters Paralloy is now offering Paralloy H39WM+, developed to increase the performance of petrochemical furnaces while simultaneously reducing furnace operating costs. Stronger and more ductile than its predecessor, Paralloy H39WM+ features enhanced creep strength and carburization resistance, meeting stringent criteria for modern steam reforming furnaces and pyrolysis cracking coils.

Paralloy H39WM+’s properties enable Doncasters Paralloy to offer the tubes with thinner walls, which reduces thermal gradient and, therefore, thermal stresses within the walls on startups and shutdowns. Thinner walls also give improvement in the rate of heat transfer and provide energy savings.

Increases in tube skin temperatures and tube operating pressures offer reformer designers a number of advantages, including the opportunity to explore new chemical reactions in the reformer, the chance to increase the yields of some chemical products, and an increase in overall productivity.

Help is here... cold startup, non-toxic, biodegradable, Paratherm MR heat transfer fluid will make your system safe and more productive. ®

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Start up at -37° F below zero. This is a non-aromatic/low odor (not noxious), pure and colorless, inherently biodegradable composition that reduces worker exposure and environmental issues. Designed as a benzene-free alternative for gas-processing applications it’s easier to handle and reduces maintenance.

You may want to check/test your system with a Fluid Analysis. Great for eliminating any downside risk or call and talk with one of our technical specialists/engineers over the phone about your particular application. Contact us today for real help right away.

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®

®

FIG. 5. General Monitors’ Multi-Spectrum Infrared (MSIR) FL4000H flame detector.

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Metso is a single source for all your process control needs, from automation systems to intelligent flow control solutions that are proven in the toughest conditions.

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HELEN MECHE, ASSOCIATE EDITOR Helen.Meche@HydrocarbonProcessing.com

Construction North America Sunoco Inc., and The Carlyle Group, L.P., have completed the formation of Philadelphia Energy Solutions, a joint venture ( JV) that will operate the Philadelphia refinery. The refinery processes 330,000 bpd of crude oil into various refined products.

Under JV agreement terms, The Carlyle Group will hold the controlling interest and will oversee the refinery and the JV’s day-to-day operations. In exchange for contributing its refinery assets to the JV, Sunoco retained a 33% nonoperating minority interest.

Specialty chemicals group LANXESS has opened its first production plant for high-tech plastics in the US. With the new facility in Gastonia, North Carolina, the company will reportedly help to meet the growing demand for premium, lightweight plastics.

The company has invested $20 million in this new Gastonia plant, and is creating up to 45 new jobs. The plant will initially operate with a capacity of 20,000 metric tpy.

In the new compounding plant, basic polymers, such as polyamide and polybutylene terephthalate, are mixed and refined with special additives and glass fibers, according to customer needs, to produce Durethan and Pocan brands.

Bechtel that provides technology licensing and process consulting services to the oil and gas industry. BHTS has licensed various aspects of the ThruPlus coking technology for five projects since acquiring it from ConocoPhilips in 2011.

A subsidiary of Foster Wheeler AG’s Global Engineering and Construction Group, in consortium with Hyundai Engineering and Construction Co., Ltd. (HDEC), has a contract from Petróleos de Venezuela, S.A. (PDVSA) for Phase I (hydroskimming section) of the new Batalla Santa Ines refinery to be built in Barinas, Venezuela.

Foster Wheeler’s scope of work includes early detailed engineering design and the delivery of an open-book estimate for the crude distillation unit, storage and blending unit, and fuel-distribution plant.

The main release of the detailed engineering design work is expected to be booked at a later date, upon release by the client.

Europe

South America

Alfa Laval has an order to supply its compact heat exchangers to a petrochemical company in Western Europe.

The order is valued at approximately SEK 70 million. Delivery of the exchangers is scheduled to start in 2013 and be finalized during 2014. The Alfa Laval compact heat exchangers will be installed in a petrochemical plant where they will be used to condense process vapors in the production of plastics.

Bechtel has a license agreement with Pemex Refinación, the refining subsidiary of Mexican state oil company Pemex, for the process design of a delayed coking unit (DCU) complex for the new Tula refinery project in Hidalgo, Mexico.

The DCU complex will use Bechtel’s ThruPlus coking technology, a proprietary process for upgrading heavy oil into high-value, light hydrocarbon liquids.

This technology is managed by Bechtel Hydrocarbon Technology Solutions, Inc. (BHTS), a subsidiary of

A subsidiary of Foster Wheeler AG’s Global Engineering and Construction Group has a contract from Zeeland Refinery N.V. (a Total and LUKOIL jointventure company) for engineering, procurement assistance and construction management assistance for the upgrade of the distillate hydrocracker at the Zeeland refinery in Vlissingen, The Netherlands.

The project’s objective is to maximize the throughput by debottlenecking the unit’s reaction and fractionation sections.

Foster Wheeler’s scope of work is expected to be completed by June 2014.

Eni has met with local and national institutions, as well as trade unions, to explain the “green refinery” process that will lead to the Venice refinery’s conversion into a biorefinery to produce high-quality biofuels. The project, which involves an estimated investment of approximately €100 million, is said to be the first in the world to convert a conventional refinery into a biorefinery, and is based on Ecofining technology developed and patented by Eni. The “green refinery” process will initially convert the existing facilities. This will be launched in the second quarter of 2013 and be completed by the end of that year.

Until the changeover starts, the refinery will continue to produce using traditional methods. Biofuel production will start January 2014 and will grow progressively as the new facilities start operating.

The new facilities for this project will be completed in the first half of 2015.

The new green plant will maintain the Venice site in an economically sustainable industrial operation over the long term, with low environmental impact.

The activities of the “green refinery” will be associated with construction of a new logistics center.

Jacobs Engineering Group Inc. has a contract to provide construction manTREND ANALYSIS FORECASTING Hydrocarbon Processing maintains an extensive database of historical HPI project information.

The Construction Boxscore Database is a 45-year compilation of projects by type, operating company, licensor, engineering/constructor, location, etc. Many companies use the historical data for trending or sales forecasting. The historical information is available in commadelimited or Excel® and can be custom sorted to suit your needs. The cost depends on the size and complexity of the sort requested. You can focus on a narrow request, such as the history of a particular type of project, or you can obtain the entire 45-year Boxscore database or portions thereof. Simply send a clear description of the data needed and receive a prompt cost quotation.

Contact Lee Nichols at 713-525-4626 or Lee.Nichols@GulfPub.com

Hydrocarbon Processing | NOVEMBER 2012 23

Construction agement services for Lotte Chemical UK Ltd.’s new polyethylene terephthalate (PET) plant to be built at the Wilton International Site in Redcar, Cleveland, UK. Officials did not disclose the contract value, but noted that the contract is scheduled for 18 months.

The new 200,000-metric-tpy PET plant (LC1 project) is to be located on an integrated pure terephthalic acid (PTA) and PET site, adjacent to Lotte’s existing

PET plant. The addition of the new line will fortify the capacity of Lotte Chemical UK’s existing T8 facility and support its transition into a wider range of PET products, including resins incorporating postconsumer recycled PET. A subsidiary of Foster Wheeler AG’s Global Engineering and Construction Group has a contract from JSC Gazprom Neftekhim Salavat for the engineering and

Find Leaks And Take Control Without Delay FLIR GF320 optical gas imaging cameras s give you the power to see and locate invisible gas leaks faster and more reliably bly than traditional “sniffer” detectors.

Scan large areas quickly and pinpoint escaping gas in real time so you can get safety hazards under control immediately, stop the flow of lost revenues, and avoid costly fines.

Visit www.FLIR.com/HydroGF to download a free guide to using IR for gas detection, or call 866.477.3687 to schedule a demo.

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24

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material supply of a new double-cell Terrace Wall steam reformer heater and air preheating system to be built at the Salavat refinery in the Republic of Bashkortostan, Russia.

The steam reformer will be part of a hydrogen production unit being built by Gazprom Neftekhim Salavat. The plant is designed to produce up to 27,500 Nm3/hr of hydrogen. It is based on Foster Wheeler’s hydrogen technology and process design package. This package was recently completed by Foster Wheeler.

Foster Wheeler’s scope of work for this award is expected to be completed in November 2013.

CB&I’s Lummus Technology business sector was selected as the license provider of a delayed coking unit (DCU) for the Grupa Lotos refinery in Gdansk, Poland. Once the coking technology is implemented, the Gdansk refinery will be able to process 2,400 metric tpd to 3,840 metric tpd of a blend of vacuum resid and ROSE pitch, depending on the season.

The Gdansk refinery is the second largest refinery in Poland.

The DCU will enable Grupa Lotos to economically increase refinery distillate yields and eliminate fuel-oil production by converting a mixture of vacuum resid and pitch from a solvent deasphalting unit. The new technology will help convert the bottom of the barrel to fuel gas, liquefied petroleum gas (LPG), naphtha and gasoils.

Lummus Technology is slated to provide the basic engineering, proprietary heater design, training and startup services.

Middle East Some of Maire Tecnimont S.p.A.’s subsidiaries have been awarded contracts totaling approximately €135 million for engineering, procurement and technology services.

In Egypt, its subsidiary, Tecnimont KT S.p.A. (TKT), has an engineering and procurement contract for the realization of some processing units for Egyptian Refinery Co.’s (ERC’s) new refinery in Mostorod, Egypt, near Cairo. The clients are a consortium between GS E&C, Mitsui & Co. Ltd., and Mitsui and Co. Plant Systems Ltd., a subsidiary of Mitsui & Co. The overall project amount is approximately €97 million. Completion is expected by the end of 2014. The project includes one 100,000-Nm3/hr hydrogen production unit; three sulfur-recovery

Construction units, with a capacity of 162.5 tpd each; one 325-tpd tail-gas treatment unit; and one 90-m3/hr amine processing unit.

The new units are part of ERC’s project involving construction of a refinery to produce fuels and other petroleum products, in line with the latest international environmental standards.

In addition, Maire Tecnimont S.p.A.’s subsidiaries, Tecnimont, Stamicarbon and TKT, have received a series of awards, located in Bangladesh, Russia, China and other countries, for licensing and engineering services totaling approximately €38 million.

A subsidiary of Foster Wheeler AG’s Global Engineering and Construction Group has a contract from Shell Global Solutions International B.V. to develop a basic engineering package (BEP) for a world-scale mono-ethylene glycol (MEG) facility at Ras Laffan, Qatar.

The MEG facility will be part of a new petrochemicals complex in Ras Laffan Industrial City being developed by a joint venture of Qatar Petroleum and Shell.

The two-train MEG facility, based on Shell’s OMEGA technology, is planned to produce 1.5 million tpy of MEG. Foster Wheeler was the front-end engineering and design, and engineering, procurement and construction management contractor for Shell’s OMEGAbased MEG plant on Jurong Island in Singapore, which opened in December 2009.

Asia-Pacfic Technip has two contracts, worth approximately €50 million in total, for the front-end engineering and design (FEED) services of two refineries in Kazakhstan. The scope involves the modernization of two out of three of the country’s existing refineries.

The first contract—for Pavlodar Oil Chemistry Refinery—is an upgrading project of the Pavlodar refinery, which is scheduled to be completed in the second semester of 2013. The second project is for Petrokazakhstan Oil Product and concerns the revamp of the Shymkent refinery, whose FEED documentation is scheduled to be completed by the end of 2013.

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Both projects aim to increase production capacity and conversion. They include new and revamp process units, as well as utilities and offsite facilities.

Technip’s operating center in Rome, Italy, will execute both contracts.

The MITC Consortium (consisting of MODEC, Inc., IHI Corp., Toyo Engineering Corp. and CB&I Nederland B.V.) has been awarded a contract

by PETRONAS for the front-end engineering and design (FEED) of a floating liquefied natural gas (FLNG) project on dual-FEED mode in Malaysia.

The FEED is for PETRONAS’ second FLNG unit. The FLNG is designed to produce 1.5 million tpy of LNG at offshore Sabah, Malaysia. The FEED includes the basic design of a natural-gas liquefaction system using a precooling system, purpose-designed hull, living quarters, mooring system, LNG storage tank and LNG offloading system, followed by an engineering, procurement, construction, installation and commissioning (EPCIC) cost estimate for the project. The FEED

Hydrocarbon Processing | NOVEMBER 2012 25

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MERICAT J Patented FIBER FILM technology and a proprietary treating solution sweeten mercaptans without the need for a solid bed media. The result is lower capital and operating costs, a higher on-stream factor, and a smaller plant footprint.

www.merichem.com Select 84 at www.HydrocarbonProcessing.com/RS

Construction and EPCIC cost estimate are expected to be completed by the middle of 2013.

The technology of UOP LLC, a Honeywell company, has been selected by Heilongjiang Anruijia Petrochemical Co. to help produce key ingredients for fuels, synthetic rubber and plastics in China.

Honeywell’s UOP C4 Oleflex process will be used to produce isobutylene, a key ingredient for fuels and synthetic rubber.

In addition, Honeywell’s UOP Butamer process will be used to produce normal butane, a feedstock used to produce ethylene, a building block for plastics.

The new units, expected to start up in 2014, will produce 180,000 metric tpy of isobutylene and 150,000 metric tpy of normal butane at Heilongjiang Anruijia Petrochemical Co.’s facility in Heilongjiang Province, China. This will reportedly be the first facility in China to dedicate a process unit for isobutylene production using Honeywell’s UOP C4 Oleflex process, and the first to license Honeywell’s UOP Butamer process to produce normal butane.

Honeywell’s UOP will also provide the engineering design, technology licensing, catalysts, adsorbents, equipment, staff training and technical service for the project.

Jacobs Engineering Group Inc. has a contract from PETRONAS to develop a basic engineering package for three sulfur-recovery units (SRUs). Officials did not disclose the contract value, but noted that the basic engineering services are being provided from Jacobs’ Leiden office in The Netherlands.

Jacobs is licensing its proprietary SUPERCLAUS technology to PETRONAS for the SRU project. Jacobs introduced the SUPERCLAUS technology in 1985; there are now over 200 licensed units in operation worldwide. The technology offers a number of performance features in areas such as reliability, sulfur-recovery levels, sulfur-emissions reduction and simple continuous operation. PETRONAS’ new three-train sulfur plant is part of the Refinery and Petrochemical Integrated Development (RAPID) project site in the state of Johor, Malaysia.

Through the RAPID site, PETRONAS is establishing an optimally configured, integrated refinery and petrochemical complex that focuses on producing high-val-

ue-added petrochemicals. This involves building a refinery to supply naphtha and to produce gasoline and diesel that meet European clean-fuels specifications. The petrochemical complex is designed and developed to produce ethylene and olefins that are used in downstream plants to produce petrochemical derivatives.

UOP LLC, a Honeywell company, has announced that China’s Jiutai Energy (Zhungeer) Co. Ltd. has licensed Honeywell’s UOP methanol-to-olefins (MTO) technology to convert methanol from coal into key plastics’ building blocks.

Honeywell’s UOP/Hydro MTO process converts methanol from gasified coal or natural gas to produce high yields of ethylene and propylene, building-block materials used to produce films, packaging, plastics and other petrochemicals.

The technology allows producers in countries such as China to tap abundant coal resources, rather than more expensive petroleum, to produce petrochemicals.

Jiutai Energy will produce 600,000 metric tpy of ethylene and propylene at its facility in Ordos City, Inner Mongolia, China. In addition to technology licensing, Honeywell’s UOP will provide basic engineering, catalysts, adsorbents, specialty equipment, technical services and training for the project, which is expected to start up in 2014.

The MTO process, jointly developed

by Honeywell’s UOP and INEOS, converts methanol from crude oil and noncrude oil sources such as coal or natural gas to ethylene and propylene. The process, based on proprietary UOP catalysts, is proven to provide high yields with minimal byproducts. MTO also offers flexibility in the quantity of propylene and ethylene produced, so producers can adjust plant designs to most effectively address market demands

Membrane Technology BORSIG offers membrane technology that stands for high quality, competence and reliability.

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Africa KBR was awarded a contract by Statoil Tanzania AS to perform prefront-end engineering and design (preFEED) studies for a prospective liquefied natural gas (LNG) facility in Tanzania, East Africa. The pre-FEED study is designed to help Statoil further assess the viability of developing an LNG facility to export natural gas from this East African region. The project is expected to be completed during 2013.

www.borsig.de BORSIG GmbH Phone: ++49 (30) 4301-01 Fax: ++49 (30) 4301-2236 E-mail: info@borsig.de Egellsstrasse 21, D-13507 Berlin/Germany

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CONSTRUCTION BOXSCORE UPDATE / ConstructionBoxscore.com COMPANY

CITY

PROJECT

Harbin Harbin Vadinar Vadinar / Gujarat Balongan

Butane Isobutylene Refinery Coker, Delayed

Johor Bahru

Bio-ethanol

Sulfur Recovery (2)

EX CAPACITY UNIT

COST STATUS YR CMPL LICENSOR

ENGINEERING

CONSTRUCTOR

Simon Carves / TCE Aker Solutions Mumbai / CB&I

UOP UOP Essar Essar

ASIA/PACIFIC China China India India

Heilongjiang Petrochem Heilongjiang Petrochem Essar Oil Ltd Essar Oil Ltd

Indonesia

Pertamina / Kuwait Pertroleum International JV GlycosBio Asia Sdn. Bhd. / Biotechnologies Inc

Malaysia

Refinery

EX TO

180 180 405 6

m-tpy m-tpy bpsd MMtpy

U U U C

2014 2014 2012 2012

9000

S

2014

30

U

2013

U

2012

Shell|Fluor

Fluor

C C

2012 2012

UOP UOP

Mustang / IAG Mustang / IAG

E C C

2014 2012 2012

F C

2013 2012

3400

U H

2016

None 1.5 MMtpy 6400 214 Mbpd 500

S E U

2013 2016

335 bpd 120 MMscfd

C C

2012 2012

300 bpd 10000 tpy

382

UOP UOP ABB Lummus Lummus Technology

SK Energy Toyo Engineering Corporation

Toyo Engineering Corporation

CANADA Alberta

OPTI Canada Inc

Saskatchewan Saskatchewan

Consumers Coop Refineries Consumers Coop Refineries

Fort McMurray, Long Lake Regina Regina

BASF BASF Conoco Phillips Co

Antwerp Ludwigshafen Cork

Butadiene Methanesulfonic Acid Wet Sulfuric Acid

None None 30 m-tpd

Linhares Santos

Gas to Chemicals FPSO

1 MMtpy 80 bpd

Barrancabermeja Aruba

Processing, Heavy Oil Refinery

Cracker, FCC (2) Crude Unit

620 LTPD EX EX

22 Mbpd 30 Mbpd

1500

EUROPE Belgium Germany Ireland

50

CB&I Haldor Topsøe

LATIN AMERICA Brazil Brazil Colombia Netherlands Antilles

Petrobras Teekay Petrojarl Production AS / Petrobras Ecopetrol Valero Energy Corp

RE

250 Mbpd 235 bpd

FW Siemens

Teekay Petrojarl Production AS

MIDDLE EAST Kuwait Qatar Turkey

Petrochemical Ind Co Kuwait Shell Royal Dutch / Qatar Petroleum Ras Laffan Socar / Turcas Enerji JV Izmir

PET Mono-Ethylene Glycol Refinery

TO

Axens

FW FW

UNITED STATES Pennsylvania Texas

Sunoco Inc West Texas Gas

Philadelphia Undisclosed

Refinery Cryogenic Gas Plant

10

Thomas Russell Co.

The above projects represent only a fraction of data updated monthly in the Construction Boxscore Database. For more information please go to www.ConstructionBoxscore.com or contact Lee Nichols at 713-525-4626 or Lee.Nichols@GulfPub.com.

28 NOVEMBER 2012 | HydrocarbonProcessing.com

Select 170 at www.HydrocarbonProcessing.com/RS

Select 102 at www.HydrocarbonProcessing.com/RS

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Reliability

HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR Heinz.Bloch@HydrocarbonProcessing.com

Closed-oil-mist systems and maintenance cost avoidance A recent Hydrocarbon Processing (HP) article conveyed an industry finding that dates back several decades: Oil mist successfully lubricates operating machinery, protects and preserves standby equipment, and provides superior lubrication to electric motors driving process pumps. In a follow-up communication, an HP reader had questions regarding these findings. He believed that closed-loop oil-mist systems would possibly: 1) require oil sampling and oil changes at times, 2) not protect or preserve standby equipment and 3) be of no use to drive motors. Under those conditions, he believed his facility would continue to depend on inferior grease lubrication. Some of this reader’s conclusions and beliefs are refuted by decades of highly satisfactory experience.

Oil sampling recommendations. In response to point No. 1,

a prudent practitioner of predictive maintenance (PdM) would occasionally sample the oil that has passed through the equipment bearings. We believe the coalesced bulk oil in a coalescercollector vessel, as shown in FIG. 1, should be sampled twice per year. Sampling the coalesced mist drawn from the bottom of an equipment-bearing housing is optional because the total bearing condition is best determined by widely available PdM devices.

These devices monitor vibration amplitude and frequency spectra. Still, with superior synthetic lubricants made cost-effective due to very low oil consumption and cooler running bearings, a five-year oil service life can be attained without difficulty.

Rely on ‘pump wisdom.’ In response to point No. 2, protective action on standby equipment is very important and has been fully proven since about 1965. In over 5,000 large plantwide oil-mist systems—including hundreds of closed systems and many open-air equipment storage yards—the oil mist envelops the antifriction bearings in a protective fog. Existing at a slightly higher-than-ambient pressure in bearing housings, oil mist keeps out ambient air typically contaminated by water vapor and airborne dust. Properly applied oil mist travels through the bearings and to the bearing housing drain port. Thus, the oil mist protects non-running or standby equipment. Without this preservation method, standby equipment is exposed to the risk of the lubrication oil being “wiped off ” due to vibration transmitted from the adjacent running equipment.

In addition, without this preservation method, corrosion of bearings in non-running equipment is a greater probability. The rate of corrosion is a function of ingress and egress of air (“breathing” action) of the affected bearing housings. This breathing action occurs only in unprotected bearing housings, and it is not possible in bearing housings filled with oil mist at about 1 psi over atmospheric pressure. Industry now has in ex-

FIG. 1. A small oil-mist console manages 20 pumps. It is shown on the left, and the return mist coalescer-collector vessel is on the right. Source: Lubrication Systems Co., a Division of Colfax Industries, Houston, Texas.

cess of four decades of experience with this protection method on many thousands of pumps and motors. In 1978, a user company commissioned 132 electric motors driving vertical pumps.

We were told that none of them had ever failed in 32 years.

Regarding No. 3, all motors with rolling-element bearings will benefit from dry-sump oil-mist applications. Thousands of motors have been lubricated in this manner for over 40 years. Many books and papers have been written about this subject. Inferior grease lubrication has been superseded by superior dry-sump oil-mist systems for decades. A recent book on pumps again shows how oil mist eliminates slinger rings, constant level lubricators, dessicant breathers and bulls-eye sight glasses.1 Oil mist safeguards against over-greased motor bearings and greatly reduces bearing failures. Closed-oil-mist systems are proven technology; they excel by further reducing lubricant consumption and protecting the environment.

1

LITERATURE CITED Bloch, H. P., Pump Wisdom: Problem Solving for Operators and Specialists, John Wiley & Sons, Hoboken, New Jersey, April 2011.

HEINZ P. BLOCH resides in Westminster, Colorado.

His professional career began in 1962 and included long-term assignments as Exxon Chemical’s regional machinery specialist for the US. He has authored over 520 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 the States of New Jersey and Texas.

Hydrocarbon Processing | NOVEMBER 2012 31

refinement redefined

clean fuel, turning “bottom of the barrel” into “top of the line.”

of other residue-upgrading technologies, turning the “bottom of the barrel” into more proven technology that processes low-quality residue streams like vacuum residue into

from every barrel.

For more information, visit www.uop.com/uniflex. © 2012 Honeywell International, Inc. All rights reserved.

Integration Strategies

PAUL MILLER, CONTRIBUTING EDITOR PMiller@arcweb.com

The energy water nexus Whether or not you subscribe to the global warming and “peak oil” arguments, it is clear to almost everyone in the industrial world that “business as usual” is not sustainable indefinitely. Fossil fuels are becoming harder and more expensive to extract. The nuclear option is being taken off the table in many countries. Wind- and solar-electricity generation are still not baseload solutions—they may never be. And many regions are already suffering some degree of water stress.

The World Business Council for Sustainable Development’s (WBSD’s) Vision 2050 Project explores the ways in which the approximately nine billion people are projected to be living in 2050 and thriving well by “living within the limits of the planet.” In other words, the study exposes what an acceptable standard of living “can be sustained with the available natural resources and without further harm to biodiversity, climate and other ecosystems.”

According to the project’s report, “All types of ingenuity will be needed over the next 40 years. Although distinct, the interconnectedness of issues such as water, food and energyrelationships that must be considered in an integrated and holistic way, with tradeoffs that must be understood and addressed.”

Global energy supply insufficient for future demands.

While it’s likely that, per capita, consumption of energy will decrease in developed economies, this will not be the case in developing economies. This is particularly true in China, India and Brazil; more energy will be required to sustain industrial development by developing nations.

According to Gerald Schotman, chief technology officer of Royal Dutch Shell, by 2050, global energy demand will double and could even triple from the 2000 level, if emerging economies follow historical development patterns. According to Mr. Schotman, even if renewable energy sources continue to grow at a promising rate, and future technological advances enable oil and gas to be extracted from remote and difficult locations, a large gap is likely to remain between demand and supply—“a gap as big as the total output of the energy industry in 2000.”

ExxonMobil’s forward-looking report, The Outlook for Energy: A View to 2040, predicts that global energy demand will be about 30% higher in 2040 compared to 2010. According to this report, while energy demand by Organization for Economic Co-operation and Development (OECD) countries will remain essentially flat, energy demand by non-OECD nations will grow nearly 60%.

Environment Programme Finance Initiative (UNEP FI) in conjunction with the Stockholm International Water Institute (SIWI), water scarcity currently affects many regions. “Without a significant reversal of economic and social trends, it will become more acute over time. Although water is considered a renewable resource, in many parts of the world, water resources have become so depleted or contaminated that they are unable to meet ever-increasing demands. The challenges are more acutely felt in developing countries.”

According to the UN report, this has become a major factor impeding both economic development and business operations. The challenges associated with water scarcity are emerging as a strategically important risk for global businesses and their financial backers.

Energy and water closely intertwined. At the macro level,

it’s clear that energy and water are closely intertwined. It takes a lot of water to explore, produce and refine fossil fuels and even more to generate electricity from fossil fuels. By some estimates, power generation accounts for approximately 40% of all water withdrawals in the US—almost all of which was ultimately returned to the source.

Conversely, due to the large, energy-intensive pumps involved and the energy-intensive nature of many of the treatment processes in use, it takes significant electricity to withdraw, treat and transport freshwater, wastewater, and— increasingly—both saltwater and reused water. According to one EPRI report, approximately 4% of the electricity generated in the US is used to pump and treat water.

To reduce present and future business risks and to help ensure business continuity, it is important for hydrocarbon processing plants to monitor, measure and manage their energy and water consumption independently, as well as to fully understand the often interactive relationships between the two. If organizations have not already started to do so, ARC Advisory Group recommends that they start putting in place and implementing initiatives on both the strategic and tactical levels to use both energy and water more efficiently and effectively.

PAUL MILLER is a senior editor/analyst at ARC Advisory Group and has 25 years of experience in the industrial automation industry. He has published numerous articles in industry trade publications.

Mr. Miller follows both the terminal automation and water/wastewater sectors for ARC.

Significant shortfall looms for freshwater. According to

a report on water challenges prepared by the United Nations Hydrocarbon Processing | NOVEMBER 2012 33

Turnaround Welding Services

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I’m proud to be the mascot for the workers at Turnaround Welding Services, because they are the best in the business. Why? It’s because they tackle a planned outing just like they tackle an emergency.

They put their hearts, their souls, their backs and their expertise to work and their reputations on the line…every day.

They don’t just do the big jobs, either. They handle jobs that may only take ten man-hours as well as the ones that require over 250,000 man-hours.

Another reason I’m proud to be with Turnaround Welding is that our guys aren’t spoiled brats. They are trained to perform multiple tasks. They might weld, fit and rig the same piece of equipment and not even ask for a helper to carry their leads.

They’re so good that they don’t have to brag––even though their weld reduction rate is low and their productivity is high. And their safety record, well, it’s about as good as it gets.

Yeah, these guys are good, all right! They deliver their services with the tenacity of a bulldog––and I know all about that.

1.225.686.7101 or visit www.turnaroundweldingservices.com Select 78 at www.HydrocarbonProcessing.com/RS

Engineering Case Histories

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

Case 71: Statistical visual data can be useful in troubleshooting—Part 1

Metrics matter. FIG. 1 shows one of the many clamping fixtures on the production line, which holds the casting for machining.

To analyze clamping forces for this application, a load cell was designed to replace the part in the assembly and measure the clamping force. The load cell was moved from fixture to fixture.

Periodically, a casting would be machined “out of round.” It was believed that the fixtures might be clamping too tightly or too loosely, thus causing the rejects.

The fixture is designed so that, when torque is applied via a hydraulic motor, as shown in FIG. 1, the part is clamped into place by screw action. A force, F, clamps the part securely in place. With too much clamping force, the part can distort and squeezed into an oval shape. When the grooving tool makes the groove, it is a true circle. When the part is “squeezed” too much, it becomes distorted when unclamped. Result: The part is rejected.

A known torque of 300 in.-lb was applied to each fixture, and the force measured on 215 fixtures. FIG. 2 shows the distribution of the measured parts’ quality from this study. A statistical analysis of the data determines the interaction of the many variables; however, one observation is obvious from FIG. 2—the clamping force varies too much from fixture to fixture. Since the force is directly related to the out of round of the groove, this condition directly contributed to the reject rate. The machining operation is designed for a 2,000-lb to 3,000-lb clamping force.

Root cause and solution. Other causes contributed to the rejection rate and poor quality of the parts. But the worn-out fixtures and poor calibration of the torque motors were the leading factors of poor quality and low production. Making those needed repairs reduced the reject rate by 70%.

Obviously, these manufacturing operations are not directly applicable to the hydrocarbon processing industry. However,

Part Torque

F Fixture

FIG. 1. Clamping fixture assembly.

80

Number of occurrences

I’ve spent many years troubleshooting equipment, along with investigative research. In research-statistical design, data analysis is frequently used when test information is available.

This article shows how very basic data analysis can be quite useful in troubleshooting.

Most specialists are knowledgeable about plotting histograms and the value obtainable from such graphs as represented by the distribution of collected data. Remember: “When looking for an answer, a good place to start is to follow the data.” In this case history, we will review a production line that machines a precision groove in a casting bore for automotive use. Hundreds of thousands of casting bores are machined annually, and the groove out of roundness must be maintained within ± 0.003 in. on the diameter since a seal fits within the groove.

60 40 20 0

0 to 1,000

1,100 to 2,100 to 3,100 to 2,000 3,000 4,000 Actual clamping force on part, lb

4,100 to 5,000

5,100 to 6,000

FIG. 2. Clamping force distribution results on manufacturing assembly.

specialists should understand that even basic plotting of data can provide valuable troubleshooting information. In this case, spread of the data represents a deviation from the norm. The troubleshooting process should then question what has caused such a spread.

Next month. In “Case 72: Statistical visual data can be use-

ful in troubleshooting—Part 2,” the example investigates how a simple analytical model could have been applied before any data is collected. This example illustrates the effect of friction and torque on the clamping force.

DR. TONY SOFRONAS, P.E., was worldwide lead mechanical engineer for ExxonMobil Chemicals before retiring. He now owns Engineered Products, which provides consulting and engineering seminars on machinery and pressure vessels. Dr. Sofronas has authored two engineering books and numerous technical articles on analytical methods. Early in his career, he worked for General Electric and Bendix, and has extensive knowledge of design and failure analysis for various types of equipment.

Hydrocarbon Processing | NOVEMBER 2012 35

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Viewpoint

SÜLEYMAN ÖZMEN Vice President, Refining and Chemical Licensing, Shell Global Solutions International BV, The Hague, The Netherlands

Age of turbulence: Charting a course for refiners toward a profitable future Having spent over 38 years in the petrochemical and refining industry developing and licensing technologies, I have witnessed profound changes in the business landscape. Perhaps because of that, people often ask for my views on the outlook for refiners. Will the volatility continue? Yes, I say. Will things get any easier? Not really, although those that exploit competitive advantages will naturally rise to the top. Does the industry have a longterm future? Absolutely.

Change is a constant. Of course, the

SÜLEYMAN ÖZMEN, Vice President, Refining and Chemical Licensing for Shell Global Solutions International BV. Few people exhibit as much passion for the refining industry or have as much downstream experience as Mr. Özmen. In recent years, he has become known for his “Three Pentagon Model,” which provides refiners with a road map for their investment plans. Mr. Özmen also packs in over 38 years of sector experience, along with numerous qualifications, patents and technical papers.

During his career, he has worked through the major challenges faced by the industry, such as the unleaded gasoline mandate, the introduction of oxygenates (such as MTBE, ETBE and ethanol) to gasoline, and the trend for ultra-low-sulfur diesel (ULSD). Following roles with IFP (three years), BP Amoco (eight years) and UOP (20 years), he joined Shell in 2006 to lead its new worldwide hydroprocessing licensing organization. Such was its success that his portfolio was later extended to include all of Shell’s licensed refinery and petrochemical technologies. In 2009, he was appointed vice president. Mr. Özmen’s qualifications include a BSc degree in physical chemistry from the University of Paris, a chemical engineering degree from ENSPM, France, and an Executive MBA from the University of Chicago.

eddies that create the turbulence are well known. They include tighter specifications, rising energy costs, tougher environmental regulations, and variable crude quality. Another hugely significant issue is the shifting pattern of product demand. The industry’s center of gravity appears destined to move away from the developed nations.

This is because the world order is changing. The economic progress of nations such as India and China, along with increased downstream activity in the Middle East, is serving to transform the global refining landscape. So while businesses in Europe grapple with the region’s issues of overcapacity, aging assets and capital constraints, and companies in the US analyze the effects of the shale boom, enterprises in China and the Middle East operating companies are busily installing new capacity. China is reportedly investing over $40 billion in building refineries, not only at home but also in Africa, Asia-Pacific, Central America, Europe and the Middle East.

With various high-profile closures, mergers and acquisitions, the list of companies that have been unable to navigate the turbulence or that have chosen to follow a different path is growing. Is it possible for refining organizations to both survive and thrive in this environment? Most

definitely, but there is no single solution, silver bullet or panacea that anyone could prescribe that will enable this. Not only are the challenges facing refiners in the different regions starkly different, but the challenges also vary enormously according to their asset and investment portfolios, and business objectives.

Opportunities are present. By the

same token, there are opportunities to be exploited. For every refiner investing in new assets, there are new markets to be tapped. For every refiner that realigns its strategy and sheds assets, there is a new owner willing to take the opportunity to find alternative ways to leverage value. Valero is a good example of this. It is the world’s largest independent refiner, despite being a relatively new entrant to the sector, and has a strong track record of squeezing extra value out of the assets that it acquires.

So what will it take to win in this sector? I believe that, in the future, suc-

cessful projects will require the owner to achieve a high performance level in at least 10 out of 12 key factors, as shown in FIG. 1. This is not easy, not least because some requirements, such as low operating costs and low capital expenditure, can be conflicting, but also because some are beyond a refiner’s control, such as the location of a new or revamp project. Moreover, two of these are mandatory: safety and environment.

1. Size. Typically, larger refineries are more efficient because they benefit from economies of scale. In addition, the economic case for costly investment in conversion equipment or emissions control may be better. There has been a clear trend toward larger-scale refineries as owners seek to leverage economies of scale to enhance profitability. In the US, for instance, although the number of reHydrocarbon Processing | NOVEMBER 2012 37

Viewpoint Size Configuration

Environment

Safety

Market

Capital expenditure

Product mix

Operating costs

Access to crude

Joint-venture composition

Project-delivery scheme Location

FIG. 1. The 12-factor performance concept. Future projects must aim to score high in at least 10 out of 12 of the key factors, as shown here.

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fineries is less than half of that in the mid1980s, the average size of the facilities has increased by a factor of four.

2. Configuration. Refineries are increasingly focusing on their ability to process heavier and higher-sulfur-content crude oils into the products that the market wants. Flexibility to respond to changing market conditions is also key—just ask the US refiners that have faced huge fluctuations in the diesel-to-gasoline price differential in recent years. Possessing a process configuration that enables a refiner to swing between the gasoline and distillate modes can facilitate taking advantage of seasonal product demand shifts.

3. Market. Does the project have a ready market for its proposed product slate? We are seeing refiners establishing joint ventures ( JVs) with national oil companies to unlock new market opportunities (see No. 8). Or, a company may have its own retail business, integrated petrochemical facility or lubricant base oil plant. Alternatively, some facilities sell product-blending components rather than finished products. Whatever the outlet, demand security can make a huge difference to a project’s bankability.

4. Product mix. The product mix must be scoped according to market trends. Will the products still be in demand when the assets come onstream?

Has the owner maximized the ratio of high- to low-value products or hedged against price variations? Are there any emerging regulatory trends that could have an impact on the product slate?

5. Access to crude. A project’s ability to secure a long-term crude supply can be pivotal, as approximately 80% of a refinery’s costs are for the feedstock.

Moreover, contingency should be built in so that there are multiple options. This can be achieved through JV partners or by signing long-term deals. In the future, we may also see independent refiners signing oil supply deals with banks, as this can help to reduce the risks of price volatility and the working capital.

6. Well-designed project delivery scheme. There is one school of thought that says for each $1 billion of capital expenditure, a 25-strong team is required to manage the project. Increasingly, initiatives are being driven by project-management consultants and strategic licensors who have been hired to coordinate the various interfaces and ensure account-

Viewpoint ability. This can help to secure on-budget and on-schedule implementation, as well as preferable financial terms.

7. Location. Location has emerged as one of the key determinants of a refinery’s profitability. A strategically placed refinery that enjoys feedstock sourcing advantages and proximity to growing markets can be a highly attractive proposition for investors.

Location can also affect cost competitiveness. The closer a refinery is to its crude supply and the markets that it serves, the lower the total feedstock and transport costs are likely to be.

In addition, integration with a petrochemical facility is also helping many refineries to enhance profitability. For instance, the hydrocracker residue can be sent to the steam cracker to make ethylene, and reformate can be upgraded to valuable aromatic products such as paraxylene and benzene, thereby enhancing the economics at both sites. Some analysts have viewed refinery–petrochemical integration less favorably because of the volatility of petrochemical prices.

However, despite this, combining petrochemical manufacturing with refining can give a good overall return.

8. JV team composition. Some of the best-performing JVs involve partners that each bring something special to the table. Shell’s proposed JV with PetroChina and Qatar Petroleum is potentially a prime example of this. Qatar Petroleum will bring the venture’s crude oil and condensate. PetroChina will provide the market—China’s expanding economy— as well as Chinese project execution expertise and capital cost advantages. Shell, meanwhile, can bring world-leading technologies; quality; health, safety and environment systems and standards; and proven experience in delivering largescale projects.

9. Operating costs. This year saw a sharp downturn in industry refining margins, so lowering operating costs can be vital to competitiveness. Operating costs are, to a large degree, built in at the frontend engineering design stage through decisions concerning the amount of process integration and the equipment’s energy efficiency. However, low operating costs can sometimes be incompatible with low capital expenditure.

10. Capital expenditure. Although the challenges of the debt markets

heighten the need for low capital expenditure, this should always be balanced against ongoing operating costs. It typically costs more to run a less capitalintensive plant. That said, intelligently designed projects can sometimes find opportunities to unlock simultaneous reductions in operating and capital costs.

For instance, a new concept to minimize duplication and maximize integration in the refinery scheme cuts the capital expenditure at the Rayong refinery in Thailand by 5% and also reduced its energy consumption by 26%.

11. Safety. High performance in this area is not optional. Given the nature of the risks involved, ensuring an asset’s safety and integrity is paramount to all refinery projects. Making sure that a facility is well designed, safely operated, and properly inspected and maintained is always a prerequisite, and requires robust, proven design and engineering practices and technical standards for design and construction.

12. Environment. Advanced technologies have helped to curb refinery

emissions over the past 20 years, but regulations will continue to tighten. World Bank standards are becoming the norm for projects worldwide, regardless of the local requirements. As with safety, compliance with environmental mandates is obligatory. A refinery that fails to meet its emissions targets can lose its license to operate, which is why financiers scrutinize a project’s emissions-control plans.

Outlook for refiners. The 12-factor performance concept described here can help refiners to chart a course toward a profitable future. As excellence is a dynamic criterion, the relative importance of these areas will wax and wane in response to market turbulence. One notion that will remain constant, though, is the importance of working together. In my experience, the sector’s highest-performing enterprises seek out and draw on external expertise throughout all project phases, from scouting and front-end engineering and development through to operations. New perspectives, it seems, are required for interesting times.

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39

| Special Report PLANT SAFETY AND ENVIRONMENT Environmental compliance and plant safety are not optional. They are 24/7 mandatory principles for hydrocarbon processing industry (HPI) facilities.

Safety and environmental programs are best practices. Equipment failure, operator error and abnormal operating conditions can cause environmental emissions as well as catastrophic safety incidents. Processing hydrocarbons is a risky business, but HPI operating companies have made safety and environment programs part of their core goals. In November, the special report articles investigate timely and critical methods to protect HPI facilities and employees along with the public and the environment.

Operator working safely in an HF alkylation unit; see full story in 2012 December Hydrocarbon Processing. Photo courtesy of Invensys and Phillips 66.

Special Report

Plant Safety and Environment D. SMITH and J. BURGESS, Smith & Burgess LLC, Houston, Texas

Relief valve and flare action items: What plant engineers should know When most companies implement the process safety management standard, they routinely or periodically review the relief systems and flare systems design bases to ensure compliance with corporate, industry and/or government standards, hereafter referred to as Recognized And Generally Accepted Good Engineering Practices (RAGAGEP). To mitigate concerns before implementing projects, it is advisable for plant engineers to consider several items when reviewing a concerns list: 1. Relief systems review methodology 2. Relief systems review priorities 3. The process designer’s familiarity with the process and/ or plant when concerns are being reviewed 4. The plant engineer’s understanding of the differences between compliance and best-in-class practices.

An article published in 2000 concluded that up to 40% of the installations evaluated had unidentified concerns.1 Since the publication of this article, many of these concerns have undergone a more detailed review showing that modifications to the facility were not required to address these concerns.

The purpose of this article is to help the plant engineer review the concerns developed by the design engineer. Implementing field modifications without performing such a review is costly and exposes a facility to unjustified risks.

For the purposes of clarity, the following terms used throughout this article are defined as such: • Plant engineer—The facility or owner’s engineer who is responsible for reviewing the concerns and determining if facility modifications should be implemented • Process designer—The individual who is responsible for analyzing the relief device and overpressure protection system and developing the concerns • Concerns—Items that are listed (prior to being fully reviewed and accepted) as deviations from industry or company standards.

At the end of the relief systems design basis project, the process designer typically identifies many concerns. As most facilities want to comply with RAGAGEP, there is a mandate to resolve these concerns, and their resolution can be costly.

Generally, most facilities seek to comply with regulations for existing facilities and to potentially build new equipment and facilities to a higher standard. This article includes examples of how to review existing systems to determine if concerns justify field modifications.

RELIEF SYSTEMS REVIEW METHODOLOGY Relief systems design basis reviews are typically performed by contractors that assist in developing project guidelines and then collect the necessary information. After these initial actions, the contractors analyze the system’s design basis per the project guidelines and present a list of identified concerns to the plant’s engineers and management. Prior to spending money to upgrade the relief systems, a plant engineer familiar with the process unit should review the concerns list to ensure that: • Details of the study are reasonable • Assumptions of the study are reasonable • Facility upgrades, not based on minimum compliance, have been thoroughly reviewed.

By reviewing the concerns list with these suggestions, a plant engineer can ensure that costly changes have a basis in sound engineering and that the expense is justified. Note that no hierarchical order is implied in this list.

Typically, when a relief systems design basis project is undertaken, the goal is to produce compliant documentation efficiently and consistently. To do this, process designers must base the analysis on a framework to minimize effort and ensure consistency. This is a practical method for performing a largescale relief systems analysis; however, for any particular concern, the framework may break down and suggest items that are not actually concerns.

In a recent review project, approximately 40% of the listed concerns were later found to be acceptable based on a detailed review. The following sections help walk a plant engineer through a systematic process and give insight into how to review the listing of concerns.

Reviewing relief system study details. When the concerns

are reviewed from the perspective of the process designer, the plant engineer can understand how the framework may have generated potential concerns. Understanding this process can help the plant engineer identify resolvable concerns by reviewing the design basis.

Understanding the process. When completing large-scale relief systems design basis documentation and design processes, the process designer is usually quite familiar with relief systems design but may not be familiar with the particulars of the process or unit. The process designer, therefore, may make unrealistic judgments about process upsets. The following are examples of these items: Hydrocarbon Processing | NOVEMBER 2012 41

Plant Safety and Environment • When process flows can be blocked, or if the normal rate is possible under upset conditions • Use of the normal/design duty from a reboiler for relief rate estimation • Equipment that is no longer in service is not properly protected.

To ensure the best possible analysis, each study should be reviewed by personnel familiar with the process operation to confirm that unique process characteristics are captured in the relief systems documentation.

Credibility of scenario or relief rate. For each overpressure scenario that generates a concern, the plant engineer should give particular attention to ensure the credibility of the scenario or required relief rate. Many times, an overpressure scenario or the estimated rate may not be credible. The following are some examples: • Pumps that can only pump to relief pressure if the upstream system is also upset (however, a simultaneous upset would be considered double jeopardy) • Systems where overpressure derives from heat input, such that the relief temperature of the process fluid exceeds the relief temperature of the utility fluid • Control valve failure calculations that are based on the capacity of a control valve instead of on another limitation (e.g., a long section of piping or a pump).

To ensure an accurate analysis, each concern should be reviewed to verify that consideration has been given to the determination of the scenario applicability and that the relief rate estimate is reasonable for the particular process or unit.

Gathering facility data. The relief systems analysis process typically limits the amount of places and time that the process designer can search for process and equipment data. This limitation is usually defined as a project scope item and is used to ensure that the project has boundaries. When reviewing concerns, the plant engineer must ensure that the process designer has not identified concerns that can be readily resolved by furSystem relief devices 4 x 8-in. inlet flange, 10-in. outlet flange, T orifice

External system feed Pmax = 200 psig

CSO

To flare

Overhead cooler

CSO

Offgas product

Top pumparound

Top reflux Overhead product

Mid-tower product

Bottom pumparound Fractionator

Bottom product Other process heaters Feed furnace

FIG. 1. Flow diagram of an example fractionator.

42 NOVEMBER 2012 | HydrocarbonProcessing.com

ther searching for process and/or equipment data. Often, this requires a call to an external supplier or technical body (e.g., the equipment manufacturer or national board).

Other execution issues. The relief systems process typically uses a consistent basis that is often documented and referred to as site or project guidelines. These guidelines are beneficial, as they provide a means for efficient and consistent execution and help ensure that both the process designer and plant engineer are in agreement on the details of the analysis. When these generic and prescriptively conservative guidelines generate concerns, it is imperative that the team generating the documentation reviews the fundamentals of the analysis to confirm that the concern is a legitimate deviation from RAGAGEP and not just a result of the project execution process.

Reviewing relief system study assumptions. The typical execution method of a project tends to enforce consistent assumptions. For most of the project, this ensures that the relief systems design basis is conservative and compliant with RAGAGEP. To ensure that field modifications are for items that must be addressed, these assumptions may need to be challenged when concerns are raised.

Standardization assumptions. Standard and generally conservative assumptions are specified to ensure consistency and efficiency. These assumptions help the relief systems documentation process run efficiently; however, if generic assumptions result in concerns, they should be revisited and updated. The following are some examples of these items: • Liquid levels for equipment • Control valve flow coefficients and trim sizes • Utility pressures (e.g., steam, nitrogen, cooling water) • Heat exchanger or pump capacities.

To ensure the best possible analysis, the assumptions associated with each concern should be reviewed and, if possible, refined to be specific for that system.

‘Conservative’ assumptions. The authors of this article have been carrying out relief systems analysis for multiple decades and believe that “conservative assumption” is frequently used as a phrase for a simplifying assumption that the process designer invoked. Furthermore, this phrase typically has nothing to do with being conservative. The following are examples of conservative assumptions: • Normal flowrate was used instead of a reduced estimate • Column tray or overhead flowrate was used instead of performing a simulation • Multiple unrelated failures occurred simultaneously.

As previously stated, each “conservative assumption” should be reviewed and refined so that it is specific for each system.

Other assumptions. The design and analysis of relief systems is an art. Much of the analysis is based on the assumptions that form the overall basis. Mathematical errors are rarely the cause of an incorrect analysis; usually, the cause is a problem with the basis. The basis for each system is stacked on top of a basis for another system. Once the assumptions are flushed out and determined to be correct, the mathematics are easy.

Fractionator example. In the past, the authors reviewed a fractionator (FIG. 1), where the normal feed vapor rate was specified as the relief rate for a power failure relief load (conservatively assumed). When the capacity of the feed furnace was

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Plant Safety and Environment confirmed, the feed furnace could barely vaporize the normal amount at the normal production rate and fractionator pressure. This particular power failure scenario specified the loss of the pumparounds, which resulted in the loss of approximately 80% of the crude preheat train duty.

When properly reviewed, upgrades to the flare and relief system from a relief systems analysis can improve the safety of an operating facility.

With the increase in pressure and cooler-than-normal feed temperature to feed furnace, the maximum vaporization would be around 50% of the normal vapor rate. The argument for keeping the feed preheat was that it was conservative, as the heat input may not be lost. If this turned out to be the case, then pumparounds would have continued, leading to a significantly different outcome. Assumptions need to at least be internally consistent for each scenario. If the pumparound cooling is lost, then so is the feed preheat, and vice versa.

Distinguishing minimum compliance from best practices. The final items that need to be reviewed by the

plant engineer are any deviations from RAGAGEP (and not just deviations from best practices). Often, when completing relief system projects, the team responsible for the design will, with the best of intentions, work into guidelines some requirements that go beyond RAGAGEP. While extra requirements may be justified based on the increased safety at nominal incremental costs in new construction, these requirements can be quite expensive for existing facilities.

These additional requirements must be reviewed and possibly excluded from items that need to be retrofitted. Regulatory requirements may require additional documentation to ensure that not making modifications presents an acceptable risk.2 Gray areas for modification. Often, items may not be absolutely correct, but they also may not rise to a level requiring field modification. An example is when current corporate standards exceed the standards to which a unit was built. This situation is particularly relevant when a facility is acquired, thus creating a situation where a facility was constructed to one set of corporate standards but is now operating with a new corporate standard in effect.

In these cases, a process designer should investigate any deviations and document why these deviations are acceptable. For cases where past designs do not meet the current RAGAGEP standards, but the deviations are deemed to be minor, management at some facilities may choose to have more regulatory risks than safety risks.

Consideration of risk to make changes. Fixing issues with equipment design, especially when the facility is running or even in turnaround, must be carried out with great care. In the past three or four years of literature searches, the authors 44 NOVEMBER 2012 | HydrocarbonProcessing.com

have yet to find a single case of a slightly undersized relief device resulting in an injury or loss of containment. There are, however, countless records of injuries sustained from refinery modifications that can be found via Internet search.

To illustrate this point, in a 2009 Chemical Safety Board (CSB) video requesting that the city of Houston, Texas adopt the American Society of Mechanical Engineers (ASME) Pressure Vessel Code, the CSB was unable to find instances resulting in loss of containment for pressure vessels for undersized relief devices.3 The video cites three examples of vessel failures from undersized relief devices. The first example is a low-pressure tank with an undersized relief device, and the other two examples have plugged or isolated vent lines.4, 5, 6 For a plant engineer responsible for increasing overall facility safety, it may be possible to defer modifications for the resolution of minor deviations until other equipment changes are required. This would be at the discretion of the facility, it would require a reasonable level of risk, and it could open up the facility to regulatory action.

FLARE SYSTEMS REVIEW METHODOLOGY The preceding section reviewed the typical methodology that a process designer would use to generate a relief systems design basis. This section is designed to help the plant engineer understand how the individual relief systems loads are developed and used to create an overall set of global scenarios, which is then used to verify that the flare system and associated equipment are adequately designed. Several key topics will be further explored: • Global load considerations • Reasonable and consistent assumptions • Advanced flare techniques.

By reviewing the flare systems design concern list from these three angles, a plant engineer can ensure that the basis for costly changes is justified.

Global load considerations. When a relief systems design

project is undertaken, the individual relief device loads are typically gathered first. Once these loads are known, they are entered into a hydraulic analysis tool, and then the flare system is analyzed. However, as with the individual load determinations, there are areas that a plant engineer should review.

Credibility of the scenario. In global scenarios, the process designer typically will review power failures (both a total loss of power and partial power failures), utility failures and largescale liquid pool fires. All of these scenarios affect multiple systems of equipment and should be considered. The process designer for each individual scenario looks at the underlying scenario to ensure that it is credible. For example: • Is a large-scale liquid pool fire possible, and to what extent?

• Is a total utility failure possible, or does the utility feed all the listed equipment systems?

• Does one utility failure lead to another utility failure (e.g., loss of steam resulting in the loss of the turbine-driven instrument air compressor)?

As previously stated, “conservative assumptions” for scenarios that are not controlling or that do not have concerns may be

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acceptable. A plant engineer should review the scenario basis for any global scenarios with concerns. Additionally, the “conservative assumptions” associated with the sizing of the relief device may not be consistent or even possible, given the specific global scenario being evaluated.

Credibility of the rates. Global overpressure scenarios are often a compilation of relief rates specified as closely related individual relief device scenarios. While these scenarios may have been conservatively estimated and may have generated no concerns, summing multiple systems with conservative rates may result in problems.

In a presentation to the 6th Global Congress on Process Safety, Dustin Smith reported on a refinery-wide review that resulted in a 40% reduction in the design relief rate by reviewing the specified relief loads and eliminating overly conservative assumptions.7 A plant engineer should ensure that the process designer does not simply create a global scenario on the basis of multiple conservative calculations; the designer must also review the system to ensure that rates are reasonable and defensible (and not excessive due to assumptions).

Reasonable and consistent assumptions. As with the individual relief systems analysis, the scenario assumptions and those used to generate the relief rates make a tremendous impact on the adequacy of the flare system and associated equipment.

‘Buried’ assumptions. When sizing individual relief devices, RAGAGEP require that the process designer assumes that the worst case occurs and that all related failures, pump lineups and control valve responses are either neutral or detrimental. For global scenarios, the process designer must assume that the global failure occurs, but the requirement for neutral

or detrimental effects is more muted. The following are some examples of “buried” assumptions typically used: • Heat exchanger duty based on service overall heat transfer coefficient and area (UA) instead of the clean and new UA • Level control valves hold level in process vessels • Airfin coolers retain some fractional cooling capacity • Operations personnel do not simultaneously open depressuring valves with utility failures unless directed to in operational procedures.

The plant engineer and process designer should work with personnel that operate the units, and they should review scenario basis and loads for any global scenarios with concerns.

Consistent assumptions. In the definition of global overpressure scenarios and associated rates, the need to ensure consistency is paramount. Many times, the process engineer will assume for one equipment system that a pump was in operation and has failed, while, in the next equipment system, the failure pump was spared and the alternative pump was in operation. For these analyses, consistency across the facility is required, as the goal is to analyze the flare system (vs. the individual relief devices). Some assumptions can result in system-wide inconsistencies: • When a pump is spared and used for multiple equipment systems, the scenario should specify which pump has failed for all systems • The effects of the failures must be considered for systems with heat integration • Utility failures that result in cascading losses must be examined consistently.

The plant engineer should review the controlling global scenarios to ensure that the assumptions used are internally consistent.

Hydrocarbon Processing | NOVEMBER 2012 45

Plant Safety and Environment Advanced flare analysis techniques. API Standard 521 alTAKEAWAY lows for the consideration of positive action of instrumentation, When reviewing concerns generated from the relief system operations or other favorable items, as long as the failure of these or flare design and documentation process, the plant engineer items is considered.8 Prior to making costly flare system modimust ensure that each concern is valid and that any resolution requiring physical changes is a justified investment of a facilfications, the plant engineer should review more complex flare ity’s capital. To properly perform this task, it is recommended system analysis tools to ensure that modifications are justified. that a plant engineer understand how a process designer perFlare load probability analysis. In a presentation to the 6th forms the study and review the concerns prior to making physiGlobal Congress on Process Safety, Dustin Smith reported on a cal changes to the facility. method to estimate the flare loading probability.7 This method determines the likelihood of loads to the flare system, and it can be used to target instrumented responses and piping modifications. This method demonstrates By reviewing the concerns list, a plant that analysis of the effects of safeguards and the probability of failure on demand (PFD) of these safeguards engineer can ensure that costly changes can be used to develop the system loading as a funchave a basis in sound engineering and tion of probability/frequency. Using this information and given an acceptable time frame (e.g., 1 in 100,000 that the expense is justified. years), the expected flare load is lower than the worstcase scenario.

The authors recently reviewed a refinery where the likelihood of a “worst-case” load, if a total power failure ocWhen properly reviewed, upgrades to the flare and relief curred, was approximately 1 in 100 million years. The design system from a relief systems analysis can improve the safety of load for 1 in 100,000 years was a fraction of the total load, and an operating facility. it was more consistent with the complexity of the plant, along LITERATURE CITED with the DCS programming and the safety instrumented func1 Berwanger, P. C., R. A. Kreder and W. S. Lee, “Analysis Identifies Deficiencies in tions and interlocks recently installed.

Existing Pressure Relief Systems,” Process Safety Progress, Vol. 19, 2000.

2 Flare quantitative risk assessment. Flare quantitative risk Smith, D. and J. White, “Ensuring safe operations when fulfilling action item requirements,” Hydrocarbon Processing, March 15, 2010. assessment is a way to review each scenario and the perturba3 “Without Safeguards, Pressure Vessels Can Be Deadly,” US Chemical Safety tions of these scenarios to determine the likelihood of vessel Board, Video, 2009.

9 overpressure as a function of frequency. This varies from the 4 Poje, G. V., A. K. Taylor and I. Rosenthal, “Catastrophic Vessel Overpressurization,” flare loading probability in that the statistical analysis and hyUS Chemical Safety and Hazard Investigation Board, Report No. 1998-002-ILA, 2000. draulic analysis are coupled; whereas, in the flare loading prob5 D. D. Williamson & Co. Inc., “Catastrophic Vessel Failure,” US Chemical Safety ability, the flare loading statistical analysis is separate from the and Hazard Investigation Board, Report No. 2003-11-I-KY, 2004.

6 hydraulic analysis. In both cases, the plant engineer must en“The Goodyear Tire and Rubber Company,” US Chemical Safety and Hazard sure that the scenario initiating event frequencies and the PFD Investigation Board, Report No. 2008-06-I-TX, 2011.

7 Smith, D., “System Limited Flare Design: A Flare Load Mitigation Technique of safeguards are reasonable and defensible. (with a QRA Case Study),” 6th Global Conference on Process Safety, 2010.

Flare load dynamic simulations. Offering and requesting 8 ANSI/API Standard 521, “Pressure-Relieving and Depressuring Systems,” dynamic flare system designs are becoming increasingly comAmerican Petroleum Institute, 2008.

9 Kreder, R. A. and P. C. Berwanger, “Quantitative Analysis—A Realistic Approach mon. Like the other advanced flare analysis techniques, this one to Relief Header and Flare System Analysis,” 2005. increases the complexity of the analysis, thus requiring the facility 10 Chen, F. F. K., R. A. Jentz and D. G. Williams, “Flare System Design: A Case for to increase its understanding of the effects of assumptions on the Dynamic Simulation,” Offshore Technology Conference, Houston, May 1992.

11 final answer.10 The basic premise of dynamic simulation is that, by Burgess, J., “Flare Header Debottlenecking,” Design Institute for Emergency Relief Systems, Spring Meeting, 2006. combining the effects of the staged timing of releases and the dynamic pressurization of the flare system, the peak loads and back DUSTIN SMITH, PE, is the co-founder and principal consultant of pressures on system components are reduced. In this method, the Smith & Burgess LLC, a process safety consulting firm based in plant engineer must ensure that the fundamental assumptions afHouston, Texas. As a consultant, Mr. Smith has extensive fecting the timing of each system or release are reasonable and experience with helping refineries and petrochemical facilities maintain compliance with the PSM standard. He has more than a defensible, thereby ensuring that the system is properly modeled. decade of experience in relief systems design and PSM Other techniques. Other methods to analyze flare systems are compliance. His experience includes both domestic and proprietary to operating companies. All of these methods are deinternational projects. Mr. Smith is a chemical engineering graduate of Texas A&M University and a licensed professional engineer in Texas. signed to account for the probability that either operator intervention or instrumentation will operate, or fail to operate, as desired.

JOHN BURGESS, PE, is the co-founder and principal consultant Any method of flare header analysis that is not a worst-case of Smith & Burgess LLC, a process safety consulting firm based analysis must, therefore, establish some reasonable means of acin Houston, Texas. Mr. Burgess is a consultant who specializes in helping refineries and petrochemical plants meet the PSM counting for the positive action of instrumentation or operator standard. His experience includes more than 10 years in relief intervention to mitigate the worst-case load. The delicate balsystems and PSM compliance, for both domestic and ance between realism and conservativism in flare header design international projects. Mr. Burgess has BS and MS degrees in is paramount in creating a safely designed flare header at a reachemical engineering from both Texas Tech University and the University of Missouri, and he is a licensed professional engineer in Texas. sonable cost.11 46 NOVEMBER 2012 | HydrocarbonProcessing.com

Special Report

Plant Safety and Environment C. REESE, SSOE Group, Midland, Michigan; and B. TAYLOR, Midland Engineering, Midland, Michigan

Surviving and thriving in the era of enhanced OSHA PSM audits Over the past two decades, the US Occupational Safety and Health Administration (OSHA) has put in place regulatory programs to protect the safety of workers in industrial plants. One such program is the process safety management (PSM) standard, which contains requirements for preventing or minimizing the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. More recently, OSHA has developed special emphasis programs to target specific industries, notably the petroleum refining and chemical industries, and enhanced its auditing processes and inspection priorities. Result: Owners are facing tougher inspections and stiffer fines. Here are some insights into what this means for owners, managers and operators today.

Most cited. Reports from recent inspections indicate that four

inspection items, in particular, are challenging owners today: • Process safety information (PSI) • Process hazard analysis (PHA) • Mechanical integrity (MI) • Management of change (MOC).

In fact, failure to meet the standard in these four areas has resulted in the highest number of citations in the refining industry in recent years. As a result, owners must reevaluate their PSM programs and ensure that they are taking a rigorous approach to developing, documenting and implementing them.

In one case, owners developed and rolled out their revised and enhanced PSM program over the course of a couple of years, while continuing to operate existing facilities and build major expansions that had to integrate the changing regulatory environment. When the petroleum industry’s National Emphasis Program (NEP) audits began, they significantly changed the program once they saw the nature of the citations being issued. For example, they observed that OSHA inspectors were examining equipment, operations and safety procedures from a new perspective and (more importantly) were interpreting the regulations from a new perspective.

With PSI, OSHA inspectors are requiring owners to produce documentation. Failure to produce documentation has become a citable deficiency. This has required firms to develop comprehensive document filing and tracking systems for PSI so they can be readily found when requested by OSHA or needed by project or process engineers. Gone are the days of plant personnel saying, “Oh, it’s in the file room somewhere.”

Another challenging area is that of the PHA, which in-

cludes requirements for a facility siting study. OSHA inspectors interpret the regulation broadly: along with renewing the PHAs of covered process units and equipment on a five-year cycle, which is part of the regulation, they expect to see that the facility siting study has been revalidated every five years just like any other PHA. Inspectors are also taking a close look at MI and MOC. They expect to see documentation showing that owners have carefully assessed and prevented hazards through their change-management programs. For example, a worker might think nothing of changing out a stainless-steel valve for a valve composed of another chemical-resistant material if the stainless-steel replacement valve is out of stock. However, the alternative might react chemically with the material that is being processed, resulting in a catastrophic failure.

In other cases, a required change made by engineering might not always be communicated to operations. Additionally, a change may be properly communicated; however, associated changes in operating procedures and training may not be, as required by the regulations. OSHA is closely looking at these types of gaps to ensure that changes are communicated and documented in all relevant process safety elements such as PSI, PHAs, operating procedures, training and any other elements impacted.

MOC, as noted previously, impacts many elements of a PSM program. It must be well-documented to enable a thorough five-year revalidation of the PHA of a particular unit or piece of equipment. In particular, any changes or incidents related to that piece of equipment must be reviewed in detail so that the hazard analysis team can ensure that the appropriate changes have been made without a negative impact on the safety of the process as it was designed.

Focus of enhanced audits. OSHA began performing enhanced PSM audits of the refining industry in June 2007 as a result of the March 23, 2005, BP Texas City incident. It expanded them to the chemical industry and other industries covered by the OSHA PSM standard from July 30, 2011. These chemical NEPs were piloted in two regions (I and VII) starting July 2009. In these audits, they focus on highly toxic chemicals, especially ammonia, chlorine and hydrofluoric acid.

The inspection process itself has become more arduous and detailed. For example, in its NEP audits, OSHA has brought in large teams to conduct detailed reviews over long Hydrocarbon Processing | NOVEMBER 2012 47

Plant Safety and Environment periods (in some cases, up to six months). These teams have often focused on one or two units. They have taken piping and instrumentation drawings, walked through a unit, and

conditioning (HVAC) design and, more important, how to shut it down in case of an alarm signaling a chemical release in the refinery or chemical plant. Some facilities are revising their HVAC control system to allow shutdown of all systems feeding a building upon activation of a single switch or button located at a readily available interior building location, such as a hallway.

Develop a comprehensive PSM program and a comprehensive internal compliance auditing process, and focus on the program elements that really make the difference.

noted differences between the drawings and the field conditions. Discrepancies resulted in citations for failure to maintain current drawings.

There have been a few surprises. In addition to the greater rigor and detail of these audits, they are also touching additional departments in the plant. For example, inspectors have required that everyone inside the plant, even office workers, have a basic understanding of the heating, ventilation and air

Internal compliance auditing. An effective internal compliance auditing program is key to protecting workers and the surrounding community, and it gives plants a better chance of coming through an inspection with fewer citations.

There are a number of ways to address internal compliance auditing, depending on the size and makeup of the company. For example, larger sites with internal auditing staff who understand the present inspection process, including areas receiving greater attention, can probably perform these audits themselves. An independent engineer with expertise in PSM can provide additional perspective to an internal team.

Some owners periodically contract with an independent auditing firm to perform the entire audit.

In any case, it is critically important to ensure that the internal compliance auditing team comprises people with PSM experience, strong understanding of the regulations, and contact with peers in other companies who can provide additional insights.

Of course, a successful internal compliance audit is predicated on a well-structured and fully documented PSM program. And, in turn, this requires leadership, ideally by an engineer with not only PSM experience but also experience or knowledge of all aspects of the unit such as operations, engineering and technology, and who can lead a multi-functional team that will implement all of the PSM elements. Finally, the key to any successful program is management support by providing proper resources, funding and overview to ensure an effective program.

An effective PSM program that protects the safety of workers—and proves itself in the eyes of OSHA—requires that owners, managers and operators observe this time-tested advice: “Don’t assume anything.” Develop a comprehensive PSM program and a comprehensive internal compliance auditing process, and focus on the program elements that really make the difference. These are key to surviving and thriving in the era of the enhanced OSHA PSM audit.

CLIFFORD REESE, PE, is a business leader and senior associate of SSOE Group, an international engineering, procurement and construction management firm. He has over 25 years experience with global engineering, chemical and petrochemical manufacturing and construction, specializing in implementations of new capacity and innovative process development programs, including coal gasification, biofuels and specialty chemical and refinery projects.

BRUCE TAYLOR, PE, CPEA, is a vice president of Midland Engineering Ltd., an engineering, consulting and auditing firm providing services in such diverse fields as organic chemicals, agricultural chemicals, pharmaceuticals, inorganic chemicals, refining, power generation and polymers. He has over 35 years of industry and consulting experience developing, implementing and auditing safety and process safety programs and management systems in the plastics, chemical, pharmaceutical and refining industries.

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Special Report

Plant Safety and Environment E. LAVERGNE, Tyco Fire Protection Products, Mauriceville, Texas

Keep it simple: Three key elements to fighting complex flammable liquid fires Many storage tank facilities in the US have the necessary resources to douse a large-scale flammable-liquids fire, but ultimate success centers on the strategy taken with personnel, equipment and expertise. Approaching each fire strategically requires taking into consideration three key elements for flammable-liquid fire extinguishment: 1. High-quality foam concentrate that outperforms industry standards and surpasses baseline testing 2. Simplistic equipment that can stand up to harsh conditions, and rigorous and extensive use 3. Understanding and identifying the hazard, and deploying the right firefighting methods to extinguish the flame quickly, with minimal loss of resources and danger to personnel.

If there is adequate water, hoses, pumping capacity, foam concentrate, delivery devices and personnel, a fire can be successfully extinguished. However, gathering those resources and implementing the appropriate procedures can be challenging. The concepts may seem simple, but execution can often be difficult. The experience of flammable-liquid firefighting personnel is one of the most invaluable elements in combating these types of fires.

The experience of battling an extremely challenging fire at a major refinery in Louisiana in 1989 continues to offer insight into strategies for dealing with especially confounding blazes.

This refinery incident was a massive multi-target fire involving tanks, pipelines, railcars and API separator units. The magnitude of this event required immeasurable skill in the vital areas of incident command, tactical excellence, logistics and resource management. Collaborating with the site fire chief, the fire was suppressed in a relatively short period of time and an incident that could have turned into a regional crisis was averted.

The response team assisted the client in suppressing fires in 16 storage tanks (two of which were 134 ft in diameter with manifold fires and dikes completely involved in the blaze), four API separators (which separate large amounts of oil and suspended solids from the wastewater effluents) and two pipebands involving about 250,000 square feet of fire area.

The company responded with hardware and personnel, successfully extinguishing all fires in 14 hours and 29 minutes with 48,000 gallons of alcohol-type concentrate foam. The facility-consuming event was a massive test of strategic response capabilities, incident command prowess, emergency preparedness and logistics.

Power loss leads to fire. The cause of this significant event

started because of a power loss to a grid serving a large radius of Baton Rouge, Louisiana, including a major refinery and chemical complex. Due to abnormal freezing temperatures, this power outage caused the facility’s systems to go into fail-safe mode.

In the fail-safe mode, system design parameters cause various components of the process and transfer system to default to wide-open or fully closed positions to manage process variables such as flow, levels, pressures and temperatures throughout the facility.

Thermal expansion on an 8-in., high-pressure product line caused a failure releasing 1,500 pounds per second in a hydrocarbon vapor/mist form. The release lasted approximately 21⁄2 minutes before ignition. An estimated 225,000 pounds of released hydrocarbon vapor created a cloud 1,000 ft–1,500 ft in circumference and about 80 ft in height/depth. The blast measured a 3.2 on the Richter scale 75 miles away in New Orleans.

On site at the time of the explosion, the fire chief for the facility was supervising safety components of other maintenance activities in a low-lying area between two high dike walls of a storage tank. Nestled between these surrounding dike walls, the fire chief and his team were shielded from the impact wave caused by the initial explosion. Following the initial explosion, the fire chief made his way through the facility to ascertain operating status and damage assessments. Impeded by excessive debris from the blast wave, he made initial observations from the ground as he made his way on foot within the facility.

FIG. 1. Rail spurs are common arteries into industrial sites, and they carry any number of railcars bearing chemicals that may become a priority following a fire event.

Hydrocarbon Processing | NOVEMBER 2012 51

Plant Safety and Environment Less than ideal circumstances. Ideal conditions for fighting a fire simply don’t present themselves when a major industrial emergency of this level occurs. One of the greatest challenges initially was the logistics of getting personnel and material onsite in a way to provide a tactical advantage over the multitude of fire-related events occurring throughout the complex. Though initially isolated from response personnel, the onsite fire chief relayed his observations that strategic upwind staging areas and supply routes had been cut off by the impact of the explosion and the ensuing fires. Optimum points of attack were initially taken away by the explosion, including a vital vehicle access tunnel that had flooded with 10 feet of burning flammable liquid from a nearby tank rupture. This required identifying alternate means to move in supplies and personnel.

Four beachheads were soon established at points on the property that facilitated injection of personnel and materiel to sustain what would become a nearly 15-hour battle. Four teams were organized at these beachheads to initiate an attack, with each team working its way through the facility to confront whatever fire scenario lay in front of them.

Simultaneously as these resources were being organized, the first order of business in the response effort was addressing the numerous railcars that were stationed on the property.

With five rail spurs (FIG. 1) feeding the facility, railcars containing various products from facilities throughout the industrial corridor were on the property at all times. Under these circumstances, the greatest immediate concern for incident command was three railcars specially marked as containing hydrocyanic acid (HCN) that were waiting transfer to another facility at the time of the incident.

The threat HCN poses prompted the railroad commission to determine that railcars carrying this product (unlike any other railcar) would be conspicuously painted white with a red stripe down the side for easy identification. Railcars were methodically removed within 45 minutes of the initial explosion. Including the 151 cars that were onsite, chemicals including gasoline, vinyl chloride, liquefied petroleum gas and other explosive and flammable liquids were present. Addressing the close proximity of these railcars to the vast ground spill fires, and the pressure fires in a pipeband across from the railroad staging area, prevented the possibility of chemical fires, more spill fires, and potential railcar boiling liquid expanding vapor

FIG. 2. Firefighters work with both facility response teams and local response personnel to identify effective response strategies.

52 NOVEMBER 2012 | HydrocarbonProcessing.com

explosions (BLEVEs). All the while, with the loss of power, gas supply and steam production, many facility personnel continued working throughout the site to secure process operations and all related aspects of facility safety.

This added the dimension of carrying on perpetual personnel accountability efforts while managing a very large response effort. Success in this incident was possible largely because of the willingness and exemplary training acquired by the response personnel for each of the specific threats they faced on this day.

Help arrives. Additional reinforcements were summoned in

the form of a contracted fire-control company. Its role was to provide added personnel, foam and equipment to aid primarily in extinguishing the larger tank fires on the site.

Using information from Louisiana State Police helicopter observations and quad sheet/map details, firefighting teams on the ground were kept informed of the activities of the teams working around them (FIG. 2), and they helped prioritize the numerous fire scenarios confronted throughout the day — thereby orchestrating the overall response efforts.

Conditions that day added to the complexity of the situation.

Firefighters dealt with challenging terrain characteristics, impeded supply lines, ambient temperatures reaching down to 10°F and the freezing of any firewater supply that was not kept moving.

It was an extreme and unusually cold December day in south Louisiana. The average temperature at that time of year normally is about 70°, but there had been subfreezing temperatures for five days prior to the fire. Even as they gained control over the situation, firefighters continually had to overcome the extreme cold given that their heat source had disappeared.

The tactics on this day were largely governed by the characteristics of the damage resulting from the initial explosion. The main challenge that haunted firefighters throughout the day was water supply. The water main was severely damaged in the explosion—hydrants were blown from their foundations, and extreme heat melted the brass steamers in the barrel of many hydrants.

Under normal circumstances, firewater supply would have been extracted from facility hydrants, but extreme temperature conditions and the explosion impact eliminated those resources. This forced the tank-fire specialists to develop their own water supplies and pumping systems. This became a fairly large task, especially considering that the fire was suppressed in less than 15 hours.

Alternate water resources available included chemically treated river-water tanks, process cooling tower water, and storm drain reservoir water that was drafted from below the oil layer and pumped to pumper trucks. In the extreme cold weather, responders resorted to burning boxes set atop frozen 12-in. valves to gain access to water within the river-water tanks.

Water from the cooling tower was relayed from 3,500 ft away.

Teams were pulled away from their primary response efforts twice to address fires that sprang up resulting from a rupture in a failed tube in a furnace, occurring when the power crashed, and another major pump fire in the chemicals division. Throughout the entire operation, not one lost-time injury was incurred.

Some of the firefighting personnel had responded to an incident at another refinery that same day (also a result of the subfreezing temperatures). Since the plants were located in a warmer climate, water distribution systems were plumbed

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Plant Safety and Environment aboveground. Result: The cold weather led to frozen and damaged pipes. After addressing the prior incident, the crews received a call about the refinery fire in Baton Rouge.

As crews arrived, fire personnel could actually see the fire from about 50 miles away, leaving no doubt that they would be dealing with a massive incident. There was a lot of difficulty getting to the facility because the explosion did so much damage to the region.

ery operator made changes to standardize its hose threads to meet the industry standard.

Training is key. The team that responded to the fire had worked together for many years, making it second nature when it came to fighting this large-scale refinery fire. In addition, the group had trained with the team permanently situated at the refinery, making their joint firefighting philosophies very similar. This alliance is credited as a key component to quickly Simple is better. Fires of this type often are best battled with controlling and defeating this incident. a simplistic approach, using a philosophy triangle that involves When firefighters receive training, they must be taught to high-quality foam concentrates, proven equipment and a vast unthink beyond the classroom; there is no textbook during a fire. derstanding of the hazard.

They should be pushed to gather all knowledge and underUnderstanding conditions is essential in battling a flammastanding, thus keeping an open mind when fighting a fire. ble-liquids blaze. This instance called for simplistic equipment When confronted with a dynamic emergency situation, the because the fire was fought under adverse conditions. way firefighters handle the task is directly related to their success and safety. Reactions to stressful situations are typically unchecked and fueled by emotion.

When firefighters receive training, Experience and advanced preparation guide responses based on intelligence and confidence. A planned rethey must be taught to think beyond sponse allows crews to act from a position of strength what they learn in the classroom, because rather than from anxiety. Professional response operations will deliver coordinated targeted actions there is no such thing as a textbook fire. that will produce specific predictable results built on knowledge of fire dynamics.

A primary reason the fire was suppressed in less than 15 hours stemmed from the relationship between the The fire field is no place for digitally-controlled equipment, company and its long-time customer, leading to well-develgiven the often extremely harsh conditions. It can be hot, cold, oped plans for such a fire. muddy or wet. Very robust equipment and products are needThis kind of evolved fire, which required addressing muled for success. Often, it’s about understanding and simplifying tiple fires at once, with reduced resources, freezing temperathe process, but everything must come together to provide a tures, burning infrastructure and lack of water, became a test total solution. of that relationship. In the end, the success in battling the blaze mitigated the impact on the surrounding community and elimMajor obstacles overcome. One of the biggest challenges inated a threat to the nearby Mississippi River. was the lack of water, since the water distribution system had The potential of a fire on the magnitude of the 1989 Louisibeen cut off. Crews had to turn to a cooling tower and the Misana refinery blaze may be somewhat rare, but it’s a major consissippi River as sources for water. They also had to deal with a cern for operators of large refining/chemical complexes. Thereconsiderable amount of ground fire. fore, they must be prepared for a major fire, even if the potential Despite the challenges, firefighters were able to extinguish is limited. The continuous development of firefighting teams is the blaze at a much lower than normal water/foam application essential in remaining prepared for a blaze of this magnitude. rate. Normally, suppressing a fire in a 134-ft diameter storage tank would have an application rate of 0.16 gallons per minute per ft2. Highly effective tactical discipline and team communiPost-incident analysis. Firefighting companies should decations enabled the crew to defeat much of the fire at an applivelop a post-incident analysis to determine strengths, weakcation rate closer to 0.10 for this tank, supporting the claim for nesses and lessons learned about incident-response operations high-quality foam concentrates. and tactical equipment/performance. The analysis requires Another issue encountered involved the fire hose couplings close evaluation of all conditions, factors, decisions and efforts that refinery operators used at its facility. The hoses had a made during a major incident. This detailed retrospective can thread specific to the company, a thread that was uncommon to empower incident command and better prepare response peroutside fire-response departments. When the hoses had to be sonnel in future events. married with the hoses from the aiding firefighting entities, the Fire personnel who keep the three key elements of effective necessary adapters were not available to make the crossovers. firefighting for flammable liquids close at hand will be successThis forced firefighting personnel to use duct tape and bailing ful. Simple, hardy equipment, high-quality foam concentrate, wire to hold couplings together on some hoses. A key lesson and a good understanding of the hazardous situation will relearned is when outside resources are being brought in, it needs main the three keys to success in reducing, preventing and to be confirmed that crossover adapters will be compatible. quickly extinguishing fires.

Each individual facility, when it calls for assistance, should enERIC LAVERGNE is an industry veteran with more than 25 years of commercial sure that mutual aid providers can tap into their system. After sales, industrial and on-the-job firefighting experience in the fire and hazard control firefighters successfully suppressed the refinery fire, the refincategory. He has a degree in occupational health and safety.

54 NOVEMBER 2012 | HydrocarbonProcessing.com

Special Report

Plant Safety and Environment R. CRUM, URS Corp., Baton Rouge, Louisiana; and B. BROBERG, URS Corp., Houston, Texas

Update on the greenhouse gas regulation by the US EPA The US Environmental Protection Agency (EPA) began regulating the emissions of greenhouse gases (GHGs) on January 2, 2011. Its long-awaited GHG controls guidance document, PSD and Title V Permitting Guidance for GHGs, was issued on November 10, 2010, and included over 450 pages of guidance and seven sector-specific white papers focused on controlling and reducing the emissions of GHGs through the use of best available control technology (BACT). All new major source permits not issued by January 2, 2011, were potentially impacted. Any new facility emitting more than 100,000 tpy of GHGs comes under scrutiny. Some facilities will have to install new controls, modify their permitting practices, and comply with significant new record-keeping, monitoring and permitting requirements.

The EPA requires US facilities to install BACT on all new major sources of pollutants controlled by the Clean Air Act (CAA). GHGs were added to that list of pollutants four years ago. BACT for GHGs are now being “defined” in the US. It is critical to note that each new permit ruling anywhere in the US sets a precedent for the next permit to be issued for the same source type. If a source in Maine installs a lower emitting unit, all other sources of the same type may have to install the same new controls unless they can show that the new controls are too expensive, not environmentally friendly or too energy consuming. As an example, a recent permit application in Indiana, where the applicant is proposing to install an onerous and costly carbon capture and sequestration (CCS) system, will set a precedent for all future construction of that source type.

FIG. 1 illustrates the process of how emission limits drop over time. Using NOx emissions as an example, the graphic shows the progression of how BACT for NOx was defined in the early 1980s at 175+ ppm and gradually progressed to today’s standard BACT for NOx, generally defined as 2 ppm–5 ppm. As more sources across the US, anxious to receive their permits, agreed to tighter controls, NOx emission rates plummeted.

GHG emissions will follow a similar track. We are now in the early days, and higher emissions are allowed. But as facilities, anxious to start construction, agree to progressively tighter emission limits, the allowable GHG emission rates will take a similar downward track. The EPA is already building a database of the various source types and the emission efficiencies achieved in practice. Permits issued later in 2011 were scrutinized to ensure they were at least as efficient as those issued earlier in the year. The downward progression in emission rates has

begun. Permits will become more stringent as facilities submit more efficient designs to earn their permits with minimal delays.

Background. The EPA was given approval to regulate GHGs

in 2007 when the US Supreme Court ruled that GHGs are an “air pollutant” under the CAA (Massachusetts v. EPA, 127 S. Ct. 1438). GHG regulations have been under active development since that time. The EPA initiated its onslaught of GHG regulations in October 2009 with the publication of the final GHG mandatory reporting rule. Just seven months later, in May 2010, it issued new corporate average fuel economy (CAFE) standards for light-duty vehicles that limited the GHGs for vehicle model years 2012–2016. That regulation was quickly followed by a second regulation only one month later ( June 2010) called the “Tailoring Rule,” which “tailored” the existing regulations to be more accommodating to the regulation of GHGs. Under the Tailoring Rule, the EPA now has oversight for any new sources exceeding 100,000 tpy of emissions of GHGs or modifications to sources exceeding 75,000 tpy.

Finally, in November 2010, the EPA issued its PSD and Title V Permitting Guidance for GHGs (updated March 2011).

The EPA also issued seven BACT white papers that summarize readily available information regarding control techniques and measures to reduce GHG emissions in specific industrial sectors, which are: • Refineries • Large industrial/commercial/institutional boilers • Nitric acid plants • Electric-generating units 1980

1990

Good combustion practices

175+ ppm NOx

Flue gas recirculation

1995

125+ ppm NOx

Low-NOx burners

2000

Ultra-low-NOx burners

2008

Ultra-low-NOx burners + SCR

80+ ppm NOx

30+ ppm NOx

2–5 ppm NOx

FIG. 1. How emission limits drop over time.

Hydrocarbon Processing | NOVEMBER 2012 55

Plant Safety and Environment • Pulp and paper • Cement • Iron and steel industry • Landfills.

These white papers are fairly generic and do not give unique insights into EPA inclinations with regard to how strict or lenient EPA regulators would be in 2011 as the initial GHG permits came across their desks. What levels of control would they require? What types of controls and emission rates would they require? A year ago, many industry pundits fully expected that the EPA would require expensive and onerous CCS on many new sources, including many refinery sources.

The range of source types coming under the EPA’s regulatory scrutiny today varies widely, from power plants to refineries to steel foundries. Similarly, the fuels used to fire these sources are equally diverse, ranging from biomass to tire-derived fuel, coal-fired and natural gas. The variation in source types and fuels in the permits processed by EPA gives us great insight into the EPA’s probable future directions.

Controlling carbon emissions. There are essentially three

strategies for reducing carbon emissions: 1. Reducing energy intensity 2. Reducing carbon intensity 3. Capturing and sequestering the produced carbon.

Strategy 1, reducing energy intensity, is likely to be the most prevalent GHG BACT approach used in the US for years to come: reduce energy usage per unit of production—for example, gallons of automobile gasoline produced per British Thermal Unit (Btu) of fuel consumed. The EPA is pushing benchmarking as one strategy for setting GHG BACT standards. It is actively encouraging industry to develop production efficiency benchmarks across an industry. In a sidebar, the Carbon capture and sequestration Reducing carbon emissions

Reducing carbon intensity

Reducing energy intensity FIG. 2. Three strategies for reducing carbon emissions.

Source size that emits 100,000 tpy of CO2 How large of a source emits 100,000 tpy of CO2?

A 200 million (MM) Btu/hr source fired with natural gas/ refinery gas emits about 100,000 tpy. A coal-fired source of 100 MMBtu/hr emits about the same amount of GHGs. A mid-sized refinery will emit 2 MMtpy.

56 NOVEMBER 2012 | HydrocarbonProcessing.com

example of a GHG BACT analysis conducted by the State of South Dakota for the Hyperion Energy Center is discussed. In this case, the state of South Dakota, desiring to know if a proposed refinery for their state was efficient, analyzed the facility by “benchmarking” it against all refineries in California.

Energy efficiency “benchmarking,” a major tenet in the EPA’s GHG BACT strategy, will be used more widely in the US going forward. Count on it being in future GHG BACT machinations. There will also be greater pressure to adopt more efficient processes over less efficient processes. Cogeneration facilities will be preferred over standard boilers and heaters.

Combined-cycle turbines will be preferred over simple cycle.

High-efficiency heat exchangers will be preferred over their cheaper, less efficient cousins.

Strategy 2 discusses the possibility of reducing carbon emissions by reducing carbon intensity. This is essentially fuel switching: reducing the ratio of carbon-to-hydrogen molecules in your fuel. For example, changing from a petcoke-fired heater (225 pounds of CO2/MMBtu) to a refinery fuel-gas-fired heater (120 pounds CO2/MMBtu) will reduce carbon emissions by approximately 45%.

While fuel switching sounds promising in theory, this poses serious challenges in most practical situations. For example, without a market outlet for the petcoke displaced by refinery gas (or natural gas), the strategy to switch to refinery gas is useless. Although certain applications exist where fuel switching can be implemented with minimal negative impacts on a facility, those applications are somewhat rare outside of the utility industry.

It should be noted that modifying an electric utility to burn low-cost natural gas instead of a higher-cost fossil fuel, such as fuel oil, is an obvious application that should have a fairly robust payback. Numerous utilities have already announced plans to switch from coal to natural gas, which should reduce their GHG emissions by approximately 45%.

The capital cost associated with switching and the potential need to find a market for the now unused fuel source will be major factors in any fuel switch, especially when carbon emissions, outside of California, do not cost a facility anything. That said, if the cap-and-trade schema spreads east from California and the emission of carbon molecules starts costing facilities, then the number of fuel-switching applications will escalate rapidly.

Strategy 3, CCS, is the most expensive and onerous of the three options for reducing carbon emissions. Even when a facility wants to capture a fairly pure CO2 stream (rare), the challenge can be enormous. The facility must identify a suitable repository, such as a nearby marginal oil and gas field—where it can be used for enhanced oil recovery (EOR)—a brine aquifer, an unmined/stranded coal seam, a basalt rock formation or an organic shale bed. Finding a suitable repository is a huge challenge that will not be possible for many, if not most facilities. And if a suitable repository within a reasonable distance is able to be located, the facility will then need to seek a permit for the development of a Class 6 underground injection control well (UIC Class VI), which is no small undertaking. Beyond that, investing considerable sums of money will be necessary to conduct the suggested 50 years of monitoring and verification recommended (and potentially required) by the oversight agencies.

Plant Safety and Environment This raises some questions: Will the corporate risk management staff allow the facility to commit the corporation to injecting millions of tons of a known asphyxiant into untested geological spaces beneath real estate not under the control of the company? Will the injection well be blamed for any and all small tremors that might occur during the next 50 years? And has the state solved the legal issue of “who owns the pore spaces in the subsurface,” an issue being hotly debated in several states?

Obviously, many risks exist in this scenario, most of which are liabilities not readily acceptable by industry today.

A second option for disposal of CO2 is to inject it into a nearby CO2 pipeline, but CO2 pipelines are rare in the US and far from most plants. Kinder Morgan, Denbury Resources and others have existing CO2 pipelines, but these outlets only cover a small portion of the US. Pipeline injection also means that CO2 must be compressed, cleaned and dried to the exacting specification of the pipeline company. Still, it is worth noting that the CO2 pipeline companies pay for the CO2 since they use it for EOR, offsetting a portion of the capital cost associated with CCS. As the CO2 market matures, it will attract smaller operators without the financial strength of a Denbury or Kinder Morgan.

Our conclusion, and the conclusion of the EPA, after its analysis of all three carbon reduction strategies, is that the sole reasonable solution to reduce GHG emissions is to reduce energy usage. Implement energy efficiency programs, equipment and processes. Produce more product with less fuel. Refiners must do more with less, something they have become quite skilled at in the last 30 years.

CCS. A year ago, industry expected to see EPA demands for

CCS to be widespread. Although CCS is not in widespread use at this time, the EPA generally considers it to be an available add-on pollution control technology for large CO2-emitting facilities and industrial facilities with high-purity CO2 streams, such as hydrogen plants.

Back then, there was fear that the EPA would force CCS installation on all fired sources, including standard refinery-gas-fired heaters and boilers at refineries even though CCS technologies had not been “demonstrated in practice” at any US refinery. There was an even greater fear of CCS being required on new hydrogen plants, especially after the EPA used a hydrogen plant as an example in its BACT guidance (Appendix H) and only dismissed the selection of CCS because the CCS would require a 500-mi pipeline to the nearest suitable sequestration site. Would it have been a different decision if the required pipeline was only 200 mi?

What about 50 mi? Was the EPA indicating that refineries need to start building pipelines?

At present, more than a year since the BACT guidance was issued, there have been no mandates by the EPA to require CCS installation on any sources, even though several permits reviewed by the agency this year had “high-purity CO2” streams emitted to the atmosphere. The EPA had said that high-purity streams would be a target of the agency in 2011, but it failed to act on that declaration.

Notably, the EPA asked almost every applicant with a major fired source to include CCS in their BACT analysis. The EPA fully recognized and stated in its comments that it expected CCS to be eliminated in the analysis due to cost or environmental issues.

But the EPA wanted to see it considered as one of the possible control options, at least in the initial analysis. So, applicants had

to include CCS as a control option under consideration but were allowed to eliminate it quickly in the BACT analysis as being too expensive and/or too energy intensive.

Avoiding the CCS imposition. As stated previously, while

the EPA has insisted that facilities consider CCS as an option in their BACT analyses, the agency has not imposed a requirement to install CCS on any facility—yet.

What types of arguments have facilities put forth to avoid imposition of CCS? There have been quite a few innovative strategies used by sources across the US to demonstrate the infeasibility of CCS at the current time and eliminate it from contention. Examples include: • Nucor Steel in St. James, Louisiana, argued that the EPA should not make the company capture its high-purity CO2 and force them to contract with an unregulated third party that had a CO2 pipeline just a few miles from Nucor Steel’s planned site.

• The Las Brisas petcoke-fired facility in Texas argued that the closest sequestration site being “field tested” is over 395 mi away.

• We Energies and many other applicants eliminated CCS from consideration since no suitable sequestration sites were near their facilities.

• The Hyperion Energy Center, a 400,000-bpd greenfield refinery planned for South Dakota, argued that the $650 million capital cost for a CCS system would equate to a $43 cost per ton sequestered, well above the $1/ton market price for a ton of carbon at the Chicago Carbon Exchange. They also demonstrated that the CCS process would require 400 MW of additional electricity and would emit several hundred tons of criteria pollutants on the already burdened local community.

New emission standards? GHG permits are unique creatures. Historically, permit conditions for fired sources contain

one-hour and/or 24-hour emission rates. However, with GHGs, instead of permits having an hourly emission rate (as with NOx , SO2 , particulate matter, etc.), emission rates will generally be stated as an annual rate: X tons/year. Since there are no one-hour or 24-hour ambient air quality standards for GHGs, there is no reason to control GHGs in the permit to these shorter time periods.

Refiners will also see a new type of emission rate in their permits. They will likely see a “benchmarking” emission rate that limits the level of GHGs emitted based on their level of produc-

Five-step BACT process The five-step BACT process has been an EPA policy since the early 1980s: 1. Identify all available control options for the source.

2. Eliminate technically infeasible control options.

3. Rank remaining technically feasible control technologies by control effectiveness.

4. Assess economic, energy and environmental impacts of each remaining option.

5. The highest-ranked technology remaining after Step 4 is selected as a BACT. Hydrocarbon Processing | NOVEMBER 2012 57

Plant Safety and Environment TABLE 1. Facilities scrutinized by the US EPA Name of facility

Description of facility

Location

Nucor Steel

Natural-gas-fired iron foundry

St. James Parish, Louisiana

PacifiCorp Energy

Lake Side 2 Project: A 629-MW combined-cycle expansion of an existing natural gas facility

Vineyard, Utah

We Energies

Biomass-fueled 50-MW power plant

Rothschild, Wisconsin

Mid-American Energy Company

Modifications to an existing coal-fired power plant

Salix, Iowa

Wolverine Power

A 600-MW coal- and biomass-fired power plant

Rogers City, Michigan

Hyperion Energy Center

400,000-bpd greenfield refinery

Union County, South Dakota

Abengoa Bioenergy

Biomass-fired power plant

Hugoton, Kansas

US Steel

Increased taconite production by 3.6 MMtpy

Ketac, Minnesota

Crawford Renewable Energy

100-MW tire-derived-fuel facility

Crawford, County, Pennsylvania

Mackinaw Power

Effingham Power Plant—Add two 180MW combined-cycle turbines

Rincon, Georgia

US Nitrogen

Greenfield H2NO3, NH4 and NH4NO3 plant—Major source for N2O (nitrous oxide) emissions

Green County, Tennessee

Showa Denko Carbon

Expand graphite electrode plant from 45,000 metric tpy to 85,000 metric tpy

Dorchester County, South Carolina

Elizabethtown Energy LLC and Lumberton Energy LLC

Addition of biomass as a fuel to two 215-MMBtu steam boilers

Elizabethtown and Lumberton, North Carolina

Beaver Wood Energy

34-MW wood-waste-fired power plant and wood-pellet manufacturing facility

Fair Haven, Vermont

Cricket Valley Energy Center

1,000-MW natural gas-fired combined-cycle electric generating facility

Dover, New York

Hoosier Energy

Eight coalbed-methane-fired reciprocating internal combustion engines (RICEs) Sullivan, Indiana

Kennecott Copper, subsidiary of BHP Billiton

Replace three of four coal-fired boilers with one combined-cycle combustion turbine

Magna, Utah

York Plant Holding

Addition of two simple-cycle turbines to existing facility

York County, Pennsylvania

Wolverine Power—Belleville

Convert simple-cycle to combined-cycle and add RICEs

Belleville, Michigan

Universal Cement

New Portland cement plant

Chicago, Illinois

University of Wisconsin—Madison

Four natural gas boilers added

Madison, Wisconsin

Interstate Power and Light

Ottumwa generating station, boiler upgrades

Ottumwa, Iowa

Christian County Generation

New IGCC plant

Taylorville, Illinois

Indiana Gasification

Convert coal and petcoke to pipeline-quality synthetic natural gas and capture CO2 Rockport, Indiana

Old Bridge Clean Energy

700-MW natural gas-fired combined-cycle power plant

Old Bridge, New Jersey

Essar Steel

Mining, ore processing, direct reduced iron (DRI) production and steelmaking

Nashwauk, Minnesota

Milwaukee Metropolitan Sewerage District

Five new landfill gas-fired turbines

Jones Island, Wisconsin

Newark Energy Center

655-MW natural gas-fired combined-cycle power plant

Newark, New Jersey

tion; that is, refiners should not be surprised to see emission rates stated as “X tons CO2/bbl of crude throughput” or “X tons CO2/bbl of diesel produced.”

In the last year, while the EPA commented on 29 permits, only one of those permits was for a refinery: the Hyperion Energy Center in South Dakota. What types of permit limits did it receive? Hyperion’s process heaters were limited to “33 tons of CO2e/1,000 bbl of crude received” while its acid-gas removal system was limited to “58.6 tons CO2e/1,000 bbl of crude received.” Overall, the Hyperion refinery will emit 16 MMtpy of GHGs. CCS paradox. The wisdom of Solomon may be required to properly render some permitting decisions to be made around 58 NOVEMBER 2012 | HydrocarbonProcessing.com

the country in the coming years. Permitting agencies will be faced with some difficult decisions related to the imposition of CCS systems on industrial facilities. The issues stem from the major parasitic loads of 20%–40% needed to power CCS systems. What does this mean? A new power plant with CCS will need to combust 20%–40% more fuel to generate the excess power required by the CCS add-on equipment (compressors, dryers, air separation units, etc.), which, in turn should result in 20%–40% higher emissions. For example, an 850-MW power plant with CCS would decrease CO2 emissions by 6 MMtpy while increasing NOx emissions by 400 tpy, SO2 emissions by 500 tpy and particulate emissions by 300 tpy.

Decreases of GHGs at the facility are laudable and will reduce the overall global emissions of CO2. Unfortunately, the

Plant Safety and Environment NOx, SO2 and particulate emissions have significant impacts on the local community and, unlike CO2 , which we exhale approximately 20,000 times a day, each of these pollutants have known health impacts. Should the permitting agency pollute the local community in order to “save the world?” What position will activists take? Current technologies require that we sacrifice the local community for the benefit of the global community. Interestingly, but perhaps not surprisingly, the environmental justice community has spoken out against CCS, and, in fact, received special provisions in California’s AB 32 cap-and-trade rule.

To the future. So, how can we know what the EPA might require of industry in the next year? The EPA has offered comments on about 29 GHG permits as of June 2012, and these comments offer good insight into what the future holds. How has the EPA defined BACT? Has GHG BACT become the onerous program expected a year ago? How have various states defined BACT? What control technologies have been accepted as BACT? Further, what type of controls have been required of facilities in the last 17 months?

TABLE 1 lists the 29 names and facilities that have been through the EPA process. The facilities range from coast to coast and vary from small 50-MW biomass-fired power plants to 400,000-bpd greenfield refineries. There are several coalfired facilities, as well as many natural gas facilities.

What edicts were issued by the EPA? How many facilities were forced to accept CCS? The answer is none in either case.

The EPA has surprised all watchers in the last year by what it has not done. While the EPA requested that almost every facility consider carbon capture in the BACT analysis, it has not forced a single facility to install carbon capture systems.

The EPA treaded very carefully during 2011. There was no “heavy hand.” Most observers who have been watching its every step have been quite surprised, as the EPA has been “unreasonably reasonable.” While there were new requirements and new costs for industry to bear; the concerns of a year ago were largely dissipated by the EPA’s almost complacent, laissez-faire attitude during the last 17 months. The EPA mostly commented on compliance-related issues, asking that a facility be required to install a CO2 continuous emissions monitoring system (CEMS) or to show a particular calculation in its permit.

The EPA has been strangely silent on the issue of CCS. New NSPS for refiners on the way. While the major source permitting process has not been much of a concern during the last year, there are serious concerns on the horizon. The EPA is not content with just the mandatory reporting rule and the tailoring rule; it is now actively working on a GHG new source performance standard (NSPS) for the refining industry. Any new sources that start construction on or after the date that the NSPS is proposed will likely be required to comply with the new NSPS. The EPA just issued a proposed NSPS for the utility industry in late March 2012; the refinery NSPS is the next major GHG regulation in the agency’s plans and it is scheduled for sometime this fall. The NSPS for electric utilities has emission standards so tight that it will effectively eliminate the construction of coal-fired power plants in the US. The proposed heat rate, a measure of efficiency, is equivalent to a natural-gas-fired

Hyperion Energy Center BACT analysis Benchmarking—Coming to a refinery near you. . .

In the GHG BACT analysis for the proposed 400,000bpd Hyperion Energy Center, a planned greenfield refinery in South Dakota, the 16 MMtpy of GHG emissions projected for the refinery were compared to the GHG emissions from all California refineries. Chevron El Segundo was found to have the most efficient process in their analysis. Since Hyperion was going to emit less GHG than El Segundo per barrel of production, the Hyperion facility was deemed to be efficient by South Dakota and the center received its permit.

Expect to see more energy efficiency benchmarking going forward, as it is a core strategy of the EPA, discussed in the BACT guidance document and the sector white papers. combined-cycle plant. Coal plants, even with CCS, may not be able to compete.

With the utility NSPS being that stringent, it is unlikely that the NSPS for refiners will be lenient. Refiners should fear the worst, and if a need for a permit is anticipated, it should be submitted quickly. Since the “effective date” of the new NSPS will be the date of the proposal, refiners must strive to have their permits in hand prior to issuance of the proposal.

Bringing it all together. It has been an interesting 17 months

with regard to the EPA’s new GHG regulatory regime, and it looks like it will get much more interesting as time moves forward. The EPA has surprised most observers in the past year with its “hands off ” stance. It has not been contentious at all; in fact, it has been mostly invisible with respect to requiring serious new GHG controls on industrial facilities. We have learned quite a lot over the last year about the EPA’s future direction, but many questions remain. With the EPA requiring facilities to spend as much as $5,000–$10,000 to eliminate a ton of NOx emissions, what is its expectation for CO2 , where facilities typically emit 1,000 times as much CO2 as NOx? How will regulatory agencies deal with the dilemma of polluting the local community while saving the world?

We know that new edicts are on the horizon. The EPA’s worrisome plans for the utility industry will be likely followed by new regulations for refiners in the near future. Last year may have been just the warmup for the main event. The soon-to-be proposed GHG NSPS for refiners could be an onerous and expensive new regulation that could spell trouble for an industry already facing tight margins.

RON CRUM is a vice president of URS Corp. in the company’s Baton Rouge office.

He is a mechanical engineer with 35 years of experience. Mr. Crum has been managing projects for URS for 22 years.

BRUCE BROBERG is a vice president of URS Corp. in the company’s Houston office. He is a meteorologist and a civil engineer. Mr. Broberg has worked on and managed projects both domestically and globally, and has 32 years of experience.

Hydrocarbon Processing | NOVEMBER 2012 59

| Bonus Report REFINING DEVELOPMENTS The world order in the global refining industry is changing.

Refining companies constantly balance the changes in fuel demand and properties along with tight crude supplies and heavier feedstocks. In planning for the long term, refiners need to be ‘flexible’ to adapt to changes that are beyond their control as discussed in this month’s Bonus Report.

Neste Oil’s Porvoo Refinery is one of the most advanced and versatile refineries in Europe.

Bonus Report

Refining Developments L. WISDOM, J. DUDDY and F. MOREL, Axens, Princeton, New Jersey

Consider new technologies to increase diesel yield from bottom-of-the-barrel products As crude oil and product prices continue to climb, there are economic incentives for refineries to increase the total distillate yield with increased selectivity toward diesel fuel. The debate continues over the pros and cons of simply adding a new delayed coker vs. a residue hydrocracker upstream of an existing delayed coker to improve overall liquid yield. The following commercial examples will explore both sides on how to find more distillates from every barrel of oil processed.

BACKGROUND The US has the greatest concentration of delayed cokers in the world. Of the 130 refineries processing 17.8 million bpd (MMbpd) of crude oil, 60 of these refineries use delayed coking (DC) to destroy vacuum residue (VR) and to increase the yield of distillates for further processing into transportation fuels.

The first delayed coker came online in 1929 at the Standard Oil of Indiana refinery located in Whiting, Indiana. At that time, crude oil was selling for $1.27/bbl in current dollars. Since then, the refining industry has gone through various economic cycles.

The most recent cycle started in 2000 with a consistent rise in the price of crude oil, which is about $100/bbl for WTI. In addition, two major shifts have occurred in the energy market; natural gas prices started declining in 2008 due to new discoveries, and the gasoline-to-diesel margin reversed in 2005 with diesel priced higher than gasoline. As a result of these changes, a study was conducted to explore how these shifts would influence a refiner’s decision on adding more crude capacity via a refinery expansion.

US MARKET FOR DELAYED COKING In 2010, the US had 60 delayed cokers as compared to 11 in Europe, 4 in the Middle East and 27 in Asia-Pacific. In the US market, delayed coking was the preferred choice for destroying the VR from medium and heavy crude oil. Of the 60 delayed coking units in the US, 55% in terms of capacity are located in PADD 3 (US Gulf Coast) and 13% are located in the PADD 2 market (US Midwest). The vast majority of these delayed coking units (DCUs) were installed when crude oil was below $20/bbl. In the last 10 years, Brent and WTI prices have risen at an unprecedented rate.

Historically, refineries have added incremental DC capacity as part of refinery expansions because it was considered to be low-investment, well-known and economically attractive option. But, with the new changes in market prices and the

increase in residue hydrocracking worldwide, is DC still the best option for a US-based refinery?

Case history 1. The following case history investigates an ex-

isting 100,000-bpsd refinery processing 100% Arabian Heavy crude. Expansion studies were conducted using both Arabian Heavy crude and Athabasca bitumen, with properties as listed in TABLE 1.

FIG. 2 is the front-end section of a typical refinery configuration; it uses a delayed coker to process the entire VR. Straightrun (SR) and delayed coker distillates are processed into naphtha, diesel and fluid catalytic cracking (FCC) feed pretreat hydrotreaters. Steam-methane reforming (SMR) is used to generate hydrogen.

FIG. 1. Delayed coker at Husky Energy’s upgrader at Lloydmininster, Saskatchewan, Canada.

Hydrocarbon Processing | NOVEMBER 2012 61

Refining Developments Two expansion configurations were investigated for this case study. The first case (Case 1) adds an additional 100,000 bpsd of Arabian Heavy crude and duplicates the existing 27,200-bpsd delayed coker. The expansion brings the total crude throughput to 200,000 bpsd. The battery limits are shown in FIG. 2; it includes the associated offsite and utilities.

It does not include the FCC unit or the post-FCC hydrotreater.

Case 2. The second case (Case 2) adds a 54,400-bpsd residue hydrocracker upstream of the existing delayed coker, which remains unchanged, as shown in FIG. 3. In this configuration, the residual hydrocracking unit is a single-train plant with a single reactor operating at 60% conversion of 975°F+ residue to distillates. A second variation of Case 2 (Case 2A) was also investigated with a variation in which the conversion level is increased to 70% and the crude throughput is increased to 300,000 bpsd to fill the existing DCU. To handle the increased feedrate and reactor severity for Case 2A, two reactors, in series with inter-stage separation was required for this single-train plant. With the higher conversion level in the residue hydrocracker, the total Arabian Heavy crude capacity was increased to 300,000 bpsd, and the existing DCU is still capable of processing the entire unconverted VR. TABLE 1. Options for refinery expansions Property

Arabian Heavy

Athabasca bitumen

27

8.4

2.85

4.92

1,680

3,900

75

325

CCR, wt%

7.9

13.5

C7 asphaltenes, wt%

2.5

9.5

°API Sulfur, wt% Nitrogen, wt ppm Ni + V, wt ppm

Distillation, wt% IBP–350°F

15.0

–

350–650°F

23.6

12.8

650–975°F

27.9

28.6

975°F+

31.9

58.6

Case 3. The final case (Case 3) examines the effect of switching from Arabian Heavy Crude to Athabasca bitumen (DilBit).

This is a variation of Case 2 (see FIG. 3) with the addition of a residue hydrocracker ahead of the existing DCU. Due to the high VR content in the crude, the crude rate to the refinery is only increased from 100,000 bpsd to 150,000 bpsd. In all cases, the product streams—naphtha, diesel and vacuum gasoil (VGO)—are treated to the same level of product quality.

ECONOMIC BASIS For this updated study, pricing data from the US Energy Information Agency (EIA) for the US as a whole and also for the PADD 2 (Midwest) and PADD 3 (Gulf Coast) were examined. The US prices for Brent, WTI and industrial natural gas for the last 10 years are shown in FIG. 4. Brent and WTI have tracked fairly close to each other, except for the last couple of years. The prices for DilBit (Athabasca bitumen) can be calculated from Western Canadian Select (WCS) synthetic crude, which is traded in Chicago, Illinois. There is a weak correlation between Brent and WCS prices except when the natural gas condensate (diluent) is removed from the WCS. To calculate the actual price of the bitumen, the cost of natural gas condensate is removed from the DilBit resulting in an average net price for the Athabasca bitumen at $68/bbl when Brent crude is valued at $100/bbl. This bitumen price is the same price as Hardisty heavy bitumen (12°API) at $68.35/bbl, quoted in January 2012.

Brent crude is used as benchmark crude for this study to determine gasoline and diesel margins based on historical trends. Natural gas prices increased from 2002 to 2005 due to a large demand and supply shortage, as shown in FIG. 4.

However, in 2006, the production of additional natural gas entered the market with tight shale gas formations; this started a downward trend in natural gas prices. At present, the average US industrial natural gas price is in the range of $4 to $5 per thousand standard cubic feet (scf), or roughly $30/bbl of oil equivalent (boe) basis.

Light gases to gas plant Naphtha HTU H2

SR naphtha Light gases to gas plant

Crude

Crude still

SR naphtha

Naphtha HTU

SR AGO

Diesel HTU

Naphtha to gasoline plant

Crude

Crude still

Diesel product Atmospheric residue

Atmospheric residue

Vacuum still

SR VGO

VGO HTU

VGO to FCC

H2 Vacuum residue

Natural gas Delayed coking unit

FIG. 2. Base case of 100,000-bpsd existing refinery.

62 NOVEMBER 2012 | HydrocarbonProcessing.com

H2 plant Coke product

SR AGO

Naphtha to gasoline plant

Diesel product

Diesel HTU H2

SR VGO

Vacuum still

VGO HTU

VGO to FCC

H2 Vacuum residue

Residue hydrocracking unit Unconverted vacuum residue

H2 Natural gas Delayed coking unit

H2 plant Coke product

FIG. 3. Case 2 of the 100,000-bpsd refinery with residue hydrocracker and expanded DCU.

Refining Developments

STUDY CASES A summary of the four expansion cases investigated is described here: Case 1: Add 100,000 bpsd of Arabian Heavy crude to the existing refinery using DC as the residue conversion unit.

Case 2: Add 100,000 bpsd of Arabian Heavy crude and install a residue hydrocracker, operating at 60% VR conversion ahead of the existing delayed coker.

Case 2A: Same as Case 2, with the residue hydrocracker op-

erating at 70% VR conversion and crude throughput increasing to 200,000 bpsd.

Case 3: Add 50,000 bpsd to the existing refinery and switch from Arabian Heavy crude to Athabasca bitumen. In this case, a residue hydrocracker was installed upstream of the existing DCU. In all of the cases evaluated, the SR and cracked products were hydrotreated to meet the product specifications, as shown in TABLE 3.

Expansion Case 1. The existing refinery crude capacity was doubled to 200,000 bpsd with Arabian Heavy crude. The 25 Whole US PADD 2 PADD 3 20 Gasoline-Brent spread, $/bbl

The gasoline-to-Brent price spread (gasoline price minus Brent crude price) is shown in FIG. 5. It reflects a general increase in gasoline margins from 2000 to 2007 and then a steady decrease thereafter. Importation of gasoline from Europe and the increase in ethanol blending into the US gasoline pool are decreasing domestic demand for this fuel. For the last three years, PADD 2 prices have been higher than the average US prices while PADD 3 prices have been lower than the national average. The diesel-to-gasoline margin over the same period is shown in FIG. 6. For this study, a price spread of $9/ bbl is assumed for gasoline to Brent crude, which equates to $109/bbl for gasoline when Brent crude is valued at $100/ bbl for the average US market. Slightly higher prices could be used for projects in PADD 2, based on these historical trends.

The price of diesel fuel overcame the price of gasoline in 2005, and it has remained higher than gasoline for the last six years. Consequently, there is more interest from refiners to increase diesel production. This would imply an increase in mildand full-conversion hydrocracking in the future. Based on the mentioned trends, an economic basis, as shown in TABLE 2, was determined.

15

10

5 1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

2012

FIG. 5. Gasoline-to-Brent price for US, PADDs 2 and 3: 1992 to 2012.

160 Natural gas WTI Brent

20 Whole US PADD 2 PADD 3

140 15

120

10 Diesel-gasoline spread, $/bbl

Cost, $/boe

100

80

60

5

0 40 -5

20

0 Jun-00

Jun-02

Jun-04

Jun-06

Jun-08

Jun-10

FIG. 4. Crude oil and natural gas prices: June 2000 to June 2012.

Jun-12

-10 1992

1994

1996

1998

2000

2002

2004

2006

2008

2010

2012

FIG. 6. Diesel-to-gasoline prices: 1992 to 2012.

Hydrocarbon Processingâ&#x20AC;&#x201A;|â&#x20AC;&#x201A;NOVEMBER 2012 63

Refining Developments total VR feedrate to the delayed coker is 54,400 bpsd. The new coker is a duplicate of the existing unit. The C5+ product yield from the delayed coker is 66 vol%. This product is then blended with the SR distillates and hydrotreated to meet the product specifications, as listed in TABLE 3. The overall liquid yield was 180,500 bpsd or 90.3 vol% on crude throughput, which includes liquefued petroleum gas (LPG), naphtha, diesel and VGO. The VGO is assumed to be routed to an FCC TABLE 2. Economic basis Item

Value

Operating, days per year

345

Offsites and utilities cost, % of process units

50

Investment contingency, %

20

Natural gas cost, $/thousand scf

5.00

Sulfur product credit, $/metric ton

20

Coke product credit, $/metric ton

10

Arabian Heavy crude price, $/bbl

92.48

Net bitumen cost, $/bbl

67.85

Brent crude (Ref. Price), $/bbl

100

LPG price, $/bbl

61

Gasoline price, $/bbl

109

Diesel price, $/bbl

114

VGO (FCC feed) price, $/bbl

105

Note: Reflects prices represents typical values in the marketplace during the period of 2009 to 2011 as reported by the US Energy Information Agency and by Natural Resources Canada.

TABLE 3. Product Specifications Item

Naphtha

Diesel

VGO

Sulfur, wt ppm

0.5 max.

10 max.

2,000 max.

Nitrogen, wt ppm

0.5 max.

Cetane number

– 40 min.

unit, which has a post-hydrotreater and can meet Tier 3 gasoline specifications. TABLE 4 summarizes the breakdown of the product yields.

Expansion Case 2. As in Case 1, the overall refinery throughput is doubled to 200,000 bpsd and all of the VR (54,400 bpsd) is routed to a single-train, single-reactor residue hydrocracking unit operating at 60% VR conversion. The unconverted residue (21,922 bpsd) is sent to the existing DCU with a nameplate capacity of 27,200 bpsd. The overall yields from the residue hydrocracker, the downstream delayed coker and hydrotreaters are listed in TABLE 4. All of the SR, residue hydrocracker and coker distillates are hydrotreated to meet the product quality specifications, as shown in TABLE 3. The overall liquid yield was 192,600 bpsd or 96.3 vol % on crude throughput including LPG, naphtha, diesel and VGO, which is routed to an FCC unit.

This case is very similar to the commercial residue hydrocracker/DCU at Husky Energy’s Lloydminster Upgrader in Saskatchewan, Canada (FIG. 7). The feed to this residue hydrocracker is about 34,000 bpsd of a blend Cold Lake/Lloydminster heavy residue, and it operates around 60% conversion. The entire unconverted residue from the residue hydrocracking unit is routed to a DCU to produce fuel-grade coke for export.

Expansion Case 2A. In this case, the residue hydrocracking unit conversion level is increased from 60% to 70%. The number of reactors is increased to two in series with inter-stage separation, but they still operate in a single train. The larger reactor volume is required due to the greater feedrate and reactor severity. With the higher conversion level, the refinery throughput can be increased to 300,000 bpsd, which results in a feedrate of 81,655 bpsd to the residue hydrocracking unit; the unconverted bottoms (24,503 bpsd) are routed to the existing DCU. The yields for this case are shown in TABLE 4 for the residue hydrocracker and DCU. As before, all of the distillate SR and residue hydrocracked/delayed coker products are hydrotreated. The overall liquid yield is 292,300 bpsd or 97.4 vol% on crude throughput.

TABLE 4. Product Yields Case 1 Feed type Configuration Resid HC conversion, %

Case 2

Case 2A

Arabian Heavy DC –

Resid HC 60

Case 3 Athabasca bitumen

Resid HC/DC 70

Resid HC/DC 68

Yields, vol% on crude LPG

1.81

1.79

1.2

1.49

Naphtha

24.73

25.32

25.2

14.06

Diesel

32.16

34.78

35.27

36.45

VGO

31.56

34.40

35.18

49.54

Total

90.26

96.29

96.86

101.53

Coke yield, metric tpy

3,114

1,431

1,706

1,647

H2, scf/bbl of crude*

490

800

875

1,840

Note: DC = Delayed coking Resid HC= Residue hydrocracker *Includes residue HC and/or DCU plus all three distillate hydrotreaters

64 NOVEMBER 2012 | HydrocarbonProcessing.com

Refining Developments Expansion Case 3. In this case, the crude type is switched from Arabian Heavy to a Canadian DilBit based on Athabasca bitumen. The feedrate to the refinery is expanded to only 150,000 bpsd of Athabasca bitumen (excluding the diluent, which is recovered and returned to Canada). The total feedrate to the diluent recovery unit is 216,900 bpsd, and it contains about 31 vol% of diluent. The relatively small increase in throughput is due to the high content of VR in the feed (58.6 vol% vs. 31.9 vol% for Arabian Heavy). The feedrate to the residue hydrocracking unit is 83,754 bpsd, and the feedrate to the delayed coker is 27,221 bpsd. In this case, the residue hydrocracking unit is a single train with two reactors in series with interstage separation and operates at 68% conversion.

STUDY RESULTS A summary of the cases processing Arabian Heavy crude is shown in TABLE 4. The most severe design conditions were associated with the cases processing the greatest percentage of cracked stocks and the highly aromatic bitumen feedstock.

Catalyst cycle lengths were set at 30 months. The product naphtha is routed to a catalytic reforming or isomerization unit, diesel to the ultra-low-sulfur diesel (ULSD) pool and VGO to the FCC/post treater for meeting Tier 3 gasoline specifications.

As expected, the total liquid yield is a function of the residue conversion level and the amount of hydrogen consumed in the liquid product, as shown in TABLE 4. Case 2 shows a 6 vol% increase in liquid yield from Case 1, which is about 4.2 MM bbl/yr of additional product (LPG, naphtha, diesel and VGO). By increasing the residue hydrocracker conversion from 60 vol% to 70 vol%, the total yield increases by 6.6 vol% over Case 1, which adds an additional production of 4.6 million bbl/yr of liquid product. The additional production translates into additional net revenue (product revenue less feedstock cost and operating cost), as shown in FIG. 8. The Case 1 expansion adds an additional $77 million/yr, while Cases 2 and 2A add more than $500 million net revenue/yr.

In contrast with the higher liquid yield, the coke production is reduced by more than 50%. Coke produced in Cases 1 and 2 are 3,114 metric tpd and 1,431 metric tpd, respectively, indicating that 54 wt% of the coke precursors were converted in the residue hydrocracker. When the residue hydrocracker conversion is raised to 70%, the conversion of coke precursors is increased to 63 wt%, reducing the amount of coke even further. Accordingly, Case 2A can process more feed without major modifications to the existing DCU. Selectivity to diesel fuel. Ebullated-bed residue hydrocrackers are more selective to middle-distillate production than other

Liquid yield. In residue hydrocracking, many of the coke 100

600 Product yield of conv. unit, vol% Incremental net revenue, $MM/yr

500

80 70

400

60 50

300

40

200

30 20

Incremental net revenue, $MM/yr

90

Product yield, vol%

precursors are hydrogenated, which results in higher liquid yield and reduced coke production. In addition, hydrogen consumption in the liquid product increases the API gravity, which, in turn, leads to greater volume swell and increased yield of transportation fuels.

100

10 0

0 Existing refinery

Case 1

Case 2

Case 2A

FIG. 8. Product yield of conversion unit vs. incremental revenue.

2.5

Diesel/gasoline ratio

2.0 1.5 1.0 0.5 0.0

FIG. 7. Husky Energy’s residue hydrocracking unit in Lloydmininster, Saskatchewan, Canada.

Case 1

Case 2

Case 2A

FIG. 9. Diesel/gasoline selectivity for Cases 1, 2 and 2A. Hydrocarbon Processing | NOVEMBER 2012 65

Refining Developments conversion technologies. With the margin between diesel and gasoline expecting to increase, the selectivity becomes more important to the refiner desiring to maximize the economic returns on projects. One measure of this selectivity is the ratio of diesel-to-gasoline production. As shown in FIG. 9, the selectivity of the conversion unit increases from the DC scheme (Case 1) of 1.5 bbl of diesel to 1 bbl of gasoline production to the residue hydrocracker/DCU (Case 2—at 60% conversion) and reaches the highest value 2.2 bbl of diesel to 1 bbl of gasoline for the res30,000

Expansion investment cost, $/bbl

25,000

Crude dist.

Conversion unit Hydrotreaters

Other Offsites Contingency

20,000

15,000

5,000 0 Case 2

Case 2A

Hydrogen consumption and volume swell. As shown in TABLE 4, the total hydrogen consumption for the expansion increases by 78% from Case 1 to Case 2A. This results in a total volume swell increase of 6.6 vol% on crude, which equates to an additional product of 13,200 bpsd for a 200,000-bpsd refinery. As mentioned previously, the base price of industrial natural gas used for this study is $5/thousand scf, which is about $30/bbl (boe basis). With gasoline and diesel selling for $109/bbl and $114/bbl, hydrogen consumption provides the refinery with an impressive uplift of $79/bbl to gasoline (i.e., $30/bbl H2 boe to $109/bbl for gasoline) and $84/bbl uplift for diesel production.

Alternate case when processing Athabasca bitumen.

The major results of this case are shown in TABLE 4. Processing Athabasca bitumen or other heavy Canadian crudes will provide economic advantages that include upgrading a cheaper feedstock with low-cost hydrogen to high °API transportation fuels.

Relative to Case 2A, Case 3 provides the highest total liquid yield on crude of 101.5% of total liquid product vs. 96.9% for Case 2A. This is due to the lower API gravity of the crude

10,000

Case 1

idue hydrocracker/DCU (Case 2A—at 70% conversion). For a 200,000-bpsd refinery, the diesel production would increase from 64,400 bpsd (Case 1) to 70,500 bpsd (Case 2A). The incremental increase of 6,000 bpsd translates into an annual revenue increase of $234 million for the refinery.

Case 3

FIG. 10. Investment costs for various expansion plans: Cases 1, 2, 2A and 3.

7

35

6

Case 1 Case 2 Case 2A

Case 3

30

5 25

4 Average US value

IRR, %

IRR, %

20

Case 2A

3 15

Case 1 2

10

Case 2 1

5

0

0

25

50

75 Brent price, $/bbl

100

FIG. 11. IRR vs. Brent price.

66 NOVEMBER 2012 | HydrocarbonProcessing.com

125

150

0

-10

-5

0

5 10 Diesel/gasoline spread, $/bbl

FIG. 12. IRR vs. diesel-to-gasoline spread.

15

20

25

Refining Developments and upgrading to about the same API gravity of the products.

This case also represents the highest production of diesel and VGO per barrel of crude for any of the cases examined.

For all of the cases, diesel production could increase further by adding a VGO hydrocracker during the expansion as compared to adding additional cat feed hydrotreating (CFHT) capacity upstream of the FCC unit. This would also improve the overall refinery diesel/gasoline ratio.

Operating cost for ISBL. The total operating cost, including fixed and variable operating costs, varied from $3.15/bbl of crude in Case 1 to $4.42/bbl for Case 2. Case 3, processing Athabasca bitumen, was the highest with a cost of $7.98/ bbl. The top two operating costs for the residue hydrocracking unit/DCU cases (Cases 2, 2A and 3) were natural gas plus catalyst and chemicals vs. natural gas and electricity for the delayed coker case (Case 1).

ECONOMIC ANALYSIS For the economic analysis, the same basis from TABLE 2 will be used. The investment cost for the expansion cases was only for new units and associated offsites and utilities whereas, the revenues and operating expenses were for the entire refinery.

Rate of return. The total net annual revenues (product reve-

Investment cost. Offsites and utilities were taken as a percentage of the total installed cost for the process units. FIG. 10 shows the investment cost breakdown for each of the investigated cases. The investment cost per barrel of crude for the new units varied from $14,800/bpsd to $22,400/bpsd with the delayed coker expansion at the lowest overall investment. For the expansion cases, the investment cost included new crude and vacuum units; conversion unit (delayed coker or residue hydrocracking unit); naphtha, diesel and VGO hydrotreaters, SMR hydrogen plant, sulfur plant, gas recovery section, amine regeneration; sour-water stripping; and corresponding offsites plus utilities.

nue less crude cost and total operating cost) varied from $169 million for the delayed coker expansion (Case 1) to $932 million for the residue hydrocracking/DCU expansion (Case 2A) based on an Arabian Heavy crude price of $92.48/bbl.

The product prices were $109/bbl for gasoline and $114/bbl for diesel.

As shown in FIG. 11, the addition of a residue hydrocracker upstream of a delayed coker is more profitable when Brent crude price exceeds $55/bbl. As light oil prices continue to climb, the IRR for the delayed coker expansion case falls to zero when Brent crude reaches $115/bbl. This is due to the low conversion (i.e., low product liquid yield) and high crude costs. This analysis assumes a constant $/bbl discount to Arabian Heavy crude and a constant $/bbl differential between the price of gasoline and diesel to the price of Brent crude. History tells us that variations will occur in both lightand heavy-crude price differentials as well as price fluctua-

Select 162 at www.HydrocarbonProcessing.com/RS

Hydrocarbon Processingâ&#x20AC;&#x201A;|â&#x20AC;&#x201A;NOVEMBER 2012 67

Refining Developments tions in the finished product prices of gasoline and diesel. For this reason, several sensitivity studies were conducted.

Sensitivity studies. During a sensitivity study, a number of questions were asked including, “What happens if the dieselto-gasoline spread continues to widen?” In all cases, the IRR climbs sharply by 6 to 7 percentage points for every $5/bbl the margin of diesel/gasoline increases. In the US Energy In100

Unit availability, %

95

90

85

80 75

formation website forecast, the margins are expected to keep climbing for the short term.

What’s the impact in processing Athabasca bitumen from Canada relative to Arabian Heavy? The IRR doubles from 24% in Case 2 to over 50% in Case 3. This is mainly due to the attractive price of Canadian bitumen ($68.85/bbl) vs. the price for Arabian Heavy ($92.48/bbl). The differential of $23.63/ bbl for feedstock cost provides a significant incentive for all cases processing Athabasca bitumen.

During a review of product prices in the US market, it was noted that higher margins for diesel fuel in PADD 2 (Midwest market) were $2/bbl to $3/bbl. The price variations in the diesel/gasoline spread varied between $5/bbl to +$17/bbl with a general increase occurring over the past five years. As shown in FIG. 12, an increase in the price of ULSD fuel vs. gasoline provides a tremendous uplift in the IRR for the project.

A project located in the Midwest would see the IRR increased by 4 to 6 percentage points, depending upon which expansion case is selected. The same general trend is evident when the gasoline-to-Brent crude price is increased.

Residue hydrocracking reliability. Residue hydrocracking

A

B

C D Commercial plants

E

FIG. 13. Onstream times for commercial advanced ebullated-bed hydrocrackers in operation.1

68 NOVEMBER 2012 | HydrocarbonProcessing.com

F

based on ebullated-bed technology is a mature technology, with 17 operating plants processing more than 650,000 bpsd of VR in North America, Europe, Middle East and Asia-Pacific. The reliability of the advanced ebullated-bed technology has improved over the last 44 years since the startup of the first plant for KNPC’s

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Refining Developments Shuaiba Refinery in Kuwait.1 Over the past 10 years of operation, the average availability of six commercial advanced ebullated-bed units was 96% (FIG. 13).1 This high level of reliability is the direct result of nearly 200-unit years of operating experience, automation of operations, pro-active reliability teams, improvements in the understanding of the chemistry of asphaltene conversion and stability through R&D, and ongoing improvements in critical equipment, components and process instrumentation. The plot shown in FIG. 13 reflects unit availability for six operating commercial advanced ebullated-bed units.1 Availability is defined as the actual onstream time less planned turnarounds (typically occur once every three to six years) and outages due to external factors (i.e., hurricanes on the Gulf Coast).

US Energy Information Agency, 2012 Annual U.S. Crude Oil First Purchase Price.

Wisdom, L., E. Peer. and P. Bonnifay, “Cleaner fuels shift refineries to increased resid hydroprocessing”, Parts 1 and 2, Oil and Gas Journal, Feb. 9, 1998.

LARRY WISDOM is a senior executive at Axens in charge of marketing the heavy-ends technologies in North America. The current portfolio of technologies includes the hydrotreating and hydrocracking of gasoil and residues, slurry-phase hydrocracking, solvent deasphalting and visbreaking. During his 30 year career, he has co-authored more than 30 papers on heavy-oil upgrading and holds two patents. Prior to joining Axens, he worked for Hydrocarbon Research Inc. (HRI) and FMC Corp. Mr. Wisdom graduated from the University of Kansas with a BS degree in chemical engineering and a MBA in marketing and finance.

JOHN DUDDY is the director of heavy oil and coal technology for Axens North America Inc. in Princeton, New Jersey. He is responsible for Axens’ ebullated-bed technologies for upgrading of heavy oil and coal. These technologies include H-Oil, H-Coal and Coal/oil co-processing. Mr. Duddy has been with Axens for 32 years and holds a BS degree in chemical engineering from Drexel University.

ACKNOWLEDGMENT Jim Colyar, a senior technology consultant, performed the revised internal study for which this article is based. The authors wish to acknowledge his work and contribution to heavy-oil upgrading.

1

EDITOR’S NOTE The process is Axens’ ebullated-bed technology.

BIBLIOGRAPHY Duddy, J., L. Wisdom, S. Kressmann, and T. Gauthier, “Understanding and Optimization of Residue Conversion in H-Oil”, Oct. 20, 2004.

Ellis, P. J. and C. A. Paul, “Delayed coking,” AIChE 1998 Spring National Meeting, New Orleans, March 8–12, 1998.

Largeteau, D., J. Ross, M. Laborde and L. Wisdom, “The Challenges & Opportunities of 10 wppm Sulfur Gasoline,” 2011 NPRA Annual Meeting, San Antonio, March 2011.

McQuitty, B., “Status of the Bi-Provincial Upgrader: H-Oil Operation and Performance,” IFP Seminar in Lyon, France September 1997.

FRÉDÉRIC MOREL is an expert director adviser for Axens’ marketing, technology and tech services department. He was formerly the manager of Axens’ hydroprocessing and conversion technical services group and the product line manager of VGO, resid and coal conversion. Mr. Morel has over 30 years of experience in oil refining, having worked previously with IFP’s Lyon Development Center as a research engineer, a project leader of distillates and residues hydroprocessing, and the manager of the development department. Mr. Morel holds a degree in chemical engineering from Ecole Supérieure de Chimie Industrielle de Lyon and a graduate degree from Institut d’Administration des Entreprises.

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Bonus Report

Refining Developments M. TELLINI and F. MANENTI, Politecnico di Milano, Milan, Italy

Low-pressure absorption of CO2 from flue gas: Plant economics with incentives The precedent to this article, published in the April 2011 issue of Hydrocarbon Processing, discussed the chemical feasibility and process engineering design to absorb carbon dioxide (CO2 ) from flue gas emissions at near-atmospheric pressure.1 The process investment and operating costs cannot be offset by the sole use or sale of the reclaimed CO2, and the regenerative absorption plant would only be sustained by ecologyoriented legislation or similar incentives.

CO2 emissions forecast and potential markets. To fix a reference for the year 2015, worldwide annual emissions from fossil-fuel-fed power plants alone are estimated to exceed 33 billion metric tons of CO2.2 The gas is diluted in the flue gas, which is mainly composed of nitrogen (N2); however, even pure, segregated CO2 appears to be a poor commodity to sell, based on economic evidence. Natural gas dehydration and CO2 removal produce large, unused quantities of the acidic gas, although the chemical inertness and properties of CO2 do not create a demand for comparable sales volumes.

Dry reforming of organic substances is another possibility for CO2 use; it has merits for the conversion of waste or toxic organic substances to generate CO and H2. The sale of such product gases does not sustain costs, unless tipping fees are recovered from all of the treated sources. However, this situation demands an amount of waste that is disproportionate for converting massive industrial emissions of CO2.3 Other niches for CO2 include the chemical and medical industries, beverage carbonation, fire extinguishers, the dry cleaning of clothes (with supercritical liquid CO2) and uses for solid CO2. However, these outlets will not absorb the significant gas volumes that could become available with CO2 capture from combustion operations. There are even applications in intensive agriculture, such as the control of atmospheric concentrations of CO2 inside greenhouses to intensify flower or vegetable growth, although this practice is also limited in its utilization of the gas.

Carbon tax. In the outlined scenario, commercial plant pos-

sibilities can be imagined where local legislation favors or prohibits a given process, or where financial benefits can significantly influence the economy of a plant. Wastewater treatment is a historical precedent, and capturing CO2 can be addressed by the general incidence of a carbon tax.

Pursuant to the recommendations of the Kyoto Protocol, some fossil-fuel-based power producers may have concerns

about a carbon tax, which is a tax on sending CO2 to the atmosphere. However, this kind of levy is applied in very few countries, and often only where a large volume of power is not generated from fossil fuels. The UK, France, Germany, Italy and Spain (to name a few) do not have a specific carbon emissions tax. Sweden has a carbon tax of €20/ton (t) of CO2 , and Finland’s CO2 tax is set at €18/t, although these rates contain provisions that allow payments to be deferred. New Zealand plans to impose a CO2 tax of €1.9/t, and the Australian senate passed a carbon emissions tax of around €20/t of CO2 over a three-year period.4 In Canada, Québec has a CO2 tax of €0.3/t, and British Columbia imposes a tax of €5.4/t of CO2 .5 However, Canada pulled out of the Kyoto Protocol in December 2011, following similar actions by Japan and Russia in 2010.6 Therefore, it appears that the tax deterrents for emitting CO2 are not very strong, and so building plants to capture CO2 emissions is not likely to be a critical concern for the industry.

Possible incentives to capture CO2 . From a different perspective, incentives to promote the generation of clean energy and CO2 emissions reduction function as deterrents for fossilfuel power producers. In Italy, for instance, green certificates exist for power generated from renewable energy sources.

These certificates are like credits or bonds in that they are earned through approved means by aeolic or hydroelectric power producers, and they are traded in a regulated market.

Since 2003, all Italian power producers have been required to generate at least 2% of their production as green power—or, to avoid sanctions, they must purchase green credits if they are unable to upgrade to cleaner technologies.7 It is estimated that over 50% of the forecast certificates have been purchased.8 The mandatory green-power level increases each year, and it is projected to reach a minimum of 7.55% for all producers in 2012.9 The value of green certificates was anticipated to escalate above €85/megawatt hour (MWh) in 2012, but they are presently traded at around €67/MWh, due to increased offers and lower incentives from the Italian government.10 The output of authorized green-power producers is much lower than that of fossil-fuel power producers. However, the authors believe that certificate trading would remain active as a method to achieve ever-greener production if loopholes were restricted.11 While a “pure green producer” would receive the entire income benefit of the bonds pertinent to its total proHydrocarbon Processing | NOVEMBER 2012 71

Refining Developments TABLE 1. Data for absorption/stripping main streams Stream number Name

6

3

Cooled flue gas

Absorber top

13

4

12

Rich amine

CO2 gas

5

15 Cool recycle

Overall Molar flow, kmol/h

3,698.259

3,151.393

13,588.629

13,588.629

540.206

13,048.423

13,048.423

Mass flow, kg/h

107,433.076

88,739.068

415,489.222

415,489.222

18,636.677

396,852.529

396,852.529

Temperature, °C

38.000

35.665

53.054

92.000

76.000

112.298

35.000

1.200

1.100

1.300

1.100

1.100

1.400

1.150

2,630.952

2,630.868

0.084

0.084

0.084

0

0

CO2

373.184

30.669

342.881

342.881

342.515

0.366

0.366

H2O

350.793

145.928

11,646.262

1,1646.262

197.586

11,448.677

11,448.677

O2

343.330

343.308

0.021

0.021

0.021

0

0

0

0.619

1,599.381

1,599.381

0

1,599.380

1,599.380

Pressure, bar Flowrates, kmol/h N2

C1–C2 ethanolamine

15 Offgas

Flue gas 1

Trim cooler

3 Absorber 8

Compressed flue gas 1

2

CO2 to dehydration and compression 12

9 14

Rich amine

4

6 13

3

7

Regenerator 2

11 Lean amine return 5 10

FIG. 1. Absorption/stripping main scheme.

duction, a conventional producer with no green power would purchase certificates for up to 7.55% of its total production.

Since the carbon content in crude oil is about 15 wt%, 1 t of fuel generates 3.18 t of CO2 and about 3.25 MW of electricity (MWe), at the average fuel-to-power conversion efficiency of 28%. Given an average oil price of €80/barrel (bbl) ≈ €450/t, the simplified equivalence becomes 1 MWe = 1 t of CO2 = 0.3 t of crude oil = €135 in fuel cost. The pure fossil-fuel power producer would thus dilute the green burden in the overall production; i.e., 1 MWe = 1 t of CO2 = (67 ⫻ 0.0755 + 135) = €140, which represents a fuel cost increase of 3.7%.

Cost figures are subject to change according to time and location, and an econometric model can frame the feasible remuneration for even partial CO2 recovery. In the recessionary climates of Europe and Northern America, it is improbable that heavy taxation or premium incentives will be applied; yet, legislation is the key vehicle for generating revenue through the capture, use or disposal of CO2 from industrial emissions.

Without incentives—or with rewards lower than the costs of capturing or converting CO2 —the Kyoto Protocol’s emissions-reduction intention will be nullified.

Description of CO2 -capture plant. The precedent to this article discussed the feasibility of absorption at varying de72 NOVEMBER 2012 | HydrocarbonProcessing.com

grees of efficiency. MDEA was preferred over primary or other amines, mainly because of its selectivity and low volatility— important factors for avoiding extra operating costs and posttreatment for odors. MDEA is highly resistant to thermal and chemical degradation, and the possibility of using MDEA concentrations in water up to 60 wt%, without incurring corrosion problems, allows for a reduction in the recirculation rate. Also, MDEA does not require the use of alloy steel equipment.

The molar concentration (M) of the circulating amine/water solution was selected at slightly higher than 4 M. Severe operating conditions were excluded; i.e., a 90% efficiency target was set for the absorption process—a specification achievable through the convergence of different process simulators, and one that would result in a sizable reduction in CO2 emissions from combustion. Since the plate efficiency is low with respect to CO2 , the theoretical absorber and stripper stages were both limited to 15 plates.

The regenerative absorption/stripping of the gas follows a straightforward scheme, without internal split streams. FIG. 1 is a conceptual scheme showing the main streams displayed in TABLE 1. The near-atmospheric-pressure flue gas is barely compressed to overcome pressure drops and to return it to the chimney after CO2 absorption. Prior to entering the absorber, the gas is cooled in both a contact condenser and a plate heat exchanger.

A subcooler for the entering gas was initially included in an attempt to reduce the water load to the absorber, but it has been eliminated because a considerable volume of water is kept under recirculation. Cooling water and low-pressure steam represent a significant burden for plant operation, which is one reason for tailoring the energy-optimization equipment.

Since the stripped CO2 is not fed to any other in-plant converter, it is sent to a dehydration unit and a high-pressure compression unit prior to storage or disposal of the CO2 . Such a unit—consisting of multiple, intercooled compression stages and the glycol regenerative absorption of the water—is not discussed in detail here. It is estimated as a standard package plant, since it has no specific features concerning the low-pressure treatment of flue gas.

Refining Developments TABLE 2. Major plant components, consumptions and estimated capital costs Description Flue gas blower

kW of electricity

kW of cooling

€ ⫻ 1,000

kW of heating

810

800

Absorber

440

Regenerator

200

Coolers

42,200

1,400

Heat exchangers

35,000

Pumps

50

Vessels and miscellaneous equipment

20

1,000 900

100

450

MDEA tank and first charge Dehydration and compression units

150 1,740

3,100

400

6,600

Distributed control system and instrumentation Electricals and motor control center

1,200 80

650

Piping

2,200

Field materials and structures

1,500

Erection

13,400

Engineering and management Total

2,100 2,700

1

2

45,400

35,400

32,990

1

Equals 1,950 m3/h of cooling water with 20°∆T 2 Equals 60 t/h of low-pressure steam

Estimated costs. Due to the selection of MDEA, the main

equipment and interconnections can be constructed with carbon steel or 304 stainless steel. Site-dependent solutions and layout have not been detailed in the preliminary design estimate. A complete takeoff of bulk materials, piping, insulation and painting was not made, and most of the field-erected materials have been estimated by calculating the main equipment costs through bare-module methods applied in common engineering practice.12 The estimated capital investment is summarized in TABLE 2, and it totals €33 million (MM) for an incoming flue gas capacity of 100,000 Nm3/h and a CO2 capture exceeding 90 vol% (112,860 t of CO2 /yr).

TABLE 3 presents operating costs for a stream year of 7,500 hours, calculated from estimated consumptions and multiplied by adjusted average rates.13 Electric power is a significant cost, for which the low-pressure absorption saves several MWh, although the ultimate dehydration and compression to high-pressure absorption is an inevitable expense if no specific use is foreseen within the plant.

The optimization of heat flows and actual consumptions are largely dependent on the site, the ambient data and the utilities directly available from the type of industrial complex where the CO2 -capture plant is installed.14 For instance, a dedicated cooling tower and a low-pressure steam-generation unit have not been considered, as they would likely be available from the service units of the main plant. The capital cost of extra equipment, such as a cooling tower, has not been included; however, the cost of the cooling water utility is included in the operating costs.

Whenever the reheating of flue gas to the chimney is required, cooling water in excess of 3 MWh can be saved through the use of a gas/gas exchanger, which recovers heat from the

TABLE 3. Primary costs for 7,500 hr/yr of plant operation Description

Quantity

Rate

€/yr

1

€37,000/yr per person

37,000

Electrical power

2,700 kW/h

€0.08/kWh

1,417,500

Amine makeup

80 kg/h

€110/t

66,000

Cooling water

1,950 m3/h

€0.015/m3

219,400

Low-pressure steam

60 t/h

€1.1/t

495,000

Dedicated operators

Total

2,234,900

compressed gas entering the absorber, plus other heat optimizations. Additional revenues or benefits could become available as a result of local conditions, such as the export of hot water to businesses, to households or to district heating, which would allow a substantial amount of cooling water to be saved.

Dedicated labor for the CO2 plant has also been minimized under the assumption that it is a simple addition to other personnel already employed at the same industrial facility.

Process economics. TABLE 4 shows the income statement for an example plant, with an assumed average inflation rate of 2%/yr (i.e., the discount rate for calculating the value of time-dependent fluxes of money). The plant’s sole income is assumed to be derived from hypothetical certificates valued at €95/t of CO2 . The table is constructed in current outlays, and inflow and outflow are not escalated on a yearly basis. However, Hydrocarbon Processing | NOVEMBER 2012 73

Refining Developments TABLE 4. Income statement (in € MM) for first 10 years of operation Year

1

2

3

4

5

6

7

8

9

10

0

0

0

0

0

0

0

0

0

0

Certificates

10.722

10.722

10.722

10.722

10.722

10.722

10.722

10.722

10.722

10.722

Total revenues

10.722

10.722

10.722

10.722

10.722

10.722

10.722

10.722

10.722

10.722

0.037

0.037

0.037

0.037

0.037

0.037

0.037

0.037

0.037

0.037

1.418

1.418

1.418

1.418

1.418

1.418

1.418

1.418

1.418

1.418

Amine makeup

0.066

0.066

0.066

0.066

0.066

0.066

0.066

0.066

0.066

0.066

Cooling water

0.219

0.219

0.219

0.219

0.219

0.219

0.219

0.219

0.219

0.219

Sales of CO2

Dedicated personnel Electric power

Low-pressure steam

0.495

0.495

0.495

0.495

0.495

0.495

0.495

0.495

0.495

0.495

Ordinary maintenance

0.330

0.330

0.330

0.330

0.330

0.330

0.330

0.330

0.330

0.330

Total costs

2.565

2.565

2.565

2.565

2.565

2.565

2.565

2.565

2.565

2.565

Gross operating margin

8.157

8.157

8.157

8.157

8.157

8.157

8.157

8.157

8.157

8.157

Depreciation

1.269

2.538

2.538

2.538

2.538

2.538

2.538

2.538

2.538

2.538

Operating income

6.888

5.618

5.618

5.618

5.618

5.618

5.618

5.618

5.618

5.618

Long-term burdens

−2.968

−2.968

−2.968

−2.968

−2.968

−2.968

−2.968

−2.968

−2.968

−2.968

Credit on debt-repaid portion

0.000

0.452

0.687

0.860

1.035

1.217

1.407

1.604

1.809

2.022

Initial investment repayment interest1

0.000

0.101

0.128

0.133

0.135

0.138

0.141

0.144

0.148

0.151

Interest/burden on previous net margin

0.000

0.042

0.035

0.038

0.039

0.041

0.043

0.046

0.048

0.050

Total burdens and interests

–2.968

−2.373

−2.118

−1.938

−1.758

−1.571

−1.376

−1.174

−0.964

−0.745

Residual cumulative loss

0.000

0.000

0.000

0.000

0.000

0.000

0.000

0.000

0.000

0.000

Income taxes

−1.816

−1.504

−1.622

−1.705

−1.789

−1.876

−1.966

−2.059

−2.157

−2.258

Net income (NI)

2.103

1.741

1.879

1.975

2.072

2.172

2.276

2.385

2.497

2.615

Cash flow (NI + depreciation)

3.372

4.280

4.417

4.513

4.610

4.710

4.815

4.923

5.036

5.153

Year-end financed investment residue

27.980

25.358

23.438

21.488

19.464

17.358

15.169

12.891

10.523

8.060

Actualization of 10 years NI2 Actualization of cash flow (less initial capital investment)2 IRR2 1 2

19.387 7.944 6.1%

At the 2% discount rate, plus half the spread with the long-term debt rate At the 2% discount rate

the cash flow is actualized under the assumption that first-year costs and revenues vary homogeneously. Depreciation also depends on local accounting practices; estimated plant costs were multiplied by their specific depreciation percentages in Italy and halved for the first accounting year. The mixed products yielded an average depreciation over a span of 14 years. In other countries—the US, for example—the depreciation would be accelerated to an average of 12 years, all other factors being equal. The salvage value of the plant is assumed to be zero.

The base model uses the average Italian taxation rate of 46.3%, and cheaper financing (e.g., a long-term loan with an interest rate of 4%/yr, to be repaid through the annual cash flow of the operation) has been assumed. There could be cases, not considered in the model, in which a substantial percentage of the investment is made available as a subsidized, interest-free grant. Working capital is kept at zero, as this operation is only an add-on to capture CO2 within a larger industrial complex.

74 NOVEMBER 2012 | HydrocarbonProcessing.com

Ten years of operation may prove to be an uncertain period of observation, due to mutable financial markets, legislative changes and inflation; however, a shorter period would not be adequate for the lifetime of a plant and its relevant outlays.

The income statement in TABLE 4 shows that a residual debt of about €8 MM remains after the first 10 years.

The 10 years of net income actualization brings the plant’s income to €19.4 MM, taking into account the initial investment of €33 MM. For the same simulation, the net present value (NPV) of the cash flow is nearly €8 MM, with an internal rate of return (IRR) of 6.1%—values that include the negative outlay of the invested capital. According to general practices of financial analysis, depreciation is not an expense, but instead a deferred tax deduction for the invested capital which reduces the net income. Therefore, the depreciation must be added back each year to ascertain the full appreciation of the calculated cash flow.

Refining Developments curves at the 2%/yr discount rate; however, this does not imply a convergence, but rather a reasonable starting point, 8

7

6

6

4

5 4

2

3

0

2 -2

1

-4

0

-6 -8

IRR, %

NPV cash flow, million €

In an attempt to reduce the investment burden, auto-financing has been assumed, rather than recurring bank loans that would penalize returns and the plant’s ability to break even. For the same reason, the entire income available during each year of operation is used to progressively repay the initial investment, and, later, to reduce the interest on the outstanding debt.

While these results may interest some industrial investors, the revenue incentive is the key variable. The plant payback drastically falls at €85/t of CO2 , and the IRR barely climbs above the discount rate for the minimum value of €82/t of CO2 . In fact, the NPV of the cash flow is practically zero, and there is no possibility of repaying the investment for capturing CO2 at such a low remuneration. The heating and cooling variables do not make a significant difference in this scenario.

Electric power is a substantial expenditure for multistage compression, prior to the disposal of the dehydrated CO2 . It must be observed, however, that halving the power consumption is less significant than is reducing the yearly financial discount rate by a quarter-of-a-point percent.

Given the same plant design, investment and incentives, the change of discount rates (between 2%/yr and 5%/yr) and the rate of borrowing capital (between 50% and 100% higher than the discount rate) are not very significant. To show the marginal effect of such variables, FIG. 2 displays the NPV sensitivity for variations at lower-value green certificates and at higher discount and financing rates. The chart initiates the

-1 –8.4 M€ at 67 €/t of CO2

–2.9% IRR at 67 €/t of CO2

-10 2

3

4

-2 -3

5

Discount rate, %/yr CF at 95 f = 2i CF at 95 f = 1.5i CF at 85 f = 1.5i

CF at 85 f = 2i CF at 82 f = 1.5i CF at 82 f = 2i

IRR at 95 f = 1.5i IRR at 95 f = 2i IRR at 85 f = 1.5i

IRR at 85 f = 2i IRR at 82 f = 1.5i IRR at 82 f = 2i

FIG. 2. Cash flow and IRR at various inflation and financing rates.

The variables are abbreviated in the legend; for example, “CF at 95 f = 1.5i” signifies cash flow (CF) calculated for green certificates of €95/t of CO2 and a financing rate (f) that is 50% higher (1.5) than the base interest actualization rate (i).

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Hydrocarbon Processing | NOVEMBER 2012 75

Refining Developments since the model would not make sense nor improve understanding at rates below worldwide inflation percentages.

The technical feasibility was expanded in terms of capital and plant operating costs, which were estimated with respect to potential revenues from a hypothetical CO2 tax or equivalent financial benefits. Although it is impractical in this brief account to provide references for all of the economic variables (positive or negative) assumed in the model, the final result is strongly dependent on legislation. Location and time are other important variables in such a study. Tailored design and cost analyses become mandatory to model the convenience of specific cases, if CO2 capture is a realistic option for power producers to meet legislative requirements.

LITERATURE CITED Tellini, M. and P. Centola, “Low-pressure absorption of CO2 from flue gas,” Hydrocarbon Processing, April 2011.

2 Ritter, J. and A. Ebner, “Carbon Dioxide Separation Technology,” Chemical Industry Vision 2020 Technology Partnership, http://www.chemicalvision2020. org, 2007.

3 Tellini, M., Hydrogen from Waste and CO2 Sequestration, AIDIC Series, Associazione Italiana di Ingegneria Chimica, 2005.

4 New York Times and CNN broadcasting, November 7, 2011.

5 Carbon Tax Center, “Where Carbon is Taxed,” http://www.carbontax.org, 2011.

6 Associated Press Toronto, http://www.CBSNews.com, December 13, 2011.

7 Italian Law Decree D. L. 79, 1999, and subsequent Law Amendment 239, 2004.

8 Rezzonico, S., “Certificati verdi in attesa di sblocco,” http://www.ilsole24ore.com, June 2010.

9 Cavriani, R., “Alla deriva il valore dei Certificati Verdi per eccesso di offerta?” http://www.reteambiente.it, 2011.

1

10

Canonico, C., G. Cenci et al., “Quantifying the price of green certificates,” http:// www.rinnovabili.it, January 28, 2011.

11 Tedeschi, E., “Dal CIP N. 6/1992 ai certificati verdi,” http://www.ambientediritto.it/dottrina, 2004.

12 Guthrie, K., Process Plant Estimating Evaluation and Control, Solana Beach, Craftsman Book Co. of America, 1974.

13 Peters, M. and K. Timmerhaus, Plant Design and Economics for Chemical Engineers, 4th ed., McGraw-Hill, New York, 1991.

14 Chauvel, A. et al., Manual of Economic Analysis of Chemical Processes, Istitut Français du Pétrole, McGraw-Hill, Paris, 1981.

MARCO TELLINI has over 30 years of experience in water, gas and waste treatments, and in the petroleum engineering and manufacturing of chemicals acquired in process design. He has worked in many senior capacities for international companies.

He earned a BS degree in chemical engineering from Politecnico di Milano and received an MBA degree from Fairleigh Dickinson University. While working in the US, Mr. Tellini became a licensed engineer in New Jersey, New York and Arizona. He earned a PhD in chemical engineering from Politecnico di Milano in 2005 and continued on in environmental engineering studies and post-doctoral research in the thermal processing of municipal and industrial wastes.

FLAVIO MANENTI is an assistant professor at Politecnico di Milano, the university where he earned his undergraduate degree and PhD. He teaches chemical process dynamics and control, along with chemical engineering courses. He has more than 10 years of experience in the field of modeling, control and optimization of industrial processes, and has co-authored more than 80 scientific papers for international journals and congresses, in addition to his work on Wiley’s book series for chemical engineers. Dr. Manenti has received international awards for his research activities and his lead on more than 20 breakthrough projects as a consultant for oil and gas and process automation societies.

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Bonus Report

Refining Developments J. ZHOU and S. VAIDYANATHAN, Fluor Enterprises, Inc. Sugar Land, Texas, and S. KAPUR, Apex PetroConsultants, Houston, Texas

Improve integration opportunities for aromatics units—Part 1 An aromatics complex is a combination of processing units that can be used to convert petroleum naphtha and pyrolysis gasoline (pygas) into the basic petrochemical intermediates: benzene, toluene and xylene (BTX). Accordingly, an aromatics complex has great versatility and can be configured in many different ways, depending on desired products, available feedstocks and investment capital.1 Integrated refining and petrochemicals facilities provide feedstock synergy and flexibility to quickly adapt to future market changes in both product quality specifications and product demand shifts. Such capabilities can maximize total profitability. Three case studies demonstrate how different configurations of an aromatics complex can capitalize on better integration between refining and petrochemicals facilities.

MODERN AROMATICS COMPLEXES In general, benzene and xylenes are present in the main feedstocks, but in proportions lower than market demand. In contrast, toluene is present in considerable excess. The excessive toluene, along with low-value heavier aromatics, can be converted to benzene and/or xylenes via an integrated modern aromatics complex. Flow schemes of fully-integrated modern complexes are shown in FIGS. 1 and 2. Both processes are designed to maximize the yield of benzene and/or paraxylene (PX) and sometimes orthoxylene (OX).

Benzene column

Raffinate

Toluene column

HA column

Benzene column

Raffinate

Toluene column

HA column

Reformate splitter Toluene conversion

Reformate splitter

A10+ PX

NHT A10+ MXs

NHT o-Xylene Xylene column

OX column

FIG. 1. Integrated aromatics complex to maximize benzene production.

Benzene Toluene

BT extraction Reforming

Toluene conversion

Naphtha

Feedstock selection. Reformed petroleum naphtha, or reformate, is the largest source of global aromatics supply. The next largest source is pygas byproduct from ethylene plants. Pygas contains a high proportion of aromatics, primarily benzene

Benzene Toluene

BT extraction Reforming

In the past, optimization of an integrated aromatics complex consisted mainly of economy of scale. Recent technical improvements, such as new-generation adsorbents, have allowed the single train size for PX recovery to increase from 400–500 thousand metric tpy (metric Mtpy) up to 1 million metric tpy (metric MMtpy). Compared to operation with previous generations, applying the latest adsorbents for the PX adsorption can result in increased processing capacity up to 30%.2 Another advancement is the latest generation of reforming catalysts that provide higher yields of aromatics and hydrogen, improved activity and lower coke make. New catalysts enable ultra-high-octane number operations, while reducing the reactor size for continuous catalytic regeneration (CCR) operations.

Finally, conversion improvements in processing excessive toluene and low-value byproduct C9 and C10 heavy aromatics to high-value xylenes and/or benzene have enhanced the overall efficiency of the aromatics complex.3

Naphtha

o-Xylene Xylene column

OX column

PX separation Isomerization

LEs

DeC7

FIG. 2. Integrated aromatics complex to maximize PX and benzene production.

Hydrocarbon Processing | NOVEMBER 2012 77

Refining Developments and toluene, and a smaller amount of mixed xylenes (MXs), which can contain up to 50% ethyl benzene (EB). Pygas is benzene rich, whereas reformate is richer in xylenes content. Most PX capacity is based on reforming petroleum naphtha.

Aromatics production based on natural gas liquids (NGLs) has been limited, mainly due to alternate disposition and availability. However, interest in NGLs for petrochemical applications is slowly growing. The Middle East condensate supply is set to double over the next five years due to massive investments in gas developments. Qatar’s condensate production will reach 780,000 bpd by 2015, thus establishing Qatar as the world’s largest condensate producers.4 This light, lowsulfur and, sometimes, aromatics-rich crude equivalent will likely play an increasingly important role in world aromatics production. In North America, shale gas developments will also support increased supply of NGLs.

Conversely, refineries that are integrated with aromatics production maximize benzene production in the reforming unit, as shown in FIG. 4. When catalytic reforming is used primarily for BTX production, a C6 –C8 cut [initial and final boiling points (IBP-FBP) 60°C–140°C (140°F–284°F)], rich in C6 , is usually applied.5 However, some aromatics complexes tailor the naphtha cut to fit downstream processing requirements. A heavier naphtha, with an end point (EP) of 165°C– 170°C (329°F–338°F), maximizes the C9 aromatic precursors in the reformer feed. If toluene conversion is incorporated into the aromatics complex, C9 aromatics become valuable sources of additional xylenes and/or benzene. The naphtha EP is usually set below 205°C (400°F) to eliminate precursors of polycyclic aromatics. These latter aromatics cause carbon laydown on catalyst and shorten the cycle life.

Naphtha quality for reforming. The quality of naphtha

Naphtha cut for reforming. In the reforming process,

pentanes and lighter components cannot be converted to aromatics; thus, these compounds pass through unconverted, isomerized and/or cracked to light ends. Because of their low octane value, they dilute the total reformate octane number and result in a higher than anticipated (C5+) octane-severity operation in the reforming unit. Due to the limits placed on benzene content in motor gasoline (mogas) by environmental regulations, many refineries that are not integrated with aromatics operations remove the benzene precursors, i.e., methylcyclopentane and cyclohexane, upstream of the reforming unit, as shown in FIG. 3, thus minimizing benzene levels in reformate. The benzene precursors are typically sent as feed to the isomerization unit and incorporated into the mogas pool.

FG/LPG to gas plant

FG

Crude

Crude distillation unit

Stabilizer

NHT

Naphtha

i-C6 to mogas

Mix C5 DeC5

Heavy naphtha

Naphtha from hydroprocessing, Diesel catalytic cracking, and thermal processes AGO

C6 to isomerization

De i-C6

Kerosine

Reforming

Reformate to mogas

Atm. residue

FIG. 3. Naphtha cut for catalytic reforming in a refinery.

i-C5 to Mercaptan mogas removal

i-C5 to treatment FG/LPG to gas plant

FG

Crude

Crude distillation unit

Stabilizer

NHT

Naphtha

Mix C5 DeC5

n-C5 to naphtha cracker

De i-C5

Heavy naphtha

NHT

Kerosine Diesel

Naphtha from hydroprocessing

Reforming

Reformate to aromatics complex

AGO Atm. residue

FIG. 4. Naphtha cut for catalytic reforming in aromatics production.

78 NOVEMBER 2012 | HydrocarbonProcessing.com

can be determined by its paraffins, naphthenes and aromatics (PNA) content—an indicator of suitability for aromatics production. Naphthenic feedstocks yield higher aromatics quantities than normal paraffinic feedstocks to reformers.

Very good process correlations were developed by reforming licensors using N+2A to predict aromatics yields at specified processing conditions. The higher this value (N+2A), the richer in naphthenes and aromatics the reforming feed.

A greater degree of processing severity is required to reform substantial percentages of normal paraffins into aromatics against a given research octane number clear (RONc) objective for the C5+ reformate.

Non-SR naphtha for reforming. Compared to straight-

run (SR) naphtha, the non-SR stocks such as fluid catalytic cracking (FCC) and coker naphtha with higher EP require a larger CCR regenerator to burn the additional coke on the catalyst. The reforming catalyst deactivation rate relative to SR naphtha increases significantly for FCC naphtha and coker or thermally derived naphtha, depending on the EP. Because of the nature of a coker naphtha (produced in a hydrogendeficient environment), the reformate yields will generally be lower than SR naphtha with comparable PNA. The difference appears to be in the C5/C6 naphthene ring distribution, with coker naphtha having a greater level of the less selective C5 naphthene rings. Processing thermally derived feeds results in lower product yields; these streams contain more C5 naphthenes.6 Contrary to non-SR naphtha, hydrocracker naphtha has catalyst deactivation rates and yields similar to SR naphtha, and, generally, it is a premium reforming feedstock due to its rich sources of aromatics and naphthenes.

Pygas cut for aromatics production. Pygas is produced as a byproduct of olefins production by steam cracking. The quantity and composition of the pygas varies with the feedstock cracked and cracker severity. Lighter feedstocks produce little pygas, but there may be sufficient aromatics contents in the resulting pygas from liquids crackers to justify extraction.

Naphtha crackers typically yield 20%–30% pygas byproduct. Hydrotreated heavy pygas C6+ has a significant octane value and contains important fractions of aromatics, primarily benzene and toluene, and a smaller amount of MXs, which

Refining Developments can contain up to 50% EB. The pygas C6–C7 cut, rather than a full-range C6–C8+, is preferred sometimes as a feedstock to aromatics complex because of the high proportion of less desirable EB in the C8 mixture. It is difficult to separate EB from MXs due to similar boiling points. Additionally, the high proportion of EB from the pygas could bottleneck the PX loop.

adverse impact that they have on catalyst life. Higher levels result in shorter cycles between catalyst regenerations, thus reducing the onstream efficiencies. The conversion of toluene is practiced by three basic techniques: • Toluene disproportionation (TDP) removes a methyl group from one toluene molecule (creating benzene) and replacing it onto the second toluene molecule (creating xylenes) • Transalkylation converts a mixture of toluene and A9/ A10 into xylenes • Hydrodealkylation (HDA) involves stripping the methyl groups from toluene, xylenes or heavy aromatics to produce benzene and methane.

BTX OPERATION OF REFORMER Catalytic reforming transforms naphthenes and paraffins into aromatics and isoparaffins. This process serves two main objectives in integrated refinery and petrochemical facilities: 1) Production of high-octane reformate for mogas blending, and 2) production of high-value aromatics for the petrochemical units. It also supplies considerable amounts of hydrogen needed for hydrotreating and hydrocracking in the refinery.

Reformed petroleum naphtha Deep desulfurization of transport fuels imposes additional hydrogen requirements on refineries. Re(reformate) is the largest source of formers associated with petrochemical production are increasingly being regarded as sources of MXs global aromatics. Integrating refinery for PX production, with benzene and toluene credand petrochemical plants can provide ited as coproducts. The more efficient CCR reforming units are increasingly used for this purpose rathfeedstock synergy and operating er than the older semi-regenerative reformers. Most new CCR reforming units designed for BTX proflexibility for both facilities. duction are run at a high-octane severity, producing reformate with a RONc of at least 104 and some as high as 108 if a maximum amount of xylenes is to be produced. One of the advantages of operating the CCR reforming unit at high severity is that the heavier fracHDA is often the most expensive route for producing bention C8+ of the feed is almost completely converted into correzene. Its facilities tend to operate only when the benzene price exceeds production cost. Selective toluene disproportionation sponding aromatics. Result: This fraction can be sent directly (STDP) processes only toluene and uses a shape-selective catto the xylenes-recovery section without extraction. Two ways alyst to produce a higher-purity stream of PX (up to 90 wt%) can be applied to change the processing severity of the reformas opposed to the conventional TDP, which produces an equier: 1) Adjusting the reactor inlet temperature, i.e., weighted librium mixture of xylenes (about 25% PX). The advantage of average inlet temperature (WAIT), and 2) changing the reacTDP lies in its ability to handle the transalkylation reaction as tor charge rate, i.e., the liquid hourly space velocity (LHSV). well as the disproportionation reaction, giving it advantages If a higher octane reformate is required, then the reactorthat the STDP processes cannot provide. inlet temperatures can be raised. If unit limitations do not alSome licensors have developed processes combining conlow a temperature increase, a boost in octane number can still ventional disproportionation and transalkylation. The quanbe achieved by reducing the charge rate, and thus lowering tity of benzene produced can be varied by adjusting the A7/ space velocity. The two major differences in the reforming to produce high-octane reformate and high-value aromatics are A9 ratio in the feed. If the A9 increased, the benzene yield will the operating pressure and feedstock selection. The operating decline and the xylene yield will increase. Alternatively, with pressure of a CCR-type reformer can be lower, thus maximizlimited A9 recycle, more benzene and less xylenes would be ing aromatics yield. generated. A9s recycle to the disproportionation/transalkylation unit is manipulated to a targeted PX production rate.

ADDITIONAL BENZENE AND XYLENES The excessive A9 , if any, can be sent to the mogas pool.

PRODUCTION WITH TOLUENE CONVERSION In a modern aromatics complex, the toluene conversion EB dealkylation vs. EB isomerization. There are two disprocess is integrated between BT extraction and xylene recovtinct types of catalyst for the xylene isomerization. Both cataery sections of the plant. All or part of the extracted toluene lysts are used to reestablish an equilibrium mixture of xylene is recycled to the toluene conversion unit rather than being isomers, essentially creating additional PX from the remaining fully withdrawn and blended into the mogas pool or sold for ortho- and meta-isomers. However, they differ in the handling solvent applications. of EB. EB-isomerization catalyst uses an isomerization reacThe toluene conversion process involves several types of tion mechanism to convert EB into additional xylene isomers. chemical reactions of toluene and sometimes C8–C10 aromatIn contrast, the EB-dealkylation catalyst uses a dealkylation mechanism to convert EB into a benzene coproduct. The EB ics. Conventional toluene conversion technologies are limited isomerization is equilibrium limited to approximately 30 wt% in their ability to process C10+ material, primarily due to the Hydrocarbon Processing | NOVEMBER 2012 79

Refining Developments EB conversion per pass. The EB dealkylation is not equilibrium limited, allowing up to 90 wt% EB conversion per pass.7 The proper selection of isomerization catalyst depends on the configuration of the aromatics complex, feedstock composition and the desired product slate. An EB-isomerization catalyst would usually be chosen when the primary goal is maximizing PX production from a fixed amount of feedstock.

Alternatively, an EB-dealkylation catalyst can debottleneck the PX loop by converting more EB per pass through the isomerization unit.

PX separation: Adsorption vs. crystallization. A xylene

isomerization unit is always combined with the PX separation process for PX recovery. Two major methods are used to separate PX contained in the xylene stream—EB, MX, OX and PX—in an equilibrium mixture produced via catalytic reforming of naphtha. One method is by multistage cryogenic crystallization separation. The other is by adsorptive separation—molecular sieve adsorbent with a strong affinity for PX. Although considered older technology, crystallization is still being used. The crystallization operation is significantly improved as a result of the richer feed such as that produced in a selective toluene disproportionation. Recoveries from a single-stage crystallizer can be increased from 65% to more than 90%, when the feed PX concentration is raised from about 25% (the equilibrium value of PX in MXs) to 90%.

Some licensors have developed a hybrid version of the process by combining the features of adsorption and crystallization technologies. The adsorption unit is placed upstream of the crystallization unit to produce a 95% pure PX stream, which feeds a single-stage crystallizer. The hybrid configuration is suitable for existing crystallization-based complexes as part of a revamp.8 Historically, crystallization technology was perceived to suffer from disadvantages such as low-temperature refrigerants for the freezing process and requiring more rotating mechanical equipment. The principal advantage of the adsorption over crystallization technology is the ability to produce 99.7 wt%–99.9 wt% pure PX at up to 97 wt% recovery per pass (vs. 99.5% purity and 60%–70% recovery for crystallization). The adsorption process has the additional advantage Refining facilities

Petrochemical facilities

Heavy naphtha Hydrogen Fuel gas/LPG Light ends

Aromatics complex integration. Fully integrated refining and petrochemicals facilities provide feedstock synergy and flexibility to adapt to future market changes in both product quality specifications and product demand shifts, thus helping to maximize overall profitability. FIG. 5 shows integrated refinery and petrochemical facilities consisting of aromatics complex, steam cracker and petrochemical-derivative units. The aromatics complex has synergies with both the refinery and the ethylene plant. Naphtha feedstocks can be optimized for the aromatics complex, as well as for the steam cracker. While light and paraffinic SR naphtha is the desired feed for the ethylene plant, the naphthenic and aromatic SR heavy naphtha is preferred for reforming to produce high-octane reformate for mogas blending and to produce high-value aromatics for the petrochemical units. The raffinate from the aromatics extraction unit is a paraffinic cut that has a low-octane value, making it unattractive for the refinery mogas pool. However, this raffinate is desirable ethylene plant feed. In addition, both the reformer and steam cracker produce aromatics (in reformate and pygas), thus allowing for economy of scale advantages when the streams are combined for aromatics extraction.

Next month. Part 2 investigates three case studies that demonstrate varying approaches to integrate aromatics complexes between refineries and petrochemical facilities.

LITERATURE CITED Johnson, J. A., “Chapter 2.1, Aromatics Complexes,” Handbook of Petroleum Refining Processes, McGraw-Hill, pp. 2.3–2.6, 2004.

2 Wantanachaisaeng P. and K. O’Neil, “Capturing Opportunities for Paraxylene Production,” www.uop.com.

3 Nexant Chem Systems, “Optimizing Aromatics Production,” PERP Report 05/06S6 February 2007.

4 Darwish, R. “Qatar the World’s Largest Condensate Producer by 2015,” March 7, 2011, http://www.english.globalarabnetwork.com.

5 Prestvik, P., K. Moljord, K. Grande and A. Holmen, Catalytic Naphtha Reforming, Marcel Dekker, New York, 2004, pp. 17–18.

6 Hydrocarbon Processing, “Refining Processes 2009,” September 2009, p. 266.

7 UOP, Isomar, www.uop.com.

8 Rault, J., C. Dupraz and F. Montecot, “Alternative routes to paraxylene production,” Petroleum Technology Quarterly, Spring 2004, p. 124.

1

10

A

Tol u

en

e

JUN (TOM) ZHOU was formally a process manager with Fluor at Sugar Land, Texas, and has recently made a career move to a major owner/operator. Over the years, he has been involved with many worldwide refining and petrochemical projects. His expertise includes feasibility studies, front-end engineering, and detailed engineering for catalytic reforming process and aromatics complex. He is a registered professional engineer in Texas and Louisiana.

SHANKAR VAIDYANATHAN is a technical director for downstream hydroprocessing with Fluor at Sugar Land, Texas. He consults for clean fuels and heavy-oil upgrading projects. Before joining Fluor, he worked for Chevron Lummus Global and Engineers India Ltd. Over the years, he has been involved with several hydrocracker and ULSD projects. Mr. Vaidyanathan holds a BE degree in chemical engineering from Annamalai University, India.

9

A,

Ethylene Steam cracker

Propylene C4s

Petrochemical derivative units

+ sC 9

ga

Hydrogen

Py

Hydrocracked distillate

Aromatics

BT extract raffinate Fuel gas Pygas C6+

Crude

i-C5 HCU LN Alkylate FCC gasoline Mogas/diesel pools Refinery HCU diesel HT diesel FCC LCO Fuel gas/LPG n-C5/naphtha

PX (o-Xylene) (Mixed xylenes) (Toluene) Benzene

of being able to accept a feed with substantial quantities of EB and other diluents and still maintain this level of recovery.

Polyethylene Polypropylene Styrene Polystyrene

FIG. 5. Interaction of integrated refining and petrochemical facilities.

80 NOVEMBER 2012 | HydrocarbonProcessing.com

SANJEEV KAPUR is an independent consultant, with Apex PetroConsultants, in the field of strategic planning and development of olefins-based petrochemical businesses and deployment of technologies for building best-in-class facilities.

He has held senior leadership positions focused toward development of large and complex olefins-based petrochemical facilities. He helps clients focus on the key success factors for large and complex projects. Mr. Kapur has over 30 years of industry experience and has been associated with Fluor, Shaw Stone & Webster, ABB Lummus Global, and Kinetics Technology International (KTI), now part of Technip.

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Special Supplement to

NORTH AMERICAN TURNAROUND AND MAINTENANCE 2012 How do project management practices guide turnaround execution? [T–84] CORPORATE PROFILES Maxon [T–89] Rentech Boiler Services [T–91] Safeway Services [T–93] Sulzer Chemtech [T–95] FabEnCo [T–96] Industrial Insulation Group [T–97] COVER PHOTO

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NORTH AMERICAN TURNAROUND AND MAINTENANCE

HOW DO PROJECT MANAGEMENT PRACTICES GUIDE TURNAROUND EXECUTION? L. AMENDOLA and M. A. ARTACHO, Universitat Politécnica de Valéncia, Valencia, Spain; and T. DEPOOL, PMM Institute for Learning, Valencia, Spain

The complex nature of turnaround maintenance projects leads to the development of various methods of managing plant turnarounds.

To discover the strengths and weaknesses of each approach during plant turnaround, it is useful to determine the main expert management approaches. Recent work identified 33 suitable project management practices linked to critical issues during the plant shutdown process in the hydrocarbon industry.

In this article, turnaround management styles have been identified that reflect the application of these 33 project management practices. Some 44 shutdown experts from 36 chemical firms took part in the study. The experts marked in a checklist which practices they were employing to manage their plant shutdowns. A hierarchical cluster analysis (HCA) was performed to group these experts according to their use and non-use of these project management practices (PMPs).

Three groupings of experts were identified that define the common approaches for managing major outage maintenance. The common practices being used by each group show the distribution of well-established PMPs among experts. Moreover, the practices unused by each group enable us to discover what should be done to improve expert performance in plant shutdown projects.

Introduction. Plant shutdowns involve processes, procedures, people and special issues that make them unique among maintenance projects.

The nature of project management required by turnaround maintenance work is different from the traditional forms of project management recommended for other types of maintenance projects. Some authors have highlighted the main factors that make plant turnaround management different from other maintenance projects.1,2 As plant turnaround projects are complex in nature, it seems reasonable to believe that different approaches to handling major outage maintenance would emerge among practitioners. However, the existence of different approaches for managing plant turnaround projects among practitioners has not been addressed in the literature.

The aim of this work is to determine the various approaches to managing plant turnaround projects by analyzing the current application of PMPs. The starting hypothesis is that various managerial patterns can be found among plant shutdown practitioners in the hydrocarbon industry. The main objective of this work has been to find the common patterns of use and nonuse of PMPs during the plant turnaround process.3 To do this, experts were asked to show which PMPs were used to manage their shutdown projects.

Once we discover which practices are currently used and which are not used by each expert, we can use clustering techniques to group experts with similar patterns of use and non-use. Each grouping represents a different style of plant turnaround management.

Finally, a frequency analysis of PMPs for each group will enable us to discover which PMPs are used by each group of experts. As these PMPs are connected to the main stages of the general shutdown process, it is not difficult to identify the management strengths and weaknesses for each group’s approach.

T-84

Literature review. There are many published studies describing the special needs and critical issues related to plant turnaround management.1,4,5,6,7 These studies emphasize the main differences between major outage maintenance and other types of maintenance frequently undertaken by plant operators. They also present methods, tools and best practices that fulfill the demands of plant turnaround projects. However, there is no reliable evidence that practitioners follow these methods and correctly put them into practice.

One study3 examined to what extent practitioners follow these methodologies by selecting the most critical issues related to the four stages of the turnaround process4 and then identifying the most suitable PMPs related to the selected set of critical issues. The researchers then studied the use and non-use of PMPs among experts, as well as the importance attributed to these PMPs. By relating real plant turnaround practices and PMPs, the researchers concluded that PMPs are insufficiently established in chemical industry plant shutdowns, despite the fact that experts clearly understand their importance.

Following this bottom-up approach and using PMPs again, the aim of this article is to identify different project management styles. It is worthwhile emphasizing that project management styles are not related to project manager style8,9 or to the way a team manages conflicts.10 A plant turnaround management style is defined as the common approach used for handling plant turnaround projects by a group of experts.

Methodology. The 33 project management practices3 established as the most suitable to manage plant turnaround projects in the hydrocarbon industry were used to prepare a checklist questionnaire. Some 44 experts from 38 chemical plants were asked to complete the questionnaire indicating whether they “use” or “do not use” each PMP in their current working practices during plant shutdowns.

The resulting data was subjected to hierarchical cluster analysis (HCA). HCA is an exploratory tool designed to reveal natural groupings within a data set that would not otherwise be apparent. HCA characterizes similarities among expert usages and non-usages of PMPs by examining interpoint distances representing all possible expert pairs in high-dimensional space. Clustering is achieved on the basis of a measured “distance” or “similarity” between experts. HCA calculates the distances between all experts using a defined metric.11 In this case, the “furthest neighbor” was used as a linkage method, and the pattern difference was chosen as a binary distance measurement in the HCA. The most similar experts were first grouped, and these initial groups were merged according to their similarities. Those experts that appear “distant” or dissimilar from the first group were placed in another cluster.

Eventually, all subgroups were merged into a single cluster as the similarity decreased. The effect was to produce a hierarchy of clusters that can be represented by a dendrogram. The plotting of fusion stage against fusion coefficients and the search for significant slope changes, along with the observation of the dendrogram, enabled determination of the number of expert clusters.

NORTH AMERICAN TURNAROUND AND MAINTENANCE 2012 HydrocarbonProcessing.com

NORTH AMERICAN TURNAROUND AND MAINTENANCE

TABLE 1. PMPs used in the checklist questionnaire

Closeout

Execution

Goals and tasks definition

Strategic planning

Project management practices (PMPs)

PMP number

Plant history review since last shutdown

P1

Database development of plant operation features to foresee and control possible events

P2

Database development of historical equipment failures to foresee and control possible events

P3

Use of reliability techniques to fit the project scope

P4

Use of reliability, availability and maintenance (RAM) methodology to define the scope

P5

Use of strategic planning techniques [Balance scorecard (BSC); Political, Economic, Social and Technological (PEST) analysis; etc.]

P6

Monitoring the supply of materials and equipment

P7

Risk database development and identification of possible affected areas

P8

Personnel assignment to manage identified risks

P9

Risk analysis to forecast and control probable failures

P10

Risk analysis to identify possible opportunities for improvement

P11

Identification of critical equipment during the turnaround process

P12

Risk analysis of critical equipment

P13

Use of risk analysis software

P14

Recording failures with failure modes and effects analysis (FMEA)

P15

Risk matrix application to set equipment requirements and frequency of inspection

P16

Development of mechanical plan with maintenance time and cost of critical equipment

P17

Use of Project Management Body of Knowledge (PMBOK) guide, or similar, to manage shutdown project

P18

Delimitation of the work list using the planning thought process

P19

Use of the optimization, cost and risk (OCR) methodology to plan and program turnaround

P20

Development of a mechanical plan with technical requirements of turnaround for critical equipment

P21

Creation of a plan with detailed work tasks and personnel assignments

P22

Use of the critical path method to schedule the turnaround project

P23

Use of the critical chain methodology to plan the turnaround project

P24

Use of decision tree tools to control event probabilities

P25

Use of project management software to program plant shutdown

P26

Use of team communication tools

P27

Use of earned value management

P28

Work-list update to control planned work

P29

Use of management of chance process to face unforeseen events

P30

Use of project management software for daily control of plant shutdown development

P31

Monitoring the effectiveness of risk control

P32

Reporting and documenting shutdown process, discoveries and needs for future work

P33

Once the experts were grouped, a frequency analysis was made to discover how many experts in each group used each PMP. By doing so, it became apparent which practices were employed by all groups, which practices were not employed by any groups, and which practices showed different use patterns between groups. Practices used by every group and practices used by no groups were removed from the management style definition study. The rest of the PMPs were those that facilitated the discovery of different styles of managing plant turnarounds.

The criteria to discard totally used and unused PMPs were as follows: • Totally used: More than 75% of experts in each group use the PMP

• Unused: Less than 25% of experts in each group use the PMP. When differences in the frequency of use of PMPs appeared among groups, usage was then classified into four categories: low use (use frequency < 25%); moderate use (use frequency between 25% and 49%); high use (use frequency between 50% and 74%); and intense use (use frequency between 75% and 100%).

Results. The 33 main PMPs used to prepare the checklist questionnaire can be seen distributed among the different phases of a shutdown project in TABLE 1.3

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TABLE 2. Percentage of experts using PMPs in each cluster* PMPs (P1â&#x20AC;&#x201C;P17) Cluster

P1

P2

P3

P4

P5

P6

P7

P8

P9

P10

P11

P12

P13

P14

P15

P16

P17

1

96.3

88.9

82.5

51.9

44.4

81.5

59.3

18.5

44.4

48.1

29.6

92.6

77.8

18.5

100

29.6

55.6

2

88.9

33.3

33.3

0

0

44.4

88.9

33.3

44.4

33.3

11.1

77.8

88.9

11.1

88.9

22.2

11.1

3

87.5

62.5

50

75

62.5

87.5

50

100

100

87.5

62.5

75

75

25

87.5

37.5

50

PMPs (P18â&#x20AC;&#x201C;P33) Cluster

P18

P19

P20

P21

P22

P23

P24

P25

P26

P27

P28

P29

P30

P31

P32

P33

1

25.9

81.5

25.9

63

100

88.9

40.7

18.5

74.1

96.3

0

70.4

88.9

92.6

22.2

92.6

2

77.8

88.9

0

55.6

77.8

88.9

55.6

22.2

88.9

77.8

0

88.9

55.6

100

66.7

100

3

87.5

87.5

37.5

25

75

50

12.5

12.5

100

100

12.5

62.5

100

100

50

100

*PMPs in green are used by all of the clusters; PMPs in red are used by none of the clusters.

TABLE 3. Summary chart showing frequency of PMP use PMPs Cluster

P2

P3

P4

P5

P6

P7

P8

P9

P10

P11

P14

P16

P17

P18

P20

P21

P23

P24

P29

P30

P32

1 2 3 Legend:

Intense use

Case 0 number

High use

Rescaled distance cluster combination 5 10 15 20

Moderate use

25

51 53 20 13 21 22 9 10 15 32 36 28 29 2 5 12 19 6 33 1 7 25 38 16 11 49 24 46 50 42 47 31 40 48 8 43 27 34 30 14 54 17 35 26

FIG. 1. Dendrogram showing hierarchical cluster analysis of PMPs. The results obtained following the HCA are shown as a dendrogram (FIG. 1) in which three well-defined clusters are visible. As can be seen in FIG. 2, a significant change of slope appears after Stage 40, and this change corroborates the existence of a three-cluster solution.

The final cluster solution leads to three clusters, one of which groups T-86

Low use

27 experts. The other clusters are smaller, with nine and eight experts, respectively, as can be seen in FIG. 1.

TABLE 2 shows the results of the frequency of PMP use analysis for each group.

TABLE 3 shows a color-coded summary chart derived from the PMPs, in which the frequency of use among clusters is different; i.e., PMPs that were widely used for all clusters and PMPs that were not widely used were removed from TABLE 2.

Takeaway. HCA using the established PMPs has enabled the grouping of experts into three clusters.3 However, TABLE 2 shows that 12 of 33 PMPs generate no differences among the groups, either because all the experts make intense use of them (10), or because they are used by none of the experts (2).

The 10 PMPs used by all groups are related to reviewing past events (P1); basic risk analysis12 (P12, P13 and P15); work list definition (P19); team management (P22 and P27); the use of project management software to plan, program and control project development (P26, P31); and reporting shutdown processes in closeout phases (P33). It could be said that the most essential PMPs are used by all groups of experts. The unused PMPs are related to the use of decision-tree tools to control event probabilities (P25) and earned value management (P28) (see Table 2).

These results are in line with previous studies on the use of PMPs among turnaround experts in the hydrocarbon industry.3 The set of 21 PMPs showed differences among the groups, and so enabled the authors to define three styles of plant turnaround management. The first cluster is the largest (27 experts) and can be defined as a basic performance group. Experts in this group perform well in the strategic planning phase. They make an intense review of past shutdowns (P1, P2 and P3) and use strategic (P6) and reliability (P4) techniques to fit the scope. Most of these experts control the supply of materials and equipment (P7) and develop a mechanical plan (P17). However, they

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show poor risk management (P5, P8, P9, P10, P11, P14 and P16), and they only make moderate use of RAM to define the scope. When it comes to defining goals and work tasks (second phase), this group should improve on the use of PMBOK management guides (P18), the use of OCR to program (P20), and critical chain methodology (P24). Finally, it could be said that this group completes a correct project execution phase, despite failing to monitor the effectiveness of risk control (P32).

Cluster 2 can be defined as a low-performance group. This group shows serious deficiencies in the strategic and planning phases, and reveals unsatisfactory scope definition (P4 and P5); serious faults in risk management (P11, P14 and P16); no maintenance planning (P17); and poor use of historical data (P2 and P3). However, apart from non-use of OCR in turnaround organization, the group shows no deficiencies in the remaining processes. It is worthwhile to note the intense use of PMBOK to manage the shutdown (P18), as well as the use of critical paths (P23) in setting goals and task definition, and the strong use of work list updating to control planned work (P29) in the execution phase. However, the deficiencies in early phases shown by this cluster have a highly negative effect on global shutdown project performance,13 and this may lead to expensive inefficiencies.

The third cluster can be defined as a high-performance group. Apart from a moderate use of risk matrix to set equipment requirements (P16) and the use of some risk-analysis software (P14), experts belonging to this group show an excellent use of PMPs related to the strategic and planning phase of the turnaround process. The group shows only a limited use of OCR to program (P20) and poor development of the mechanical plan (P21) in the goals and task-definition phase. Critical chain methodology (P24) is the only PMP that is unused by this group. In summary, this group shows an outstanding use of PMPs to manage turnaround projects.

The main deficiencies appear (to a greater or lesser extent among the groups) in the early phases of the general plant turnaround process.

Once again, this result, in line with other works,13 highlights the importance of early phases when it comes to improving and guaranteeing successful management performance.

It is important to stress that this work took into account only the use and non-use of PMPs among experts. No information about the level of performance achieved by experts using PMPs was gathered. Therefore, it is not possible to link the use pattern of clusters with management maturity levels. This article does not take into account how possible differences in project size, complexity, and the skills of project teams could affect the PMP-use patterns defined in this study. Future research is needed to measure the performance achieved in turnaround processes and to link these performances to the pattern of PMP use.

In summary, the use and non-use of PMPs enabled the utilization of HCA to group experts into three clusters with varying levels of performance. As a result, three different approaches to managing plant shutdown projects have been identified with low, basic and high use of PMPs. This result enables us to find deficiencies for each group in each phase of the general plant turnaround process. This information gives us insight into what must be done to improve expert performance in plant shutdown projects.

LITERATURE CITED 1

Brown, M. V., Managing Shutdowns, Turnarounds and Outages, Wiley Publishing Inc., Indianapolis, 2004.

2 Lenahan, T., Turnaround, Shutdown and Outage Management, ButterworthHeinemann, Burlington, 2006.

3 Amendola, L., M. A. Artacho and T. Depool, “Consider critical issues during a plant turnaround,” Hydrocarbon Processing, September 2011.

4 Amendola, L., Dirección y Gestión de Paradas de Planta, Espuela de Plata, Seville, 2005.

5 Lenahan, T., Turnaround Management, Butterworth-Heinemann, Woburn, 1999.

6

Levitt, J., Managing Maintenance Shutdowns and Outages, Industrial Press, New York, 2004.

McLay, J. A., Practical Management for Plant Turnarounds, 2003.

8 Müller, R. and J. R. Turner, “Matching the project manager’s leadership style to project type,” International Journal of Project Management, January 2007.

9 Li-Ren, Y., H. Chung-Fah and W. Kun-Shan, “The association among project managers’ leadership style, teamwork and project success,” International Journal of Project Management, April 2011.

10 Cheung, C. C. and K. B. Chuah, “Conflict management styles in Hong Kong industries,” International Journal of Project Management, December 1999.

11 Wilks, D. S., “Cluster Analysis,” International Geophysics, 2011.

12 Levitt, A., “Promised Joy: A Step-by-step Guide to Managing Project Risk,” New Standard Institute, 2007.

13 Amendola, L., T. Depool and M. A. Artacho, “Identification of the critical phases and decision-making criteria for the shutdown of chemical processing plants case studies: South America, Spain and Portugal,” International Journal of Industrial Engineering, March 2010.

7

.08 .07 .06 .05 .04 .03 .02 .01 0 1

3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43

FIG. 2. Fusion stage vs. fusion coefficient.

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MAXON

EXTEND PROCESS “UP-TIME” WITHOUT SACRIFICING SAFETY Maxon Series 8000 Safety Shut-off Valves and PSTrend partial stroke testing technology MAXON VALVES ARE KNOWN FOR THEIR RUGGEDNESS

Probability of Failure on Demand (PFD) Degraded SIL 1 Performance Range

Potential increased maintenance interval

0.010 0.009 0.008 0.007 PFD

The Series 8000’s claim of ruggedness is field-proven and comes from design and construction features which put Series 8000 in front of run-of-the-mill shut-off valves. Chief among them is the unique metal-tometal seating that actually wears IN, not out, with each cycle. The wide choice of special materials for body and trim provide excellent application flexibility for the most dirty of service. Series 8000 even meets tough Class VI leakage standards normally reserved for soft-seated valves, yet without the wear concern.

0.006

SIL 2 Performance Range

0.005

RELIABLE PERFORMANCE IN EXTREME TEMPERATURES

0.004

Series 8000 valves are made for reliable performance in extreme conditions—searing heat and bitter cold—providing sure closing at temps to –50°C (–58°F). They also meet API 6FA standards where valves must maintain leakage requirements when exposed to flame temperatures of up to 760–980°C for thirty minutes.

Series 8000’s global endorsements include FM, CSA, ATEX, CE, ATEX, IECEx, INMETRO, KTL, Hazardous Locations, Fire Safe, and carries safety assessment to IEC 61508, making them SIL-3 capable.

0.003 0.002 0.001

Years of 0 Operation

1

2

3

4

5

6

SIL 3 Performance Range

This graph suggests that maintenance would be required within 2 years for an untested valve versus 6 years for one with monthly PST testing.

KNOW THE TRUE CONDITION OF YOUR SAFETY INSTRUMENTED SYSTEM Even the highest-quality valves are subject to stressors which increase the probability of failure on demand and negatively affect SIL (safety integrity level) over long periods of service.

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The patented PSTrend functional logic then trends results from periodic testing, looking for indications of degrading valve performance, allowing operating personnel to plan ahead for service or replacement of faulty valves.1 The chart above shows the potential increase in maintenance intervals.

WON’T FREQUENT TESTING CAUSE PREMATURE WEAR? Maxon Series 8000 utilize metal-to-metal seats (that wear in, not out, with use) can actually benefit from frequent testing. This self-cleaning feature makes corrective action possible for a degrading valve by simply increasing the test frequency, fully leveraging 8000’s “wear in, not out” characteristics.

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O U R

E N G I N E E R I N G

AT

R E N T E C H

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RENTECH

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SULZER CHEMTECH

TOWER TECHNICAL BULLETIN Tray design features that reduce turnaround maintenance time BACKGROUND Column shutdowns can be costly. Production is halted and maintenance expenses accumulate without any offsetting revenue. Maintenance crews need to isolate, open, inspect, modify, repair, and close columns, all under pressure to complete work as expeditiously as possible.

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Lip-SlotTM Connection

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Quick Opening

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HYDROCARBON PROCESSING

NORTH AMERICAN TURNAROUND AND MAINTENANCE 2012

T-97

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

1. Title of publication: HYDROCARBON PROCESSING 2. Publication number: ISSN 0018-8190.

3. Date of filing: October 1, 2012 4. Frequency of issue: Monthly.

5. Number of issues published annually: 12 6. Annual subscription price: $199.00.

7. 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: Suzanne McGehee; 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 5E4, 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 5E4, United Kingdom 12. Tax Status has not changed 13. Publication title: Hydrocarbon Processing 14. Issue date for circulation data below: September 2012 15. Extent and nature of circulation-Average number of copies each issue during preceding 12 months. (A) Total number of copies (net press run)-23,579; (B) Legitimate paid and/or requested distribution; (1) Outside County Paid/ Requested Mail Subscriptons stated on PS Form 3541-10,777. (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-11,027. (4) Requested Copies distributed by Other mail classes through the USPS-28; (C) Total paid and/or requested circulation (sum of 15B1,2,3 and 4)-21,832; (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 Distributed Outside the Mail - 1,013; (E) Total Nonrequested Distribution (sum of 15d) - 1,013; (F) Total distribution (sum of 15C and E)-22,845; (G) Copies not distributed -734; (H) Total (sum 15F and G)-23,579; (I) Percent paid and/or requested circulation (15C/F x 100)95.57%. Actual number of copies of single issue

World Oil and Hydrocarbon Processing present:

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published nearest to filing date: (A) Total number of copies (net press run)-22,900; (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)-10,586. (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-10,983.

(4) Requested copies distributed by other mail classes through the USPS- 25 (C) Total paid and/ or requested circulation (sum of 15B1,2,3 and 4)-21,594; (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 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 - 780; (E) Total Nonrequested distribution (sum of 15d) -780; (F) Total distribution (sum of 15C and E)-22,374; (G) Copies not distributed- 526; (H) Total (sum15F and G)-22,900; (J) Percent paid and/or requested circulation (15C/F x 100)-96.51%.

16. This statement of ownership will be printed in the November 2012 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/ John T. Royall, President and Chief Executive Officer

Universal Gas Detection: What does it really mean?

We’ve all heard the term, universal gas detection, but what does it really mean. During this seminar you will learn about the next generation of fixed gas detection. In this truly universal world, it is important that you protect your people, improve system reliability and operational efficiency, and lower total cost of ownership.

During this presentation you will learn: • About the latest technologies in gas detection including the evolution of sensor management • What it means to have a universal fixed gas detection system • How to lower your company’s overall total cost of ownership around gas detection

OCTOBER 31, 2012

Speakers:

Moderator:

10am CST, 3pm GMT

Register at: HydrocarbonProcessing.com Aziz Khan Product Manager, Fixed Gas Detection Scott Safety

Conor Twomey Director, New Product Development Scott Safety

Nell Lukosavich Senior Editor World Oil

Hydrocarbon Processing | NOVEMBER 2012 99

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Select 208 at www.HydrocarbonProcessing.com/RS Hydrocarbon Processing | NOVEMBER 2012 101

SALES OFFICES—EUROPE

Bret Ronk, Publisher Phone: +1 (713) 529-4301 Fax: +1 (713) 520-4433 E-mail: Bret.Ronk@GulfPub.com www.HydrocarbonProcessing.com

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CT, DC, DE, MA, MD, ME, NC, NH, NJ, NY, OH, PA, RI, SC, VA, VT, WV, EASTERN CANADA Merrie Lynch Phone: +1 (617) 357-8190, Fax: +1 (617) 357-8194 Mobile: +1 (617) 594-4943 E-mail: Merrie.Lynch@GulfPub.com

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REPRINTS Rhona Brown, Foster Printing Service Phone: +1 (866) 879-9144 ext. 194 E-mail: RhondaB@FosterPrinting.com

INDUSTRY PERSPECTIVES continued from page 4.

“Cyber security and cyber threats are an ever-more complicated challenge for HPI companies, even as their equipment and workforce continue to age. As these companies seek to strengthen and modernize their cybersecurity systems, they need to take a holistic view of their business requirements. Technology solutions implemented through the control system, intrusion prevention, firewall and other technology are important, but comprehensive cyber protection frequently involves changing the company culture so that individual operators and other personnel are identifying vulnerabilities and then relying on standardscompliant solutions to mitigate risks.”

—DR. MARTIN TURK, Global Director, HPI solutions, Invensys Operations Management “Cybersecurity is critical to protecting refineries and petrochemical facilities, and we have taken tremendous steps to ensure our systems are safe against the increasing amounts of cyber threats facing our facilities. Our businesses have developed their own standards, technologies, controls, strategies and processes, as well as work with external sources to manage cyber-security threats.”

—DAN STRACHAN, Director, Industrial Relations and Programs, American Fuel & Petrochemical Manufacturers (AFPM) “Cyber security solutions are most effective when the supplier and user share responsibility. Users should seek a vendor who not only helps them implement various degrees of control network protection and fully manage their security functionality 24/7, but one that actively works with government entities, like the DOE Energy Roadmap, industry-specific programs, like NERC, Critical Infrastructure Protection (CIP), and other standards bodies, such as the International Society of Automation (ISA,) to develop new standards. This level of involvement allows the vendor to validate and adopt advanced cyber-security techniques and solutions that keep the user more secure, but more importantly, more vigilant.”

102

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—DOUG CLIFTON, Director, Critical Infrastructure and Security Practice, Invensys Operations Management

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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 Products & Chemicals Inc. .........43

(67)

RS#

www.info.hotims.com/41434-153

(53)

Hermetic Pumpen GmbH ...............70 (164)

Baldor Electric Company .............. 103 (65) www.info.hotims.com/41434-65

Hoerbiger ................................. 12-13 (151) www.info.hotims.com/41434-151

www.info.hotims.com/41434-160

www.info.hotims.com/41434-158 www.info.hotims.com/41434-157

www.info.hotims.com/41434-169

Invensys .......................................10 (69) (97)

www.info.hotims.com/41434-69

www.info.hotims.com/41434-86

Detector Electronics.......................39 (159) www.info.hotims.com/41434-159

Dixon Valve ..................................67 (162)

Safway Services, LLC .......... T-92–T-93

(81)

www.info.hotims.com/41434-81

(73)

www.info.hotims.com/41434-73

ITT Industries ................................. 2 (88) www.info.hotims.com/41434-88

Kobe Steel Ltd...............................82

Sherwin Williams ..........................22 (98) www.info.hotims.com/41434-98

Shin Nippon Machinery Co., Ltd. ..... 17 (152)

(83)

www.info.hotims.com/41434-83

Sulzer Chemtech, USA Inc...T-94–T-95 www.info.hotims.com/41434-92

Swagelok Co. .............................. 107

Linde Process Plants .................... 105 (85)

(92)

(87)

www.info.hotims.com/41434-87

www.info.hotims.com/41434-85

www.info.hotims.com/41434-162

FabEnCo, Inc. ............................ T-96 (168) www.info.hotims.com/41434-168

Flexitallic LP .................................. 5

(82)

www.info.hotims.com/41434-152

www.info.hotims.com/41434-97

Colfax Americas ............................30 (86)

Rentech Boiler Services...... T-90–T-91

www.info.hotims.com/41434-161

Industrial Insulation Group, LLC ...T-97 (169)

Borsig GmbH ................................27 (157)

RS#

Scott Safety .................................. 81

Idrojet ......................................... 48 (161)

BIC Alliance...................................38 (158)

Page

www.info.hotims.com/41434-82

HyTorc ..........................................45 (160)

www.info.hotims.com/41434-53

Company Website

www.info.hotims.com/41434-164

AW Chesterton Company ............... 18 (153)

CB&I ............................................ 50

Page

Website

www.info.hotims.com/41434-67

Axens ......................................... 108

Company

Maxon Corporation............T-88–T-89 (80)

www.info.hotims.com/41434-95

www.info.hotims.com/41434-80

(93)

www.info.hotims.com/41434-93

Flir Systems, Inc ............................24 (155) www.info.hotims.com/41434-155

FourQuest Energy..........................76 (166) www.info.hotims.com/41434-166

Global Vapor Control .................... 69 (90) www.info.hotims.com/41434-90

Gulf Publishing Company Events—EMGC ........................ T-98 Events—IRPC..............................87 HP Webcast ............................... 99 HPI Market Data 2013 ................6–7 HPI Marketplace .................100–101 HPCL ............................................28 (170) www.info.hotims.com/41434-170

Merichem Company.......................26 (84) www.info.hotims.com/41434-84

Total Safety .................................. 16

(71)

www.info.hotims.com/41434-71

Metso Automation......................... 21 (59) www.info.hotims.com/41434-59

Milliken Workwear ........................36

Team Industrial Services ............... 49 (95)

(61)

www.info.hotims.com/41434-61

Neptune Research .........................25 (156)

Trachte USA ................................ 102 (167) www.info.hotims.com/41434-167

Turnaround Welding Services .........34

(78)

www.info.hotims.com/41434-78

www.info.hotims.com/41434-156

Nucon International ..................... 68 (163) www.info.hotims.com/41434-163

Paharpur Cooling Towers, Ltd. ........29 (102)

UOP LLC ........................................32 Weir Minerals Lewis Pumps ............14 (94) www.info.hotims.com/41434-94

www.info.hotims.com/41434-102

Paratherm Corporation ................. 20 (154) www.info.hotims.com/41434-154

Pentair, Inc. .................................. 19 (64) www.info.hotims.com/41434-64

Winsted Corporation .....................75 (165) www.info.hotims.com/41434-165

Zyme-Flow Decon Technology .......53

(91)

www.info.hotims.com/41434-91

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.

104 NOVEMBER 2012 | HydrocarbonProcessing.com

Linde Process Plants, Inc. Accepting Challenges. Creating Solutions.

StarLNGTM The leading small-to-mid-scale standard LNG plant Linde Process Plants, Inc., a world leader in cryogenic technologies, has now translated the idea of product standardization into the LNG industry. These modularized plants cover about 90% of real life boundary conditions, and provide improved, simple and robust technology with high HQHUJ\ HIÄžFLHQF\ StarLNGâ&#x201E;˘ delivers a pre-engineered process design, standard documentation and modularized plant layout for shortest delivery time with minimum on-site construction.

Consider Linde Process Plants, Inc. for your next project.

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A member of The Linde Group Linde Process Plants, Inc. 6100 South Yale Avenue, Suite 1200, Tulsa, Oklahoma 74136, USA Phone: +1.918.477.1200, Fax: +1.918.477.1100, www.LPPUSA.com, e-mail: sales@LPPUSA.com

Control

LARRY O’BRIEN, CONTRIBUTING EDITOR Larry.Obrien@fieldbus.org

What’s new with FOUNDATION fieldbus—Part 1 FOUNDATION fieldbus continues to increase its installed base in the hydrocarbon processing industry (HPI). The organization continues to develop the technology, making it easier to use, creating certified training centers and increasing the FOUNDATION’S requirements for testing and registration of devices and host systems. FOUNDATION fieldbus is proof that a truly digital-open standard can survive and thrive in the marketplace. FOUNDATION fieldbus’ openness gives the ability to adapt to new technologies as they become available in the marketplace. Here is a brief update: Advancements in interoperability testing and registration. One of the founding principles of the Fieldbus Founda-

tion is the support of interoperability—the ability to operate multiple devices from multiple manufacturers, in the same system, without loss of functionality. The testing and registration process is the key to interoperability. With FOUNDATION fieldbus, interoperability is made possible in that devices and software must conform to the same standard.

Products bearing the FOUNDATION product registration symbol have undergone a series of common tests. End users can select the best device for a specific measurement or control task, regardless of the manufacturer. Users know the device will provide a consistent level of functionality and interoperability.

Testing and registration ensures that users can achieve the best return on fieldbus investments.

There are three basic paths for testing and registration within the Fieldbus Foundation—H1 testing for devices residing on the H1 network, health, safety and environment (HSE) testing for devices residing on the high-speed HSE network, and host profile testing for host systems. The Foundation has test kits ITK for each level of testing. For H1 testing, the 6.0 of the Interoperability Test Kit was released in 2010. The H1 ITK 6.0 has been updated to test for new, required field diagnostics capabilities, which standardize how all fieldbus devices communicate diagnostic data to the process control and asset management systems-regardless of the vendor.

All ITK 6.0 devices now support the latest advancements in field diagnostics per the NAMUR NE107 recommendation, which builds upon the existing, powerful diagnostic capabilities of FOUNDATION fieldbus equipment, and, at the same time, adds a greater degree of organization so that field instruments can represent their diagnostics in a more consistent way.

NAMUR NE 107: Presenting diagnostic data in context.

According to the NAMUR NE107 recommendation, “selfmonitoring and diagnosis of field devices,” fieldbus diagnostic results should be reliable and viewed in the context of a given application (FIG. 1). The document recommends categorizing 106 NOVEMBER 2012 | HydrocarbonProcessing.com

Status signal

Color

Symbol

Normal: Valid output signal Maintenance required: Still valid output signal Out of specification: Signal out of the specified range

?

Function check: Temporary non-valid output signal Failure: Non-valid output signal FIG. 1. Self-monitoring and diagnosis of field devices with codes and symbols standardize information for operator review.

internal diagnostics into four standard status signals. It also stipulates that configuration should be free, as reactions to a fault in the device may be very different depending on the user’s requirements. According to NE107, plant operators should only see status signals, with detailed information viewable by device specialists. This facilitates “information in context,” provided to the proper people at the right time, in the required format.

Using the NE107 recommendations for field diagnostics, the Fieldbus Foundation developed a profile specification enhancing the organization, integration and presentation of device diagnostics within fieldbus systems. The diagnostic profile includes a standard and open interface for reporting all device alarm conditions, and a way of categorizing alert conditions by severity. The technology facilitates routing alerts to appropriate consoles, based on user-selectable severity categories. The right information is sent to the right person without flooding the operator with alarms that are irrelevant. It also provides recommended corrective actions and detailed help.

Next month. In Part 2, updates describe new safety integrity levels for instrument and service provider programs.

LARRY O’BRIEN joined the Fieldbus Foundation as Global Marketing Manager in April of 2011. Prior to his job at the Foundation, he was research director for process automation at ARC Advisory Group, where he began work in 1993. As an industry analyst and market researcher, he covered the topics of process fieldbus, distributed-control systems, process safety, automation services business and intelligent field instruments. Mr. O’Brian has authored or co-authored numerous market forecast reports, strategic-level advisory reports and white papers for ARC and its clients, including all the major process automation suppliers.

He holds a BA degree from the University of Massachusetts at Lowell.

Make the unpredictable totally predictable.

© 2012 Swagelok Company

Swagelok® Pressure Regulators are now an even better choice for all your pressure regulator needs. Why? Well, alongside our proven experience and expertise, our range now covers sizes from 1/8 to 4 in. and all your regulator needs – high-flow capability, two-stage, back-pressure and vaporizing models. With our regulators you get accuracy, sensitivity and pressure stability. In short– total predictability. Exactly what you would expect.

Visit swagelok.com/pressure.

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Your objectives in focus Make the most of today’s and tomorrow’s challenges with leading-edge solutions from Axens - Clean and alternative fuel technologies - Petrochemicals - Energy efficiency - High performance catalysts & adsorbents - Revamps

Single source technology and service provider ISO 9001 – ISO 14001 – OHSAS 18001 www.axens.net Select 53 at www.HydrocarbonProcessing.com/RS