HP_2009_09 by androsov.info

SEPTEMBER 2009

HPIMPACT

SPECIALREPORT

TECHNOLOGY

Styrenics market endures downturn

REFINING DEVELOPMENTS

Harness the power of your company

Positive demand for plastics

Energy policy driving changes in fuel blending

Designing the LNG facility of the future

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SEPTEMBER 2009 • VOL. 88 NO. 9 www.HydrocarbonProcessing.com

SPECIAL REPORT: REFINING DEVELOPMENTS

Viewpoint

Maximize liquid yield from extra heavy oil

Greenhouse gas emissions: Characterization and management

Key representatives from the energy industry present their insights on how to achieve balanced energy policy while meeting the global appetite for energy, what is the future for alternative fuels, how to sustain profitability during economic downturns, and more Next-generation hydrocracking processes increase conversion of residues G. Butler, R. Spencer, B. Cook, Z. Ring, A. Schleiffer and M. Rupp

Proposed federal measures may require that refiners report and mitigate greenhouse gas emissions P. Gunaseelan, C. Buehler and W. R. Chan

Increase the flexibility of your Claus unit

‘Green up’ air and water pollutant control

Consider advanced modeling to control air emissions

Novel approach incorporates liquid redox methods to manage refinery sulfur loading G. J. Nagl Recycling spent activated carbon can offer economic benefits and environmental credits K. R. Tarbert

Improve efficiency of furnaces and boilers

Residue upgrading: Challenges and perspectives

Novel ‘control’ scheme optimizes operations and reliability of combustion units F. Rodríguez, E. Tova, M. Morales, M. A. Portilla, L. Cañadas and J. L. Vizcaíno New hydrocracking technology efficiently ‘cracks’ heavy end cuts for distillates D. Stratiev and K. Petkov

ROTATING EQUIPMENT Applying pumps with variable-speed drivers An evaluation carried out for a specific project demonstrated that the technology can result in lower operating and investment costs G. Nardozi

LNG DEVELOPMENTS

105

Designing the LNG terminal of the future New requirements dictate operational flexibility of the design S. P. B. Lemmers

MANAGEMENT GUIDELINES

113

HPIMPACT 19 Styrenics market hit further by economic downturn 21 Developing regions increase demand for plastics

Computational fluid dynamics methods improve designs for NOx reduction applications D. Dakshinamoorthy and A. Gupta

Cover The Pulau Bukom refinery is Shell’s largest refinery with a crude distillation capacity of 500,000 bpd. Established in 1961, this refinery is a key regional supplier of transportation fuels and products. Over 90% of Bukom’s products are export to Asia-Pacific and beyond.

COLUMNS 11 HPIN RELIABILITY Smart motor lubrication saves energy 13 HPIN EUROPE Refiners’ great plans look badly awry in 2009 15 HPINTEGRATION STRATEGIES Emissions rules demand flexible fuel terminal blending 17 HPIN ASSOCIATIONS What happened in Reno didn’t stay in Reno 122 HPIN CONTROL Temperature points on main fractionators

Effective standardization: Harnessing the power of your organization Applying these guidelines can effectively leverage economies-of-scale K. Smith

ENGINEERING CASE HISTORIES

117

Case 52: Problems with a blocked-in centrifugal pump The potential for overheating is one of many concerns T. Sofronas

DEPARTMENTS 9 HPIN BRIEF • 19 HPIMPACT • 23 HPINNOVATIONS • 27 HPIN CONSTRUCTION • 31 HPI CONSTRUCTION BOXSCORE UPDATE • 118 HPI MARKETPLACE • 121 ADVERTISER INDEX

GPC SOFTWARE REFERENCE GUIDE— FALL 2009 Following page 124.

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www.HydrocarbonProcessing.com Houston Office: 2 Greenway Plaza, Suite 1020, Houston, Texas, 77046 USA Mailing Address: P. O. Box 2608, Houston, Texas 77252-2608, USA Phone: +1 (713) 529-4301, Fax: +1 (713) 520-4433 E-mail: editorial@HydrocarbonProcessing.com www.HydrocarbonProcessing.com Publisher Bill Wageneck bill.wageneck@gulfpub.com EDITORIAL Editor Les A. Kane Senior Process Editor Stephany Romanow Process Editor Tricia Crossey Reliability/Equipment Editor Heinz P. Bloch News Editor Billy Thinnes European Editor Tim Lloyd Wright Contributing Editor Loraine A. Huchler Contributing Editor William M. Goble Contributing Editor Y. Zak Friedman Contributing Editor ARC Advisory Group (various) MAGAZINE PRODUCTION Director—Editorial Production Sheryl Stone Manager—Editorial Production Chris Valdez Artist/Illustrator David Weeks Manager—Advertising Production Cheryl Willis ADVERTISING SALES See Sales Offices page 124. CIRCULATION +1 (713) 520-4440 Director—Circulation Suzanne McGehee E-mail: circulation@gulfpub.com SUBSCRIPTIONS

Subscription price (includes both print and digital versions): United States and Canada, one year $140, two years $230, three years $315. Outside USA and Canada, one year $195, two years $340, three years $460, digital format one year $140. Airmail rate outside North America $175 additional a year. Single copies $25, prepaid. Because Hydrocarbon Processing is edited specifically to be of greatest value to people working in this specialized business, subscriptions are restricted to those engaged in the hydrocarbon processing industry, or service and supply company personnel connected thereto. Hydrocarbon Processing is indexed by Applied Science & Technology Index, by Chemical Abstracts and by Engineering Index Inc. Microfilm copies available through University Microfilms, International, Ann Arbor, Mich. The full text of Hydrocarbon Processing is also available in electronic versions of the Business Periodicals Index. ARTICLE REPRINTS

If you would like to have a recent article reprinted for an upcoming conference or for use as a marketing tool, contact us for a price quote. Articles are reprinted on quality stock with advertisements removed; options are available for covers and turnaround times. Our minimum order is a quantity of 100. For more information about article reprints, call Cheryl Willis at +1 (713) 525-4633 or e-mail EditorialReprints@gulfpub.com HYDROCARBON PROCESSING (ISSN 0018-8190) is published monthly by Gulf Publishing Co., 2 Greenway Plaza, Suite 1020, Houston, Texas 77046. Periodicals postage paid at Houston, Texas, and at additional mailing office. POSTMASTER: Send address changes to Hydrocarbon Processing, P.O. Box 2608, Houston, Texas 77252. Copyright © 2009 by Gulf Publishing Co. All rights reserved. Permission is granted by the copyright owner to libraries and others registered with the Copyright Clearance Center (CCC) to photocopy any articles herein for the base fee of $3 per copy per page. Payment should be sent directly to the CCC, 21 Congress St., Salem, Mass. 01970. Copying for other than personal or internal reference use without express permission is prohibited. Requests for special permission or bulk orders should be addressed to the Editor. ISSN 0018-8190/01. www.HydrocarbonProcessing.com

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HPIN BRIEF BILLY THINNES, NEWS EDITOR

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The Association of International Automobile Manufacturers (AIAM) filed comment with the US Environmental Protection Agency (EPA) opposing a waiver request that would allow the ethanol content of gasoline to be increased from 10% (E10) to 15% (E15). AIAM believes that it is premature for the EPA to approve the near-term distribution and sale of fuels containing more than 10% ethanol without further testing. Most vehicles operating in the US were not designed to operate on ethanol blends greater than E10. A range of problems could materialize such as harm or failure of the vehicle’s highly calibrated emission system. The consequence of potential equipment failure by using E15 fuels would also create a high risk for consumer dissatisfaction stemming from drivability problems and possibly economically damage automobile manufacturers and dealerships. AIAM is working with the US Department of Energy, the EPA and other involved industries to conduct studies to access the impacts from mid-level ethanol blends to the US fuels market.

The International Energy Agency (IEA) has jumped on the bandwagon with other organizations and analysts that see the world economy emerging from its stupor. The agency recently upped projections for world oil demand and output for the remainder of 2009 and the entirety of 2010. It expects average demand in 2009 to be 83.9 MMbpd, with 2010 world demand projected to 85.3 MMbpd. These numbers are both noteworthy increases over the IEA’s previous forecast. The IEA sees the increase happening solely because of demand growth in Asia, with its more detailed projections indicating flat growth in OECD countries. Information from a report outside the HPI still holds valuable information for those within. According to the Association of Electrical and Medical Imaging Equipment Manufacturers (NEMA), shipments of industrial control equipment contracted during the second quarter of 2009, as NEMA’s Primary Industrial Controls Index fell 6.5% versus the first three months of this year. Although this represents a much slower rate of decline than the first quarter’s 23% drop, shipments have declined nearly 40% from their cyclical peak and are at their lowest level in 18 years. On a year-over-year basis, the index posted its second consecutive record drop as it shed 35.4% versus the second quarter of 2008. The Primary Industrial Controls and Adjustable Speed Drives Index, a broader measure of demand for industrial controls, registered a 4.9% decline compared to the first three months of 2009, while shrinking more than a third versus the same period a year ago. The results of this report can be extrapolated out to apply trending to other industries reliant on industrial control equipment, like the hydrocarbon processing and petrochemical industries.

Catalysts continue to play a key role in helping refiners attain fuel standards cost-effectively, according to a new study from Frost & Sullivan. The increasingly popular trend of moving feedstocks to heavy sour crude oils is necessitating the shift of catalyst systems with higher conversion, selectivity and efficiency. Due to ever-tightening fuel specifications on sulfur and aromatic content, refiners regard hydroprocessing as a key methodology, the study says.

Honeywell recently acquired RMG Group for approximately $400 million. The goal of the acquisition is to strengthen Honeywell’s position in the clean energy industry, specifically natural gas. Based in Kassel, Germany, RMG’s main business involves natural gas measuring and control products, services and integrated solutions. RMG will be part of Honeywell Process Solutions (HPS), an arm of Honeywell that provides automation and control systems, safety systems, simulation technology, wireless technology and integrated facility and process security systems for industrial process manufacturers. HPS President Norm Gilsdorf said that the deal would increase value to customers of both businesses throughout the natural gas production supply chain. HP

■ Refining outages and gas prices Refining outages can have varying gasoline price impacts, but gaps in federal data limit understanding of these impacts, according to the US Government Accountability Office (GAO). The GAO evaluated the effect of refinery outages on wholesale gasoline prices from 2002 to September 2008. It concluded that some unplanned refinery outages, like the aftermath of hurricanes Katrina and Rita, had large price effects, but, in general, “refinery outages were associated with small increases in gasoline prices.” The GAO’s report indicated that planned outages generally did not influence prices significantly, the reason being that refiners likely built up inventories to meet demand prior to shutting down. For unplanned outages, the GAO said that “average price effects ranged from less than one cent to several cents per gallon.” One of the key factors influencing the size of the price increase after unplanned outages was whether the gasoline was branded (sold at retail under a refiner’s trademark) or unbranded (sold at retail by independent sellers). The analysis revealed that “during an unplanned outage, branded wholesale gasoline prices had smaller price increases than unbranded, suggesting that refiners give preference to their own branded customers during outages, while unbranded dealers must seek out supplies in a more constrained market.” The report also attempted to identify gaps in federal data. One conclusion from this section of the report was that data linking refiners to the markets they serve was inadequate for the GAO to fully evaluate the price effects of unplanned outages on individual cities. The US Department of Transportation (DOT) was also operating in an information vacuum, with holes in the data necessary for DOT accurately assess potential fuel pipeline infrastructure constraints. HP HYDROCARBON PROCESSING SEPTEMBER 2009

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HPIN RELIABILITY HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR HB@HydrocarbonProcessing.com

Smart motor lubrication saves energy Many decades of experience confirm the success of oil mist for rolling-element bearings in the operating speed and size ranges found in motors for process pumps. For the past 40 years, empirical data have been employed to screen the applicability of oil mist to pumps and electric motors. The applicability of oil mist is expressed in a rule-of-thumb that incorporates bearing size, speed and load. It uses the parameter “DNL” (D = bearing bore, mm; N = inner ring rpm; and L = load, lbs) and limits oil mist to values below 109, or 1,000,000,000. An 80-mm electric motor bearing, operating at 3,600 rpm and a load of 600 lbs, would thus have a DNL of 172,000,000—less than 18% of the allowable threshold value. While reference 1 focused on a diester-base oil and viscosity effects, it also established that equivalency of protection existed for the 32-cSt synthetic vs. 68-cSt mineral oils. Bearing service life matched the theoretically predicted levels with either lubricant, but the lower viscosity together with oil mist saved about 0.53 kW on the average pump set. Since publishing the energy savings potential of oil mist in conjunction with synthetic lubricants in 1980,1 superior additives technology has also yielded improvements. Because synthetic fluids are chemically different from mineral oils, one might expect effects that go beyond those attributable TABLE 1. How changes in lubes and application methods affect power losses Change

⌬ power loss per bearing

Total reduction

0.017

Sump: MIN 68 to SYN 32 Mist: MIN 68 to SYN 32

0.022

Sump MIN 68 to Mist MIN 68

0.080

29%

Sump SYN 32 to Mist SYN 32

0.085

31%

Sump MIN 68 to Mist SYN 32

0.11

38%

Total reduction

to viscosity relationships alone. Indeed, lubricant properties and application methods also affect lubrication effectiveness and the frictional torque to be overcome. Quantifying the energy savings potential. The potential cost savings through power loss reduction are quite substantial when we realize that industrial machines consume an estimated 31% percent of the total energy in the US. Reference 2 clearly established that power losses in rolling-element bearings could be reduced by as much as 37% (Table 1). The resulting savings with different lubricants and lubrication methods, i.e., sump vs. pure oil mist, are highlighted in the bar graph of Fig. 1. Prorating these savings to a refinery with 1,000 centrifugal pumps and their respective drivers could save in excess of $400,000 per year. These are realistic expectations and the higher cost of synthetic lubricating fluids is compensated by reduced maintenance requirements. While again making the case for oil mist lubrication and adding energy conservation to its other advantages, it should be pointed out that synthetics make longer drainage intervals feasible in conventional sump-lubricated pumps. In summary, electric motor lubrication by oil mist is highly advantageous. It saves both energy and labor costs. Sealing and mist drainage are well understood and have been thoroughly explained.3 Although oil mist will neither attack nor degrade the winding insulation on electric motors manufactured since the mid-1960s, mist entry and related sealing issues have been addressed by competent users and suppliers. Still, regardless of motor type, i.e., TEFC, X-Proof or WP ll, cable terminations should not be made with conventional electrician’s tape. The adhesive in this tape will last but a few days and then become tacky to the point of unraveling. Instead of inferior products, experienced motor manufacturers use a modified silicone system (“Radix”) that is highly resistant to oil mist. With this rating, modified silicone systems have consistently outperformed the many other “almost equivalent” systems. HP

35 30

Percent

25 2

20 3

LITERATURE CITED Morrison, F. R., Zielinsky, J. and James, R., Effects of synthetic fluids on ball bearing performance, ASME Publication, February, 1980. Pinkus, O., Decker, O., and Wilcock. D. F., “How to save 5% of our energy,” Mechanical Engineering, September 1997. Bloch, Heinz P., Practical Lubrication for Industrial Facilities, The Fairmont Press, second edition, May 2009.

10 5 0 Sump: min. 68 to syn. 32 FIG. 1

Mist: min. 68 to syn. 32

Sump: min. Sump: syn. Sump: min. 68 to mist 32 to mist 68 to mist syn. 32 syn. 32 min. 68

Percentage savings in frictional energy when changing lubricant type and lubricant application method.

The author is HP’s Reliability/Equipment Editor. A practicing consulting engineer with close to 50 years of applicable experience, he advises process plants worldwide on failure analysis, reliability improvement and maintenance cost-avoidance topics. Mr. Bloch has authored or co-authored 17 textbooks on machinery reliability improvement and over 460 papers or articles dealing with related subjects. This excerpt is from the recently released second edition of his book Practical Lubrication for Industrial Facilities, ISBN 0-88173-296-6.

HYDROCARBON PROCESSING SEPTEMBER 2009

I 11

In troubled times fierce global competition for premium crudes means that refinery units must have the flexibility to handle heavy, viscous, dirty crudes that increasingly threaten to dominate markets. And flexibility must extend to products as well as crudes, for refinery product demand has become more and more subject to violent economic and political swings. Thus refiners must have the greatest flexibility in determining yields of naphtha, jet fuel, diesel and vacuum gas oil products.

Why Do Many Crude/Vacuum Units Perform Poorly?

Rather than a single point process model, the crude/vacuum unit design must provide continuous flexibility to operate reliably over long periods of time. Simply meeting the process guarantee 90 days after start-up is very different than having a unit still operating well after 5 years. Sadly few refiners actually achieve this—no matter all the slick presentations by engineers in business suits!

modeling. Refinery hands-on experience teaches that fouling, corrosion, asphaltene precipitation, crude variability, and crude thermal instability, and many other non-ideals are the reality. Theoretical outputs of process or equipment models are not. In this era of slick colorful PowerPoint® presentations by well-spoken engineers in Saville Row suits, it’s no wonder that units don’t work. Shouldn’t engineers wearing Nomex® coveralls who have worked with operators and taken field measurements be accorded greater credibility?

In many cases it’s because the original design was based more on virtual than actual reality. There is no question: computer simulations have a key role to play but it’s equally true that process design needs to be based on what works in the field and not on the ideals of the process simulator. Nor should the designer simply base the equipment selection on vendor-stated performance. The design engineer needs to have actual refinery process engineering experience, not just expertise in office-based

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HPIN EUROPE TIM LLOYD WRIGHT, EUROPEAN EDITOR tim.wright@gulfpub.com

Refiners’ great plans look badly awry in 2009 In September 2004, with anticipation of that year’s European Refining Technology Conference, I summoned up an image of a ring of refining VPs around the Atlantic basin looking at billiondollar investments to expand and upgrade their sites and wondering whether to say, “Okay, let’s do it.” What they would have given then to have the perspective that we have now. Reasons to raise capacity. In 2004, there were reasons to be expansive. New fuel specs had been good for business. European Brent cracking margins had risen after changing to 50-ppm-sulfur fuels. In the summer of 2004, that same average margin, as measured in BP’s global indicator, broke ground above $5, while West Texas sour coking margins were approaching $10. It was easy to go along with a crowd believing that the refiners’ boat had finally come. But as we know, investing in 2004 wasn’t a straightforward decision. There was also an underlying sense of damned if you do, damned if you don’t. Looking for the Golden Age of refining. In 2004, mar-

gins were on the up; as such, most refiners made step investments over and above the upward creep capacity increases at each major turnaround. Hydrocracking in Europe was the thing, while US refiners were reconsidering the gasoline shortfall and contemplating satisfying it themselves. Everyone knew that, if they all went ahead and signed off on the investments, then oversupply could trash the economics. The flip side of the dilemma was that, if they did nothing, demand could crumble in the face of the ensuing price rises. So, there we were with approaching 500 projects being drawn up. Early adopters were already bolting together iron or clearing ground. Sweden’s Lysekil refinery had the foundations finished for its new Isocracker. Neste had earthmovers onsite for its one million-bpd (MMbpd) hydrocracker. TOTAL had its plans underway for the $550 million hydrocracker at Normandy, and the Cepsa Huelva refinery in Spain had ambitious plans too. The Golden Age of refining was arriving. But so was the other side of the dilemma. As we approached the ’04 conference, I’d been speaking to a source in the economics department of a major European refiner. He had a warning, “The risk that high prices could provoke a synchronized US/Chinese economic slowdown is low, but it can’t be ruled out.” A “synchronized slowdown” was just a stretch or two beyond serious contemplation. Movers and shakers. By the 2006 ERTC, most players had made their plans public. Early movers were moving; the late movers were waiting for engineering teams or high-pressure vessels to become available. According to the keynote speakers, 66 refineries were planned worldwide and 180 upgrading projects were envisaged along with some 180 clean fuels projects. The fact that the cost of projects had risen by 50%–100% was

affecting how many would be realized. But conservatively, the world was due an 8.5-MMbpd increase in distillation capacity, with an implied 8.5-MMbpd increase in crude output to service the new refineries. While downstream, Europe’s largest refiner was being bold and carefully watching the 3%–4% annual demand growth in oil consumption, upstream the head of exploration was saying that industry could never produce the oil that International Energy Agency projections were calling for. Next Golden Age. In the end, refining got its Golden Age. It was 2005 to 2007. And it got its synchronized global slowdown resulting from high oil prices as well. Pump prices that were twice the $2-level that shocked drivers in 2004 were, in my mind, the straw that broke the camel’s back in 2008. Manipulated into driving trucks instead of cars by less than visionary government policy, US consumers couldn’t keep up the repayments. The house of cards teetered, and we know the rest. For the lucky refiners, it’s almost as if the new investments were paid for by the undercapacity in the hiatus before the projects were brought onstream. But try getting that logic past the board. No one is looking lucky this summer—least of all those who took their time to implement something of visionary scope. Take the European refiner who chose to capture Mayan crude coking margins with new diesel upgrading in the heart of a deeply deficit European distillate market. Who knew that sour crude margins that raced through double digit numbers over the last three years could wrong-foot refiners so badly. First, you would needed to know that OPEC’s production slowdown would be for the sour crudes preferred by the new upgrade projects. And that if a slump hit the US and China, it would affect road diesel used to move goods harder than gasoline. “A year ago, we couldn’t believe how good the project looked,” says Modesto Fernandez, the Repsol YPF project manager for a truly expansive reconstruction of hydroskimming refinery at Cartagena, Spain. “Delayed coking margins were at $20/bbl,” he says. By May 2009, margins for delayed coking at similar sites in the US Gulf Coast were as low as $1.19. A complex site running Brent crude in Europe had a margin of $1.74, while those running sour Urals crude through a hydrocracker in Europe were getting only about 60¢/bbl of additional benefit for their efforts. Repsol YPF isn’t on its own. The summer reporting season is littered with loss-making refiners who failed to call the destruction of the sour crude discount. The cycle comes around on itself. The game-theorizing herd is up to its knees in detritus, and there are losses all round. HP The author is HP’s European Editor. He has been active as a reporter and conference chair in the European downstream industry since 1997, before which he was a feature writer and reporter for the UK broadsheet press and BBC radio. Mr. Wright lives in Sweden and is the founder of a local climate and sustainability initiative.

HYDROCARBON PROCESSING SEPTEMBER 2009

I 13

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HPINTEGRATION STRATEGIES WIL CHIN, CONTRIBUTING EDITOR wchin@arcweb.com

Emissions rules demand flexible fuel terminal blending There’s no avoiding the inevitable; it’s time for terminal owneroperators to get ahead of the fuel blending automation curve. The migration of blending to marketing load terminals, and eventually to retail stations, is becoming a reality due to increasing regulations and consumers’ increasing appetite for greener fuels. Marketing terminal blending requirements pale in comparison to refinery blending systems that must contend with widely varying constituents, many with nonlinear characteristics. However, today’s increasingly more complex blending of conventional, reformulated and biofuels can benefit from the proven measurement and control solutions deployed in process automation. Diverse fuel end products require flexibility. Refinery

blending has always been extremely complex since many fuels, such as gasoline, are actually a mixture of many components. Fortunately, marketing terminals do not have this complexity, but they will need to contend with an increasing variety of products as tighter emissions regulations take hold. Whether or not the EPA ruling to allow California and many other states the option to enforce stricter greenhouse gas standards forms the basis for a single nationwide standard in 2012, this ruling and other regulations will likely demand an increasing number of fuels and require different clean fuel blending recipes at the regional marketing terminals. As owner-operators build new terminals and upgrade their existing blending systems, they should consider adopting the most accurate solutions with the flexibility to measure and blend a variety of constituents, from very small to large quantities, to accommodate whatever changes may come. Pick the right blending technology. Traditional blend-

ing methodologies deployed in marketing terminals include ratio, sequential, sidestream and splash blending. Ratio blending is in the best position to meet current and future demands. Ratio blending provides multiple flow loops engineered to accurately meter the correct quantity of components within specification without overaddition of the high-cost component, such as ethanol in an E10 blend of gasoline and ethanol. This assumes that an appropriate batch controller/flow computer incorporates blending algorithms that correct for nonlinear mixing and component interactions. Optimize fuel blending at load rack. Increasingly, load-

rack blending is becoming more desirable due to reduced footprint, elimination of tanks and increased product flexibility of load arms that can provide various blends on demand in exact quantities without waste. Regardless of the methodology selected, accurate online measurements are key to terminal operator profitability. Using the most accurate field devices (for flow, level, temperature and pressure measurements) and control valve technology will help terminal operators improve efficiency and reduce product give-

away that may not be measurable by lesser field devices. Today’s automation equipment is well suited to the hazardous area environment of load racks. However, the multitude and complexity of formulations of fuels with widely ranging percentages of from 10 to 100% ethanol for export requires the utmost in rangeability and response from both flowmeters and control valves. For example, the flowmeters of choice in blending systems are mechanical PD and turbine meters. These typically wear with use, resulting in under-reading of blend components and increased product giveaway. New digital flowmeters, such as compact Coriolis meters, can provide much greater accuracy and have been field-proven to provide accurate long-term measurements without adjustments to the meter due to their nonwearing measuring elements. More importantly, picking the right blend methodology with precise measurement will reduce the possibility of loading off-specification products, which could require costly reblending operation to obtain saleable products. Terminal operators tend to be conservative creatures-of-habit who would rather deploy proven technologies and processes than take additional risks; even if those risks could, in the long run, help reduce total cost of ownership and improve both productivity and profitability. Even though newer technologies have been proven in other parts of the oil and gas industry, terminal operators require further evidence of success in their applications. In this case, “proven” means reliability, safety and quantifiable benefits. In countries where grassroots terminals are being constructed, Coriolis meters are more frequently deployed than are mechanical meters. Lessons learned in these applications should be more easily transferrable to legacy installations in the US, but upgrading a legacy blending system presents obstacles. This is particularly true for the Coriolis meter. Since the mechanical meters and typical Coriolis meters have different pipeline installation lengths (flange face-to-face), modifications to the piping will be necessary that will drive up the installed and project costs, including the time required to complete the change. Load terminals are becoming much more important to the fuel distribution supply chain and terminal automation systems incorporating advanced flow measurement and blend control technology can contribute greatly to marketing terminal profitability. The ability to blend a wide range of constituents and the precise measurement of key variables, particularly flow measurement, will allow operators to efficiently blend the clean fuels of tomorrow. HP

The author leads the field device consulting team at ARC covering process measurement technologies. He is responsible for pressure, flow, level, temperature and related markets. Mr. Chin also covers field device communication protocols, plant asset management (PAM) and laboratory information management systems (LIMS). He has nearly 30 years’ experience in the areas of sales management, product marketing and engineering in industrial field instruments.

HYDROCARBON PROCESSING SEPTEMBER 2009

I 15

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HPIN ASSOCIATIONS BILLY THINNES, NEWS EDITOR

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What happened in Reno didn’t stay in Reno Contractors, owners and members of academia met at the Construction Industry Institute (CII) conference July 28–30, 2009, in Reno, Nevada. The conference center was busy with tourists playing slots and enjoying the beautiful weather by lounging pool-side. Even with such temptations, sessions at the conference were well attended as discussions evolved from the current state of the construction industry to how to cultivate future leaders. Jim Miller, CII Conference chair, opened up his remarks with what he considered are the four key qualities of leadership: • Ethics—leaders must never lose their moral ethical compass • Reality—leaders must foster an open and transparent culture for filters, politics and other factors that do not distort project objectivity • Courage—leaders must have the strength and courage to make tough calls at the right time • Vision—leaders must keep balance between resorting to survival tactics and maintaining their vision. Keynote speaker. Dr. Marianne Jennings, professor of Legal and Ethical Studies at Arizona State University, offered her

Jim Miller talked about the four key qualities of leadership.

thoughts on ethics for the conference’s keynote address. During his introduction of Dr. Jennings, Mr. Miller said, “The topic of ethics is especially timely since we have seen ethical lapses of historical proportions come to light in the past year.” Dr. Jennings discussed the four divisions of an economic business system (business, investors, customers and government) and the problems that occur if bribery is introduced. “We ask you to worry about ethics because it’s a pretty compelling part of economic systems,” Dr. Jennings said. Breakout sessions. Topics covered in the sessions included project performance, business leadership, estimating for capital projects and making implementation a reality. Of particular interest was a breakout session discussing improving innovation potential by using an innovation maturity model. The program model in question compares how companies are doing when it comes to innovation. The research was done in multiple phases. Phase One looked at key components that drive innovation, while Phase Two compiled raw data from membership surveys and in-depth case studies on how to use the tool and put it into action.

John Dalton informed attendees about the current activities of CII.

CII accomplishments. John Dalton,

executive vice president at Mustang and CII committee chair, gave an update on CII’s recent activity. Mr. Dalton informed the attendees that CII has been busy with many accomplishments in the past year. There are 12 new projects in progress and two new academic committees. CII is working closely with the National Academy of Construction to get high school students involved in the industry. CII is also implementing a new degree in Industrial Construction Management, offered at the University of Houston this fall. “What happens in Reno shouldn’t stay in Reno,” Mr. Dalton said. “Take the materials and data back to your organizations.” Overview of CII. CII is headquartered

in Austin, Texas, and was established in 1983 to improve the world’s largest industries. Today, CII is well known for creating and implementing research-based knowledge that measurably improves the delivery of capital facilities. Some of the committees include benchmarking and metrics, branding implementation and membership. The committees are chaired by professionals in the construction and academic industry. —Tricia Crossey HP

Dr. Marianne Jennings gave the keynote address.

HYDROCARBON PROCESSING SEPTEMBER 2009

I 17

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HPIMPACT BILLY THINNES, NEWS EDITOR

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Styrenics market hit further by economic downturn From Nexant’s latest report, “Styrenics Market Dynamics,” the styrenics industry continues to endure difficult market conditions. Over recent years, producers have struggled with a shrinking market caused by aggressive substitution of a key derivative—polystyrene (PS). Further pressure is being felt by producers as strong growth sectors, such as expandable polystyrene (EPS), acrylonitrile butadiene styrene (ABS) and styrene-butadiene rubber (SBR), are impacted by crisis in the construction and automotive sectors. The trend toward consolidation has advanced significantly and is expected to continue, given the poor economic outlook and pressure from new and increasingly more competitive plants in the Middle East and Asia Pacific. Mergers have occurred horizontally to lower costs and consolidate the supply base, and also vertically to improve integration with feedstocks. Some producers are attempting to exit the styrenics business. Huntsman’s exit is almost complete, following the sale of most of its business to Flint Hills Resources. BASF’s styrenics business remains for sale. Mitsubishi Chemical Corp. plans to exit the PS business in late 2009.

destruction. The automotive and construction industries are globally responsible for much of the recent growth in styrene demand, but these industries are the hardest hit by the present economic downturn. Although PS demand has declined globally since 2005, it remains the largest styrene consumer (Fig. 1). Among other the derivatives, EPS demand has accelerated, driven by protective packaging and construction sectors and an increasing focus on energy conservation in buildings. Styrene demand for ABS and SBR performed strongly over 2006–2007, reflecting high economic growth and the development of the automotive industry in developing regions. The economic uncertainty in developed economics led a widespread move away from vehicle purchases, leading to catastrophic losses for several western vehicle manufacturers. While the effect on ABS and SBR was most severe in these regions, the downturn was felt everywhere. Several Asian countries produce vehicles and automotive components for export, as well as consumer and household items for which demand has reduced. Capacity development has recently been concentrated in Asia-Pacific and the Middle East. Asia Pacific has been the largest production base since 1997 following huge capacity development in China, South Korea and Taiwan. Saudi Arabia has been the focus of capacity development in the Middle East, although Iran and Kuwait have also recently been active. In 2008, styrene capacity development in the Middle East entered an active phase, following minimal activity over 2002–

2007. Jubail Chevron Phillips started up a major plant in Saudi Arabia in 2008, while TKSC (Kuwait) and Pars Petrochemical (Iran) both have major plant starts in 2009. Styrene producers in the Middle East do not have the same level of competitive advantag, for example, olefins producers, but they benefit from lower energy costs. Limited benzene availability has been a barrier to previous major styrene investment. But increasing aromatics production from steam cracking and reforming now allows major projects to proceed. While benzene production is not particularly advantaged in the Middle East, competitiveness is supported by ethylene-cost leadership. Styrene capacity in Asia-Pacific accounts for almost half of the global total. The capacity will continue to grow, but at lower rates. Most new capacity will be integrated with ethylene and benzene feedstock sources. Over the past five years, 5 MMtpy of new styrene capacity has been added, mainly in China. There have been no new market entrants for some time in Japan, South Korea or Taiwan. But total capacity has increased as the existing producers have expanded and rebuilt plants to improve their cost positions (Fig. 2).

PS. Global PS consumption in 2008 dropped back almost to its 2001 level. The negative effects of high and volatile styrene feedstock prices, competition from polypropylene (PP), and consumer behavior Styrene. While styrene consumption changes were compounded by the demand growth has slowed considerably, 2008 slump in demand in almost all sectors. was the first time in at least 20 years that The increase of digital music has severely the market actually declined. The main impacted CD sales, and with it, the use of derivative, PS, has shown minimal growth PS media enclosures. In develsince 2000 due to inter-polymer oped markets, the packaging competition and consumer sector is the largest application behavior changes. The styrene UPR SBR Others SB latex 5% 4% area for PS, in such products as market as a whole continued to ABS 9% 6% 15% disposable cutlery, vending cups, grow from 2001 to 2007. ABS egg trays, meat trays, salad boxes, demand benefited from strong soups bowls and hamburger clam growth in automotive and elecshells. Its usage in food packaging trical/electronics sectors, and has, however, stagnated due to EPS demand was driven by the an increasing preference for enviconstruction sector. ronmentally friendly paper-based Part of the 2008 decline was Polystyrene (expandable) Polystyrene 18% 43% products. Expandable PS (EPS) due to destocking at all points is facing sustained substitution throughout the value chain when FIG. 1 Global styrene demand by derivative products, 2008. pressure from competing materiprices collapsed. Part of this als such as PP and polyethylene contraction is genuine demand HYDROCARBON PROCESSING SEPTEMBER 2009

I 19

Select 99 at www.HydrocarbonProcessing.com/RS

HPIMPACT finished rubber goods, primarily tires, from regions such as China to the US and Europe have increased dramatically, thus leading to the closure of tire plants in importing regions. Flourishing automotive sectors in China, India and Thailand have also increased demand in the Asia-Pacific region. –Stephany Romanow

2,000 Global PS capacity additions (closures), thousand tpy

terephthlate (PET), but there are some applications where PS remains the polymer of choice. Although PS consumption is changing, some producers are developing premium applications, such as high-gloss PS to replace ABS in automotive decorative parts, in applications where the superior impact strength of ABS is not required. Total Petrochemicals remains the largest global PS producer. Total PS capacity in North America has declined steadily since peaking in 2002, and most of the closures have been made as part of cost-reducing measures. In Western Europe, almost half a million tpy of PS capacity closed over 2005–2009 due to declining local demand and lack of competitiveness in export markets.

1,500 1,000 500 0 -500

-1,000 -1,500 -2,000 2006

2007

2008

2009

North America Eastern Europe South America Middle East

2010

2011

2012

Developing regions increase demand for plastics

Western Europe Africa Central Europe Asia Paciﬁc

Developing nations show increased demand for polyethylene (PE) while the global plastic industry struggles, according to Townsend Solutions. The Middle India Other Asia Middle East East, Africa, India, Eastern Europe Paciﬁc 10.5% 3.5% Africa 11.2% China and South America are thriving. North America 17.9% 21.4% Global consumption of PE resin EPS. EPS ability to improve the declined 3.7% in 2008. Approxienergy efficiency of buildings will mately, 66.7 MMtons of PE were support future demand growth. consumed globally—down from EPS will remain the fastest growabout 69 MMtons in 2007. The ing of the major styrene deriva2008 PE consumption was well Japan Central/South 4.1% Central/Eastern America 6.3% tives, supported by ongoing efforts below the five-year annual averWestern Europe Europe 5.5% 19.6% to reduce energy consumption in age of 3.4%, during 2003–2008 buildings. The packaging sector (Fig. 3). The global recession and FIG. 3 Polyethylene resin consumption share by region in 2008. will benefit from the increased financial crisis in the latter half of consumption of electrical and 2008 were the main reasons for electronic appliances by the growthe decline in PE consumption. ing middle classes in regions such as Asia. will be one of the key drivers for styreneYet, there were some bright spots. SevAlmost 3 MMtons of EPS capacity has been market growth during the next economic eral regions showed positive consumption added in Asia Pacific since 2000, accounting recovery, with long-term sustainable growth growth rates in 2008. Regions with posifor over 80% of the global capacity addition. supported by the electrical appliance and tive growth were in the Middle East/Africa, Developments in China accounted for over automotive sectors. Asia Pacific, particu- India, Central/Eastern Europe and Central/ 90% of the Asia Pacific total, and have mas- larly China, will remain the largest con- South America. Regions that declined were sively outstripped consumption growth. The suming region. Central Europe is expected China, Other Asia/Pacific, North America, EPS market is dominated by regional rather to grow and to balance the slowdown in Western Europe and Japan. Positive forces than global players. Six of the 10 largest Western Europe. are in place in developing regions for PE producers globally are Chinese, with Loyal growth between 2008 and 2013. China, Chemical being the market leader. SBR. The tire industry consumes 75% of Central/Eastern Europe, Central/South the SBR produced globally, followed by America, India, Middle East/Africa and ABS. Global ABS demand has been under mechanical rubber goods/automotive parts Other Asia-Pacific are exhibiting broadpressure from inter-polymer competition, applications (19% of the market). Footwear based growth fundamentals. Townsend especially from PP and lately PS, which are accounts for only around 6% of the SBR concludes that the developing regions’ competing particularly at the lower-specifi- market. The main use of SBR is in manu- combined growth rate is projected to be cation end of the automotive sector. Recent facturing tire tread, and consumption is 4.6%/yr over the five years and is well developments in high-gloss PS constitute forecast to develop in line with the automo- above the average global projected annual a new threat for ABS for decorative parts. tive sector. The production of auto tires is growth rate of 3.2%/yr. On the contrary, as However, ABS remains the material of choice increasingly competitive and cost sensitive. a group, Townsend projects that the more in most applications in the key electronics/ Consequently, the manufacturing of tires developed regions of North America, Westelectrical appliance sector, due to its mechan- and other rubber goods has migrated to ern Europe and Japan will have a five-year ical properties, high gloss and processability. lower labor-cost areas, depressing market growth rate of only 1.6%/yr on average Although ABS consumption is forecast growth in developed regions such as West- over 2008–2013. HP to grow at slower rates over 2009–2018, it ern Europe, the US and Japan. Exports of –Stephany Romanow FIG. 2

Global PS capacity additions (and closures)—2006 to 2012.

HYDROCARBON PROCESSING SEPTEMBER 2009

I 21

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Syngas and power produced from urban waste Rentech, Inc. plans to build a plant in Rialto, California, that will produce ultraclean synthetic fuels and electric power from renewable waste biomass feedstocks. The Rialto Renewable Energy Center is designed to produce approximately 600 bpd of pure renewable synthetic fuels and export approximately 35 MW of renewable electric power that is expected to qualify under California’s Renewable Portfolio Standard Program. The plant will be capable of providing enough electricity for approximately 30,000 homes. RenDiesel, the renewable synthetic diesel to be produced, meets all applicable fuels standards; it is compatible with existing engines and pipelines and burns cleanly, with emissions of particulates and other regulated pollutants significantly lower than from CARB ultra-low-sulfur diesel. The carbon footprint of the RenDiesel plant is designed to be near zero as the fuels and power would be produced only from renewable feedstocks. The low carbon footprint would help the transportation sector meet targets established by the Low Carbon Fuel Standard Executive Order 1-S-07 and reduce carbon intensity from transportation fuels by 2020. Rentech entered into a licensing agreement with SilvaGas Corp. for biomass gasification technology for the Rialto facility. Between 1998 and 2001, a 400-tpd plant using the SilvaGas biomass gasification technology successfully operated in Burlington, Vermont, producing synthesis gas from wood-based biomass in a series of operating campaigns. Rentech’s proprietary technology for conditioning and syngas clean up will provide the next critical link in the technology chain after gasification. The conditioned syngas will be converted by a commercial-scale reactor to finished, ultra-clean products such as synthetic diesel and naphtha using upgrading technologies under an alliance between Rentech and UOP. Renewable electric power will be produced at the facility by using conventional high-efficiency gas turbine technology. The power is anticipated to be sold to local utilities under the California

RPS program. Jacobs Engineering Group will conduct the feasibility engineering phase of the project. The primary feedstock for the Rialto Project will be urban woody green waste such as yard clippings. Rentech is currently negotiating supply agreements. The plant is designed to also use bio-solids as a portion of the feedstock. Select 1 at www.HydrocarbonProcessing.com/RS

Gas seal increases equipment reliability

FIG. 1

Flowserve’s GTSP hightemperature pump gas seal.

Flowserve Corporation has introduced the GTSP high-temperature pump gas seal that increases equipment reliability and reduces energy consumption for the hottest process pumps in refinery and hydrocarbon facilities (Fig. 1). Using Flowserve’s exclusive bidirectional wavy-face topography, GTSP seals are pressurized with dry steam or nitrogen. Laser-applied wavy-face technology creates a gas-film barrier between the seal faces to eliminate seal face wear, minimize fouling, increase long-term equipment reliability and lower gas consumption. As HP editors, we hear about new products, patents, software, processes, services, etc., that are true industry innovations—a cut above the typical product offerings. This section enables us to highlight these significant developments. For more information from these companies, please go to our Website at www.HydrocarbonProcessing.com/rs and select the reader service number.

“The GTSP gas seal is the latest example of Flowserve developing reliable, energyefficient products for the oil and gas and hydrocarbon processing industries,” said Andrew J. Beall, President, Flowserve Flow Solutions Division. “Continuing our commitment to creating sealing technologies that maximize every energy dollar, Flowserve GTSP seals consume at least 10 times less energy than traditional liquid dual seals.” Easier to install and maintain than liquid barrier seals, wavy-face GTSP gas seals eliminate the energy requirements from circulating, cooling and churning a liquid barrier, and creates significantly less heat generation and torque at the seal faces. Sinusoidal waves allow bidirectional operation to simplify installation on doubleended pumps, while the smooth-wave texture is self-cleaning to resist contamination. Alloy 718 welded metal bellows assembly construction offers high resistance to stress corrosion cracking in high-temperature, sulfuric-laden services. The GTSP seal is designed to operate without cooling at full process temperatures and can tolerate high-axial overtravel during pump warm-up and thermal transients. The seal design eliminates process leakage and coking problems. Select 2 at www.HydrocarbonProcessing.com/RS

New service fights hydrocarbon leaks Leaks are a phenomenon any refinery will deal with in its lifetime—it is just a matter of “when.” The Baker Petrolite LeakGuard Hydrocarbon Leak Detection Service Program can find and fight hydrocarbon leaks in industrial cooling water systems. Such systems can help refiners save hundreds of thousands of operating dollars and avoid costly environmental regulation violations. The Baker Petrolite LeakGuard Hydrocarbon Leak Detection and Mitigation Service Program was designed to find and to fight leaks fast in any cooling water system configuration. One component, the LeakID Rapid Hydrocarbon Identification Service test, is the first field-ready methodology that can accurately identify and quantify a hydrocarbon, and it does it faster HYDROCARBON PROCESSING SEPTEMBER 2009

I 23

HPINNOVATIONS DYNA-THERM CORPORATION

than any current method on the market. An additional feature provides hydrocarbon quantification, providing insight into leak severity for planning effective mitigation and repair programs.

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Midwest refinery suspected they had a hydrocarbon leak. Anecdotal evidence included an increase in oxidant biocide demand, cooling water turbidity, foaming and mild steel pitting on corrosion coupons. Refinery personnel began looking for the leak; they were challenged by dozens of heat exchangers without sample points on their outlet side. Water samples had to be taken via back-flush lines.

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FIG. 2

The LeakID Service test identified the hydrocarbon within minutes, quickly narrowing the search for the leaking heat exchanger from dozens to 10.

During unsuccessful attempts over a two-week period to pin down the leak source, microbiological growth and pitting corrosion rates increased. When asked to get involved, Baker Hughes experts simply took a water sample from the cooling tower hot return header. Within minutes, the LeakID Service test identified the hydrocarbon as either benzene or gasoline (Fig. 2). Refinery personnel were quickly able to key in on a set of 10 heat exchangers and exclude dozens of others. By back-flushing each exchanger, Baker Hughes experts tested the outlet water using both an ORP meter and a meter that measures low levels of combustibles. On the fourth heat exchanger tested, the outlet sample ORP measurement was negative 200 millivolts and the level of combustibles in the sample pegged the meter. This heat exchanger was identified as the leaking culprit. Refinery personnel were able to develop their leak mitigation and exchanger repair plans. Along with the LeakID Service test, the

turnkey LeakGuard Program also encompasses the LeakTrap Hydrocarbon Leak Detector for early leak detection, and emergency leak mitigation through the Baker Petrolite PREPARED TO RESPOND (P2R) Services, featuring BioKlenz ER Biofilm Control Services for the safe and effective generation and delivery of chlorine dioxide biocide. Select 3 at www.HydrocarbonProcessing.com/RS

New methanol catalyst released Johnson Matthey Catalysts has released a new generation of methanol (MeOH) synthesis catalyst called KATALCO APICO. The new MeOH synthesis catalyst product represents a significant advancement in catalysis. It offers huge benefits to existing MeOH plant operators in reduced operating and maintenance costs. The enhanced activity, slower deactivation and product strength doubles the catalyst service life while halving byproduct formation. The new catalyst is pre-reduced, leading to significantly faster start-up times. KATALCO APICO can provide significant opportunities; existing MeOH plants can increase output with no plant modification. The advanced catalyst system will enable designing for more compact reactor systems or to increase plant capacities; thus further improving MeOH production economics. Building on the traditional strengths of Johnson Mattheyâ&#x20AC;&#x2122;s expertise in copperzinc catalysis, KATALCO APICO has been formulated to give high, and precisely controlled, dispersion of active copper. This high activity has been further enhanced through improved thermal stability to reduce sintering and to retain higher activity over longer service life. In addition, KATALCO APICO is estimated to produce only half the level of higher alcohols and other oxygenates as other competitive catalysts. With less byproduct generation, distillation losses are reduced in MeOH product purification. KATALCO APICO is a robust product that can withstand the rigors of catalyst loading without degrading passivation, thus, removing the risk of overheating. The new catalyst will be manufactured by a new, state-of-the-art catalyst plant at Clitheroe, UK. To achieve the highest control precision in the manufacturing process, Johnson Matthey has constructed the worldâ&#x20AC;&#x2122;s first truly continuous catalyst manufacturing facility. Select 4 at www.HydrocarbonProcessing.com/RS

Solved by Nature

Alternative Fuel Production – a key technology of the future As a leading supplier of catalysts, absorbents and additives, Süd-Chemie has allocated signiﬁcant resources in the ﬁeld of catalysts for alternative fuel production for many years. Known as the key catalytic technology provider for GTL and CTL production, the company is also well-positioned to offer a broad range of solutions for the critical steps involved in converting Biomass into value added products. Süd-Chemie – your partner for emerging technologies!

SÜD-CHEMIE www.sud-chemie.com Select 70 at www.HydrocarbonProcessing.com/RS

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HPIN CONSTRUCTION BILLY THINNES, NEWS EDITOR BT@HydrocarbonProcessing.com

North America The Shaw Group Inc.’s Power Group Maintenance Division has a maintenance, modifications, packaging and small capital construction contract with Lion Copolymer to service its two plants in Geismar, Louisiana.

at Gassco’s Zeebrugge terminal in Belgium. Foster Wheeler has also been awarded the concept development and pre-engineering of the blow-down system at Gassco’s Dunkerque terminal in France following its successful completion of the study phase.

Middle East Emerson Process Management has formed a strategic relationship with Secure Energy, Inc. to help build an $800 million alternative energy plant in Decatur, Illinois. The plant will execute the concept of coal gasification-to-synthetic natural gas. According to this strategic relationship, Emerson will serve as the main automation contractor (MAC), responsible for managing and digitally automating the Secure Energy plant that will convert 1.4 million tpy of Illinois coal into 21 billion cubic feet of pipeline quality natural gas. The modular facility is a template for four additional clean coal plants that Secure Energy intends to construct in other parts of the US.

South America PetroquímicaSuape is building a large pure terephthalic acid (PTA) plant in the Port of Suape, Pernambuco, Brazil. For the project, Aker Solutions is delivering basic and detailed engineering design and providing offshore procurement services for long delivery purchase orders. The new plant will produce 640,000 tpy of PTA, and is expected to come online in late 2010.

Europe Technip has an engineering, procurement and construction management contract for a “crystal” gas plant project in Etzel, Germany. The contract was awarded by Electricité de France S.A., in coordination with EnBW Energie Baden-Württemberg AG. The “crystal” project covers gas compression and treatment facilities for the storage of gas in underground salt caverns. Gas will be injected into the caverns at times of low gas prices and withdrawn to feed into the Dutch and the German gas grids, notably during periods of peak demand. Foster Wheeler Energy Ltd. has an engineering, procurement and construction (EPC) contract with Gassco AS for the implementation of the blow-down system modification

ABB has a contract worth $223 million from Sonatrach for three gas plants in Algeria. Scheduled for completion in the first quarter of 2012, the project includes new compressor trains, re-instrumentation of existing gas treatment plants and an integrated control system for both the new and existing facilities. ABB will also deliver related automation equipment, as well as medium- and low-voltage switchgear and transformers to the plants. ABB will be responsible for the engineering, procurement and commissioning of the project, while construction activities will be carried out by Sarpi. Borouge has awarded The Linde Group a contract worth over $1 billion to build TREND ANALYSIS FORECASTING Hydrocarbon Processing maintains an extensive database of historical HPI project information. Current project activity is published three times a year in the HPI Construction Boxscore. When a project is completed, it is removed from current listings and retained in a database. The database is a 35-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 comma-delimited or Excel® and can be custom sorted to suit your needs. The cost of the sort depends on the size and complexity of the sort you request and whether a customized program must be written. You can focus on a narrow request such as the history of a particular type of project or you can obtain the entire 35-year Boxscore database, or portions thereof. Simply send a clear description of the data you need and you will receive a prompt cost quotation. Contact: Lee Nichols P. O. Box 2608 Houston, Texas, 77252-2608 Fax: 713-525-4626 e-mail: Lee.Nichols@gulfpub.com.

another 1.5 million-tpy ethane cracker at its production site in Ruwais, Abu Dhabi, UAE. The contract will be executed on a lump-sum turnkey basis with the construction work to be executed by the Consolidated Contractors Co. The new cracker, the third of its kind to be built by The Linde Group for Borouge in one decade, complements the 600,000tpy and 1.5 million-tpy ethane crackers, the latter of which is currently under construction as part of the plant’s expansion from 600,000 tpy to 2 million tpy of polyolefins by mid-2010, and ultimately 4.5 million tpy of polyolefins by 2013. Technip has two lump-sum turnkey contracts with Saudi Aramco Total Refining and Petrochemical Co. (SATORP) for two packages that are part of the grassroots refinery to be built in Jubail, Saudi Arabia. This full-conversion refinery will have a processing capacity of 400,000 bpd of Arabian heavy crude oil. Technip’s scope for this project covers the engineering, procurement and construction of two contracts: the hydro and catalytic cracking conversion process units; and some of the utility units, as well as the interconnecting network and process control system of the entire refinery. These contracts are scheduled for completion during the second quarter of 2013. Samsung Engineering has a $300 million contract for an air separation unit (ASU) to be delivered to National Industrial Gases Co. Located in Al Jubail, Saudi Arabia, the air separation plant would produce gaseous oxygen, nitrogen and argon from compressed air through a cryogenic separation process. Samsung Engineering will execute the licensing, engineering, procurement and construction under a lump-sum turnkey basis and the plant is scheduled to be completed in 2011.

Asia-Pacific Samsung Total Petrochemicals Co., Ltd., has selected Merichem Chemicals & Refinery Services’ technologies for a heavy-ends byproduct upgrade project at its petrochemical complex in Daesan, South Korea. Merichem will supply its technologies to caustic and water treat 15,000 bpd HYDROCARBON PROCESSING SEPTEMBER 2009

I 27

HPIN CONSTRUCTION of jet fuel in order to meet internationally accepted jet fuel specifications.

benzene. Its refining capacity will also increase from 580,000 bpd to 630,000 bpd.

S-OIL Corp. recently held a groundbreaking ceremony for its refinery expansion project in Onsan, South Korea. S-OIL plans to invest 1.4 trillion won to complete the expansion by June 2011. The focus of the project is to construct facilities for producing 900,000 tpy of paraxylene and 280,000 tpy of

Indian Oil Corp. Ltd. plans to begin construction on its 15 MMtpy Paradip refinery complex by December, located in Orissa, India. Detailed engineering and project planning have already started. Construction is scheduled to be completed by March 2012.

Liaoyang Petrochemical is building a10 million ton refining facility in China to process crude oil imported from Russia. On February 17 of this year, China and Russia signed a long-term oil trade framework agreement, under which Russia will supply China with 15 million tpy of crude oil from 2011 to 2030. Liaoyang Petrochemical’s new refining project mainly includes a 1 million tpy hydrocracking unit, a 2 million tpy hydrofining unit, and a 30,000 tpy desulfurization and sulfur recovery unit, as well as new storage tanks, a recycled water plant, a substation and other supporting facilities. All the works are expected to be completed by the end of 2010. Chevron Corp. has awarded Bechtel Oil, Gas & Chemicals, Inc. with a frontend engineering and design contract for the first phase of the Wheatstone natural gas development in northwest Australia. The contract is for the first phase of the project and consists of two LNG processing trains, each with a capacity of about 4.3 million tpy, and a domestic gas plant. The facility will be supplied initially from Chevron’s 100% interest in the Wheatstone Field and the Chevron-operated Iago field. Chevron expects to make a final investment decision on the Wheatstone project in 2011.

Sulzer Chemtech is a leading, global provider of proven mass transfer equipment and services. Sulzer products are relied upon for their outstanding performance and include: gas/liquid separator products like the VKR Mist Eliminator™; structured and random packing; advanced trays such as the Shell HiFi™ and FRI tested VGPlus™; and a full complement of other tower internals for gas and liquid separation. In addition to a full range of mass transfer products, Sulzer Chemtech also provides complete solutions that often include CFD and engineering studies, pilot testing, and full installation capabilities.

Sulzer will service any OEM product and offers emergency replacement services and hardware supply 24 hours a day – all with the quickest response rate in the industry and an enhanced customer focus. For complete solutions to your mass transfer needs, one call to Sulzer Chemtech does it all: 281-604-4100. Or visit www.sulzerchentech.com

A subsidiary of Foster Wheeler AG’s Global Engineering and Construction Group has a contract with Santos Ltd. to undertake the front-end engineering design (FEED) for Santos’ project in Queensland, Australia. This project involves the extraction of coal-seam gas from the Fairview, Roma and Arcadia fields in Central Queensland and the supply of coal-seam gas to a planned onshore LNG facility. The FEED to be undertaken by Foster Wheeler is for the extraction, collection, compression and transportation of coal-seam gas to the transmission pipeline, and associated infrastructure and services, including power generation and water treatment facilities. Sulzer Chemtech, USA, Inc. 8505 E. North Belt Drive Humble, TX 77396 Phone: (281) 604-4100 Fax: (281) 540-2777 ctus.tas@sulzer.com

Select 153 at www.HydrocarbonProcessing.com/RS 28

Jacobs Engineering Group Inc. has a contract with Indian Oil Corp. Ltd. (IOCL) to provide project management consultancy services for a delayed coker unit (DCU) at the Paradip refinery in Orissa, India. IOCL’s Paradip refinery is a 15-MMtpy facility. The total installed cost of the DCU is estimated at $350 million. Jacobs will perform front-end engineering and design services, and supervise the resulting lump-sum turnkey contractors. HP

Do you see a leaf? We also see a challenge to convert waste into new resources. No single entity is responsible for environmental protection. Our industries, communities and environmental service providers must all work together. As a world reference in waste management, Veolia Environmental Services focuses on a sustainable future by treating more than 68 million tons of waste annually and converting it into raw materials, energy and recycled goods.

The environment is our universal challenge.

Learn more about the innovative material reuse solutions we implemented for Autoliv, Inc. Select 85 at www.HydrocarbonProcessing.com/RS

veolianorthamerica.com

Gold or Coal? Why ‘or’? The rising demand for energy has contributed to the comeback of coal – which has a golden future. Global reserves are vast. The task now is to make the most of it. Lurgi has a decisive edge in coal technology owing to its decades of experience in this ﬁeld. We command reliable processes for generating syngas from coal. This gas can be converted into synthetic fuels using the Fischer-Tropsch technology or via the intermediate product methanol. Such fuels contain substantially less hazardous substances than oil-derived fuels. Besides fuels, Lurgi can also convert these gases into valuable petrochemical products. In future, also the environment will be protected more than ever before in coal gasiﬁcation. Lurgi’s state-of-the-art technologies as well as its innovative CO2 management will shape the future. As you can see, coal is the new black gold.

Build on our alternatives. Call us, we inform you: +49 (0) 69 58 08-0 www.lurgi.com

1131_e

A member of the Air Liquide Group

Select 92 at www.HydrocarbonProcessing.com/RS

HPI CONSTRUCTION BOXSCORE UPDATE Company

Plant Site

Project

Capacity Est. Cost Status Licensor

Engineering

Constructor

UNITED STATES Florida

Buckeye Tech/Myriant Tech

Perry

Bio-ethanol

None 54 MMgpy

U 2009 Verenium Corp|Myriant Technologies LLC C 2009

Illinois

Center Ethanol Company LLC

Center Ethanol Plant

Controls, Ethanol

Siemens E & A

Point Lisas

Melamine

60 Mm-tpy

U 2010 Eurotecnica

Eurotecnica

Etrez Etrez Etrez Etrez Aspropyrgos Aspropyrgos Corinth Corinth Corinth

Controls, Compressor Gas Compression Storage, Gas Utilities FCC Gasoline Hydrodesulf (HDS) Crude Unit (1) Lube Oil Refining (1) Sulfur Recovery

BY None BY None BY 400 Bcf BY None 27 Mbpd None 60 Mbpd EX tpd 165 tpd

U U U U C C U U U

2012 2012 2012 2012 2009 2009 2010 2010 2010

Jacobs Jacobs Jacobs Jacobs CDTECH CDTECH Technip Technip Technip

Inpex/Total E&P JV Inpex/Total E&P JV Inpex/Total E&P JV Inpex/Total E&P JV Ningxia Hanas Ningxia Hanas Ningxia Hanas Ningxia Hanas Ningxia Hanas Ningxia Hanas Ningxia Hanas HMEL HMEL HMEL HMEL HMEL HMEL HMEL Mangalore Rfg & Petrochemicals Esso Highlands Samsung Total Petrochemicals S-Oil Corp Nghi Son Refinery Nghi Son Refinery Nghi Son Refinery

Darwin Darwin Darwin Darwin Yinchuan Yinchuan Yinchuan Yinchuan Yinchuan Yinchuan Yinchuan Bathinda Bathinda Bathinda Bathinda Bathinda Bathinda Bathinda Mangalore Kutubu Daesan Onsan Refinery Thanh Hoa Thanh Hoa Thanh Hoa

LNG LPG Offsites Utilities LNG LNG Storage (1) LNG Storage (2) NG liquefaction Offsites Pretreatment Utilities Coker, Delayed Cracker, FCC Hydrotreat, Diesel Hydrotreater, VGO Liquefied Petroleum Gas Polypropylene Utilities Regenerator Project Management Services Treater, Jet Fuel Refinery Cracker, FCC-Resid Gasoline Desulfurization Kerosene, HDS

8 MMtpy 1.6 MMtpy None None 800 Mtpy 400 Mtpy 400 Mtpy None None None None None None None None None None None None None 15 Mbpsd TO 630 Mbpd None None None

2011 2011 2011 2011 2011 2011 2011 2010 2010 2010 2010 2010 2010 2010 2011 2014

Chiyoda/JGC Corp/KBR Chiyoda/JGC Corp/KBR Chiyoda/JGC Corp/KBR Chiyoda/JGC Corp/KBR Technip Technip Technip Technip Technip Technip Technip L&T L&T L&T L&T L&T L&T L&T EIL Eos

Sonatrach Sonatrach Sonatrach Sonatrach Sonatrach Samsung Eng Shell Petr Dev Co Nigeria

Arzew Rhourde Nouss Skikda Skikda Skikda Skikda Okoloma

Heat exchanger Gas Processing Benzene Isomerization Paraxylene Refinery Gas Dehydration

3.5 200 700 220 RE 330 120

Kirkuk Kirkuk Kirkuk Maissan Maissan Maissan Haifa Al Jubail Al Jubail Al Jubail Al Jubail Al Jubail Al Jubail Khalifa Port Ind Zone Khalifa Port Ind Zone Khalifa Port Ind Zone Khalifa Port Ind Zone Khalifa Port Ind Zone Khalifa Port Ind Zone Khalifa Port Ind Zone Ruwais Ruwais Ruwais Ruwais Ruwais Ruwais Ruwais

Offsites Refinery Utilities Offsites Refinery Utilities Hydrocracker Aromatics Complex Benzene Coker, Delayed Paraxylene Propylene Refinery BTX Cracker Ethylene Glycol Ether Phenol Propylene Reformer Butene (3) Ethane Cracker (3) Melamine Offsites (2) Offsites (3) Polyethylene, LD (3) Utilities (3)

LATIN AMERICA Trinidad

Methanol Holdings

Eurotecnica|MAN Ferrostaal

EUROPE France France France France Greece Greece Greece Greece Greece

Storengy Storengy Storengy Storengy Hellenic Petroleum SA Hellenic Petroleum SA Motor Oil (Hellas) Motor Oil (Hellas) Motor Oil (Hellas)

267 21

Technip Technip

ASIA/PACIFIC Australia Australia Australia Australia China China China China China China China India India India India India India India India Papua New Guinea South Korea South Korea Vietnam Vietnam Vietnam

1400

F F F F E E E E E E E U U U U U U U U F E U E E E

Merichem 2011 2013 Axens 2013 Axens 2013 Axens

Technip Technip Technip Technip Technip Technip Technip L&T L&T L&T L&T L&T L&T L&T L&T

Samsung Eng

APCI SNC-Lavalin Samsung Eng Samsung Eng Samsung Eng Samsung Eng Twister BV

Saipem

AFRICA Algeria Algeria Algeria Algeria Algeria Algeria Nigeria

None Bcmy 1100 Mm-tpy Mm-tpy Mm-tpy Mbpsd MMscfd 12

U E U U U U C

2010 APCI 2013 2012 2012 2012 2012 2009 Twister BV

Pietro Fiorentini

MIDDLE EAST Iraq Iraq Iraq Iraq Iraq Iraq Israel Saudi Arabia Saudi Arabia Saudi Arabia Saudi Arabia Saudi Arabia Saudi Arabia United Arab Emirates United Arab Emirates United Arab Emirates United Arab Emirates United Arab Emirates United Arab Emirates United Arab Emirates United Arab Emirates United Arab Emirates United Arab Emirates United Arab Emirates United Arab Emirates United Arab Emirates United Arab Emirates

Iraq Ministry of Oil Iraq Ministry of Oil Iraq Ministry of Oil Iraq Ministry of Oil Iraq Ministry of Oil Iraq Ministry of Oil Oil Refineries Ltd SATORP SATORP SATORP SATORP SATORP SATORP Abu Dhabi Natl Chem Co Abu Dhabi Natl Chem Co Abu Dhabi Natl Chem Co Abu Dhabi Natl Chem Co Abu Dhabi Natl Chem Co Abu Dhabi Natl Chem Co Abu Dhabi Natl Chem Co Borouge Borouge ADNOC/Agrolinz Melamine JV Borouge Borouge Borouge Borouge

EX EX EX EX

None 150 Mbpd None None 150 Mbpd None 25 Mbpd 840 Mm-tpy 140 Mm-tpy 100 Mbpsd 700 Mm-tpy 200 Mtpy 400 Mbpd None None None None None None None None 1.5 MMtpy 80 Mtpy None None None None

500 700 700 900 700

175

S S S S S S E U U U U U U F F F F F F F F U A U F U F

Shaw Shaw Shaw Shaw Shaw Shaw 2012 2012 2012 2013 2012 2013 2013 2014 2014 2014 2014 2014 2014 2014 2013 2013 2009 2010 2013 2013 2013

Samsung Eng Samsung Eng Samsung Eng Samsung Eng

Neste Jacobs Neste Jacobs Neste Jacobs Neste Jacobs Neste Jacobs Neste Jacobs Neste Jacobs Linde Agrolinz Tecnimont Tecnimont Tecnimont

Linde Eurotecnica|WorleyParsons Tecnicas Reunidas|FW Tecnimont Tecnimont Tecnimont

CCC|Linde Tecnicas Reunidas

See http://www.HydrocarbonProcessing.com/bxsymbols for licensor, engineering and construction companiesâ&#x20AC;&#x2122; abbreviations, along with the complete update of the HPI Construction Boxscore. HYDROCARBON PROCESSING SEPTEMBER 2009

I 31

You Get More Than Just a Process Gas Compressor Lubricated up to 1’000 bar, non-lubricated up to 300 bar For longest running time: We recommend our own designed, in-house engineered compressor valves and key components Designed for easy maintenance We are the competent partner with the full range of services – worldwide

Your Beneﬁt: Lowest Life Cycle Costs

More beneﬁts: www.recip.com/api618

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HPI VIEWPOINT Leadership and the art of ‘issue triage’ Gary R. Heminger is executive vice president, downstream, Marathon Oil Corp. Mr. Heminger, a Tiffin, Ohio, native, earned a bachelor’s degree in accounting from Tiffin University in 1976 while already employed by Marathon Oil Co. in Findlay, Ohio. He earned an MBA from the University of Dayton in 1982. Mr. Heminger’s 34 years with Marathon include experience in a variety of groups and functions. In addition to five years in various financial and administrative roles, he spent three years in London, England, as an audit supervisor of the Brae Project. He worked eight years with Emro Marketing, the predecessor of Speedway SuperAmerica LLC, in several marketing and commercial roles and was named vice president of the subsidiary’s Western Division in 1991. From 1995 to 1996, he served as president of Marathon Pipe Line Co.; he assumed the role of manager, Business Development & Joint Interest of Marathon Oil Co. in November 1996. He was named vice president of Business Development for Marathon Ashland Petroleum Co. LLC upon its formation on Jan. 1, 1998, and was named senior vice president, Business Development, one year later. In January 2001, Mr. Heminger was named executive vice president of Supply, Transportation and Marketing. He assumed his current responsibilities as executive vice president, downstream, Marathon Oil Corp. on Sept. 1, 2001. A graduate of the Wharton Executive Management Program, Mr. Heminger is chairman of the board of trustees of Tiffin University. He is past chairman of both the American Petroleum Institute (API) Downstream Committee and the Louisiana Offshore Oil Port, and a member of the Oxford Institute for Energy Studies. He also serves on the board of directors of Fifth Third Bancorp.

t Marathon Oil Corp., we bring a positive, disciplined outlook to analysis of our industry and its prospects. This is even more important today because of the current economic turmoil, declining domestic demand for refined products and increasing calls for renewable fuels—particularly bio fuels. It’s important to remember that the transportation fuels industry is evolving into a global market and that the world is adding about a billion people every 15 years—consumers who rely on multiple energy sources for their welfare and economic well-being. Given the evolving slate of alternative energy, potential government mandates on greenhouse gas (GHG) emissions, and the worldwide recession, how does our country best engineer its energy future? And what role does the refining industry itself play? The answer—as always—is that we need tough-minded, principled leadership from both government and industry. This response is certainly not new. It is our ongoing expectation. Ironically, however, the cool, deliberate judgment expected of real leaders is especially difficult to find in today’s environment. Today, unfortunately, energy development has been politicized and refined products either discredited or treated merely as a source of tax dollars. Accordingly, Marathon believes that the first step in effective energy policy is perception correction. Call it “issue triage.” By that I mean understanding and acting on the real priorities that will lead first to economic recovery, second to energy security and finally to an enhanced quality of life and standard of living.

Hydrocarbons set the world standard. Energy “elitists”

need to abandon the view that conventional hydrocarbons are environmental impediments, old-fashioned and dirty. The truth— inconvenient though they may find it—is that hydrocarbons set the world standard for affordability, efficiency and cleanliness. The story of reductions in nitrogen oxide, sulfur and aromatics emissions is well-known, the product of our industry’s cutting-edge science and unrivalled technical sophistication. The health and living conditions of people around the globe have been improved through the movement of goods and services brought about with the use of ever-evolving and cleaner refined products. Hydrocarbon fuels will power the growth of developing economies while remaining a mainstay in the US far into this century. Department of Energy statistics prove it. Industry analysts cite it. Marathon and its colleague companies believe it. In a real sense, hydrocarbon energy is the future—for decades to come. Policymakers too often see energy only as a tax source, a market to be regulated or a complicated game of chance with carbon credits as chits and huge investments as table stakes. In the interests of issue triage, they need to abandon that view. A more practical view, by far, would be a focus on how a strong domestic energy industry, including refining and marketing assets, will drive US job creation and economic recovery. The relationship between energy use and GDP growth is well understood. Refined products power the factories, drive the tractors, and move both product and produce from source to market. Any economy encumbered by artificially inflated energy costs is an economy that suffers in comparison to its worldwide competitors. Those who see imported crude oil as a national security issue should be attentive to the prospect of a future where foreign governments not only control substantial amounts of oil production, but gasoline and distillate production, as well. Do we really want to see refining included in the list of US industries being outsourced abroad? India and Saudi Arabia are becoming refined product powerhouses at the same time that legislative initiatives in Washington, DC, are threatening refining jobs here at home. According to the American Petroleum Institute, climate legislation currently before Congress could result in the closure of one out of six US refineries. There is no substitute for a strong domestic refining and marketing industry—whether the litmus is job growth and economic well-being—or energy security. Marathon calls on government to support and defend this industry. That is best done by removing unreasonable regulatory hurdles and allowing the industry to compete on a fair and equal footing with rival companies around the world. As we plan for a new US energy future, what is the role appropriate to the refining industry and its member companies? It’s not a simple question. No snap judgment will suffice. The industry needs a process of careful self-assessment to determine its perspective on the world and its place in it. At Marathon, this is how we understand ourselves and our purpose: we are in the business of providing customers with the energy products they need—safely, efficiently, cost-effectively. To this end, we have embarked on two major refinery projects, HYDROCARBON PROCESSING SEPTEMBER 2009

I 33

HPI VIEWPOINT invested in the frontier of oil sands recovery and nonconventional fuels production, and taken equity positions in ethanol production, as well as advanced cellulosic fuel R&D. Refinery expansion? Yes. Our projects are cost-effective. They are driven by the desire to employ the efficiencies of scale and feedstock selection that will ultimately benefit our customers and our shareholders. After all, efficient, low-cost refiners are best positioned to weather down-cycles as well as to profit in the coming economic resurgence.

■ The health and living conditions of

people worldwide has been improved through the movement of goods and services brought about by cleaner refined products.

Select 154 at www.HydrocarbonProcessing.com/RS 34

I SEPTEMBER 2009 HYDROCARBON PROCESSING

Future fuels? Oil sands? Advanced R&D? Yes. Our portfolio of operations is extremely diverse and draws upon a wide range of technological prowess. If we are to provide for the needs of a world adding more than a quarter million new consumers every day, we need the broadest possible resource base. To operate on a hydrocarbons-plus basis is a necessary prerequisite for companies that see themselves providing solutions for their customers’ needs now ... and in a distant future. Anything else is short-sighted. However, it is equally short-sighted to imagine that a nonhydrocarbon world is already at hand. That is simply not the case. Suggestions that we obtain GHG emission reductions on the order of 50% by 2050—through reliance on energy alternatives that are either unspecified or altogether noncommercial—lets wishful thinking trump common sense. No technologies in use today will allow us to reach such a goal. Proposed mandates for renewable fuels rest on Hollywood logic: “If you build it, they will come.” EPA’s Renewable Fuel Standard II ramps up the volume of renewable fuels required each year from 9 billion gallons in 2008 to 36 billion gallons by 2022! This increase is mandated despite the much-publicized constraints on corn-ethanol production or the current lack of necessary commercial biomass technology. The program assumes that the nation will develop an infrastructure capable of delivering, storing and blending these volumes in new markets and, in addition, expanding existing market capabilities. The currently proposed cap-and-trade legislation smacks of political partisanship. Moreover, it risks choosing energy winners and losers through government fiat rather than the operation of free market forces. Instead of partisanship, we need a well-thought-out and defined national policy to drive economic growth while reducing emissions in a fair and logical manner. This can only be accomplished by tapping the finest minds from government, academia, business and others who can collectively address the many challenges we face. These facts illustrate that our most pressing need is an open, frank, non-politicized exchange that will explore the promise of— and the constraints involved in—the transition to whatever energy mix characterizes the last half of this century and beyond. This kind of discussion will be possible only through tough-minded, principled leadership from both government and business. It will be best served by undertaking the difficult business of issue triage—understanding and acting on appropriate priorities. HP

EMERGENCY SHUTDOWNS OFFER A REAL CHALLENGE QUICK, EFFICIENT AND LASTING REPAIR FURTHER TO AN EMERGENCY SHUTDOWN

A major German refinery had planned the replacement of four sets of reactor internals in a catalytic reforming unit after 20 years of trouble-free operations. Unexpected pressure drop was witnessed on one of the reactors four months before the planned shutdown date. Consequences The whole unit had to be stopped and costly loss of production would be imminent. Solution Johnson Screens emergency shutdown procedure was activated on the same day: • Johnson crew members arrived on scene at the refinery, inspected the faulty reactor and dismantled the damaged parts • Meanwhile, new parts were being produced at the Johnson factory and were shipped within 48 hours of the first call • The parts arrived at the refinery and the repair was performed by a crew of four Johnson Screens’ welders. Results The catalyst was reloaded five days after the first call to Johnson Screens and the catalytic reformer was restarted within a week. Scheduled replacement of the three remaining sets of reactor internals was performed as initially planned four months later.

Johnson screens has the products and service you need – across the globe. Call us or visit www.johnsonscreens.com to learn how our internals can make your reactor run at peak performance.

A Weatherford Company AUSTRALIA - ASIA PACIFIC

EUROPE - MIDDLE EAST - AFRICA

NORTH & SOUTH AMERICAS

+61 7 3867 5555

+33 5 4902 1600

+1 651 636 3900

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HPI VIEWPOINT Aspiration or pragmatism: Who wins, who loses? John Hofmeister, upon retirement from Shell Oil Co. in July 2008, founded and heads the not-for-profit (501(c)(3) pending), nation-wide membership association, Citizens for Affordable Energy. This Washington, D.C.-registered, public policy education firm will exist to promote sound US energy security solutions for the nation, including a range of affordable energy supplies, efficiency improvements, essential infrastructure, sustainable environmental policies and public education on energy issues. Mr. Hofmeister was named president of Houston-based Shell Oil Co. in March 2005, heading the US Country Leadership Team, which included the leaders of all Shell businesses operating in the US. He became President after serving as Group Human Resource Director of the Shell Group, based in The Hague, The Netherlands. As Shell President, Mr. Hofmeister launched an extensive outreach program, unprecedented in the energy industry, to discuss critical global energy challenges. The program included an 18 month, 50-city tour across the country during which Hofmeister led 250 other Shell leaders to meet with more than 15,000 business, community and civic leaders, policymakers and academics to discuss what must be done to ensure affordable, available energy for the future. A business leader who has participated in the inner workings of multiple industries for over 35 years, Mr. Hofmeister has also held key leadership positions in General Electric, Nortel and AlliedSignal (now Honeywell International). He serves as the chairman of the National Urban League and is a member of the US Department of Energy’s Hydrogen and Fuel Cell Technical Advisory Committee. He also serves on the boards of the Foreign Policy Association, Strategic Partners, LLC, and the Center for Houston’s Future. Mr. Hofmeister is a Fellow of the National Academy of Human Resources. He is also a past chairman and serves as a director of the Greater Houston Partnership. Mr. Hofmeister earned bachelor’s and master’s degrees in political science from Kansas State University.

he debate over the future of liquid fuels for transportation continues. Gasoline and diesel producers know their track record for reliability, efficiency and affordability. Despite hurricanes, crude shortages, shutdowns, pipeline disruptions and public policy, US citizens can travel when and where they choose. We enjoy ubiquitous, homogeneous (yet differentiated) supply of product across the nation. Products are moved efficiently across states and regions; quality issues are rare and quickly resolved if they occur; supply, distribution and retail networks are established, functional and competitive. The existing liquid fuel industry provides jobs to millions of US citizens; enables tens of millions more to do their work; and hundreds of millions to live their lives. The lifestyles of US citizens are envied around the world. Unlimited, affordable mobility is one of the reasons. US citizens are free to travel and free to choose what, where and how they drive. A century of mobility is a cherished privilege and has morphed into a de facto democratic right. Limiting availability or pricing mobility beyond the means of average citizens motivates reactionary political behavior. I know firsthand, having led Shell Oil Company during the last run-up in gas prices and having endured the onslaughts of elected officials during post-hurricane shortages. Opponents of hydrocarbon fuels are determined to price such products beyond the reach of most consumers, and to make 36

I SEPTEMBER 2009 HYDROCARBON PROCESSING

alternative, commercially unproven products more affordable than hydrocarbons by public subsidy. They are doing so by legislating renewable fuel mandates, promoting cap and trade to add a carbon price to fuel, providing fewer free credits for refined products (in the House bill, 35% of credits benefit the coal industry, which produces 50% of the nation’s energy; 2% of credits benefit the oil and gas industry, which produces 20% of the nation’s energy) and otherwise linking hydrocarbon liquid fuels to unacceptable risks for society. In return, they promise “green jobs,” drowning out the objections to lost jobs in an historic and essential industry. Ideology and partisan politics trump pragmatism and common sense regarding the US’ liquid fuel future. The US’ competitiveness declines and lifestyles deteriorate. No one speaks about the social injustice perpetrated on middle, low and fixed income Americans by hurting affordability. Rapid change and higher costs risk popular reaction leading to the opposite impact on the long-term future of cleaner energy. Citizens for Affordable Energy (www.citizensforaffordableenergy.org) is the voice of pragmatism and common sense promoting the future of affordable, sustainable energy. Citizens for Affordable Energy advances energy and environmental literacy at the grass roots level, while promoting economic competitiveness and lifestyles that remain strengths and the envy of the world. It promotes its Four Mores while educating people in their communities; voluntary associations; cultural, religious and professional groups; schools and homes. They include: • More supplies of energy from all sources to ensure affordability • More technology and innovation to deliver more efficient use of energy • More environmental protection for our land, water and atmosphere to sustain earth • More infrastructure, both legal and physical, to deliver energy from where it is produced to where it is consumed. The Four Mores, adopted and implemented over the next 50 years, promote the best balance for transforming our economy and lifestyles from a traditional hydrocarbon base to the development of a virtually carbon-free economy. They also protect the social values of our pluralistic society. Rushing political doctrine, disguised as energy policy, via partisan elitist hierarchy in short bursts of political time, whether from the Left or the Right, is an invitation to partisan paralysis, dysfunctional government and economic decline. Energy change takes decades; political change occurs in two- and four-year election cycles. The US cannot fix its energy future in political time. The US can change its energy directions. But let’s use time as an enabler. The current liquid fuels infrastructure, technology and vehicle fleet are the outcome of a century of effort. Let’s use the first half of this new century to transform our energy future purposefully, minimizing the destructiveness of rapid political change, while protecting social cohesion and affordability. Clean-energy advocates promote liquid biofuels, hybrids and battery-powered electric vehicles as the transportation future for the US. They aspire to displace today’s 10 million barrels per day (10 MMbpd) consumption of gasoline by 4 MMbbl of biofuels, 2 MMbbl equivalent by use of electric vehicles and 2 MMbbl

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HPI VIEWPOINT equivalent by use of hydrids with higher miles per gallon. Stimulus funding and new budget frameworks utilize taxpayer subsidies to promote these alternatives, while legislation prices hydrocarbon fuels out of the market. The timeframe is as fast as possible based on desperate claims about global warming, which developing nations ignore, and without regard to commercial economics, infrastructure, consumer choice or affordability. Lost in conversation. The levers of change include promises of energy security, hostility toward select oil-exporting nations, domestic oil and gas producers and car manufacturers’ designs. Lost to conversation are huge undeveloped domestic natural resources, cleaner hydrocarbon fuels and offsets, and consumer preference. Also lost is discussion about the inherent inefficiency of biofuels relative to hydrocarbons and of biofuels supply and distribution infrastructures that rely on trucks and rail cars instead of pipelines. No one talks about future environmental impact when tens of millions of battery disposals and intensive biofuels agricultural methods hit land and water. Finally, no one has checked whether consumers either want or can afford new vehicles built with expensive, complex technical systems or whether taxpayers will tolerate subsidizing such products. The rush to alternatives is nongovernmental organizations (NGOs) think tank, laboratory and politiciandriven within a single electoral cycle. With millions of jobs, tens of millions of consumer choices and hundreds of millions of people challenged by affordability, doesn’t the electorate deserve

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a deeper, broader discussion about the implications of aspiration versus pragmatism? Rush to alternatives. The rush to alternatives prices low- and

fixed-income citizens out of personal mobility and middle income families into fewer choices about what they drive, where and when. The only group that might enjoy the new mobility is highincome consumers (including policymakers) who don’t relate to mobility costs in the first place. Moreover, displacing 8 MMbbl of gasoline per day has untold implications for refinery closures, job losses, and even deeper implications for the availability and prices of middle distillates, petrochemicals and other oil products, which the US will continue to depend upon for decades to come. The alternatives rush is on. The implications touch every citizen. Practical solutions. Citizens for Affordable Energy suggests pragmatic solutions without ideological or partisan preference, using energy time and not political time. The Four Mores do it. Timing is the guarantor of successful transformation. Energy and the environment are too important to be decided by partisans in two-year political cycles. So here is what we should do: • Establish a national panel of consumer, industry, NGO and policymaker participants. • Require from them a 50-year comprehensive short-, medium- and long-term plans for energy and the environment that set in 10-year segments. • Establish targets for energy supplies, technology, environmental protections and infrastructure that are achievable in these time periods. • Maintain energy affordability at the historical percentage of national-average disposable income, where it has been for decades. • Build a change platform that is practical, comprehensive, technologically doable, environmentally sustainable, politically nonpartisan and affordable. • Achieve consensus where possible; legislate when necessary. This plan ultimately satisfies consumers and environmentalists at the same time. It protects social cohesion through incremental change. It delivers mobility, affordability and also achieves targeted greenhouse gas reductions over 50 years. Some may say that the horses have already left the barn. It’s too late; we’re on our way. Reality says that, if we don’t create what works for grassroots citizens, we’ll have a do-over, or we’ll have a crisis. Practically, there may be a short-term need for more domestic hydrocarbons to ensure energy security and affordability in the next decade or longer and to serve as a bridge to new technologies. The technologies to displace hydrocarbons need more time to mature. Biofuels and their manufacturing processes need more time to prove out. Electrification of cars using batteries or hydrogen fuel cells needs more analysis, especially with batteryrelated environmental risks. Hydrogen fuel cells could eliminate internal combustion engines altogether. Infrastructures need time to be planned and built. The developing world needs time to adopt environmental sustainability. Most of all, citizens need time for education so they can participate in policymaking by selecting pragmatic representatives who care more about grassroots Americans than partisan politics. Four decades of partisanship has been a disaster for energy and the environment. Yet we’re headed for more of the same. The US loses when political aspiration makes partisan policy in political time; the US wins when pragmatism prevails in energy time. HP

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HPI VIEWPOINT Setting the record straight on alternative fuels John Lynn has served as President and CEO of the Methanol Institute (MI) since December 1, 1996. MI is the trade association representing the global methanol industry. Mr. Lynn and MI initiate and respond to legislative, health & safety, and regulatory actions around the world that impact the methanol industry. MI currently concentrates on methanol-fuel blending in transportation fuels, promoting the use of methanol for power generation and wastewater treatment, and developing methanol-powered fuel cell technologies. He also directs the activities of the Methanol Foundation, the industry’s research arm. Recently, with the rationalization of the North American and Western Europe methanol industries and the development of new production in Asia and the Middle East, Mr. Lynn and the MI Board of Directors have launched new programs to broaden MI’s influence and effectiveness on a global basis. New member companies have been successfully recruited from Oman, Saudi Arabia, Malaysia and the People’s Republic of China, as a demonstration of the new global scope of responsibilities being undertaken by MI on behalf of the world methanol industry. Mr. Lynn spent 25 years on Capitol Hill as chief of staff to two US Senators, including the Chairman of the Senate Energy Committee. He began his congressional career and served as chief of staff to Congressman James R. Jones, Chairman of the House Budget Committee and former US Ambassador to Mexico. Mr. Lynn serves as treasurer on the Board of the Congressional Federal Credit Union. Mr. Lynn is a native of Oklahoma, graduating from the University of Oklahoma.

s an essential chemical commodity, methanol is a building block for hundreds of products that touch our lives each day. In a world where energy security and environmental stewardship are foremost concerns, methanol is becoming part of the solution as an alternative fuel and energy resource. And while most of the world’s methanol is produced from clean natural gas, the methanol molecule containing carbon, hydrogen and oxygen can be made from a diverse mix of feedstocks. In his seminal book Beyond Oil and Gas: The Methanol Economy, Nobel Prize Laureate Dr. George Olah states, “Methanol is a most convenient way in which to store and distribute energy, a suitable fuel in its own right, and a raw material in the production of synthetic hydrocarbons and their related compounds. . . The ready conversion of methanol to synthetic hydrocarbons and their products will ensure that future generations will have access to the essential products and materials that today form an integral part of our life.” Leader in methanol consumption. In 2007, China firmly established itself as the driver of the global methanol industry, becoming the world’s largest methanol producer and consumer. China also leads the world in the use of methanol as an alternative transportation fuel, blending over one billion gallons of methanol in gasoline last year. Taxi and bus fleets are running on high-level methanol blends (M-85 to M-100), and retail pumps sell low level blends (M-15 or less) in many parts of the country. At the same time, China is developing production capacity for dimethyl ether—using coal-based methanol as a feedstock—for markets as a blendstock with liquid petroleum gas (LPG) used for home heating and cooking and as a diesel substitute for buses. 40

I SEPTEMBER 2009 HYDROCARBON PROCESSING

For more than a decade, provincial leaders in coal-producing provinces (Xinjiang, Shanxi, Shaanxi, Henan, Inner Mongolia, Beijing Shi, Hebei, Anhui, Guangdong, Sichuan, Guizhou, Liaoning, Heilongjiang and Ningxia) have been developing methanol fuel demonstration programs. These efforts have involved methanol producers, automakers and academic institutions. In 4Q 2005, eight leaders provided a report to Chinese President Hu Jintao titled “Suggestion on Promoting Methanol Fuels to Replace Gasoline and Diesel Fuel.” President Hu approved this “Suggestion” and in December 2005, directed the powerful National Development and Reform Commission (NDRC) to explore the use of methanol fuels. Methanol fuel could now be considered as strategic fuel for vehicles. Together with the NDRC, the Ministry of Energy and the China Association of Alcohol and Ether Fuels and Automobile (CAAEFA) are instrumental in directing the development of national methanol fuel blending standards. National standards for alternative fuels. In recent weeks, China adopted national standards for Methanol Fuel for Vehicles and standards for M-85 used in vehicles and dedicated methanol-fueled cars, trucks and buses. The M-85 national standard will become effective across China on December 1, 2009. A separate national standard for M-15 is expected to be issued when the 80,000-km road-testing program will be completed by end2009. Adoption of these national standards is a critical step toward the use of methanol fuels across China. If just 5% of China’s cars use M-85 or M-100 fuel and another 15% use M-15, China would displace 14 million tons of gasoline (5 billion gallons) and significantly reduce its dependence on imported oil. China’s automotive industry is already stepping up to meet this challenge. Chery Automobile, a state-owned enterprise has competed demonstration work on 20 methanol flexible-fuel vehicles some time ago and is believed to be ready for full-scale production of methanol cars. Shanghai Maple Automobile, a production base for Geely Automobile, one of the country’s fastest growing independent automaker is also believed to have the technology for producing methanol cars. The company has already put its Haifeng methanol car into production. Shanghaibased Huapu Automotive, another production base for Geely has built a number of methanol-fueled cars. Chang’an has introduced the methanol-fueled BenBen car. Shanghai Automotive Industry Corp., one of the big-three automakers in China, has been engaged in the research and development of methanol-fueled cars. With the introduction of national methanol fuel standards, the large international automakers can be expected to follow suit. Ford, for example, is believed to have the technology for methanol cars. US legislation on alternative fuels. Unfortunately, the automotive industry in the US is opposing key legislation that would spur the introduction of methanol-fueled cars. The Open Fuel Standard Act (OFS) would require that, starting in 2012, 50% of new automobiles, and, starting in 2015, 80% of new automobiles, be flexible fuel vehicles (FFVs) warranted to operate on gasoline, ethanol and methanol. By establishing this requirement, Congress can break the “chicken vs. the egg” syndrome that has stymied the alternative fuel vehicle market introduction. With

HPI VIEWPOINT the transformation of the US car fleet to FFVs, the OFS will open Department of Energy and the Department of Agriculture, US new markets for methanol and ethanol fuels. forestland and agricultural land, the two largest potential biomass The House-passed American Clean Energy Security Act sources, represent over 1.3 billion dry tpy of biomass potential. included drastically watered down provisions of the OFS by Using mature gasification technology, one ton of biomass can be permitting but not mandating that the Department of Transporused to produce 165 gallons of methanol. The production of 10 tation require an unspecified minimum proportion of new cars billion gallons of methanol would require 60 MMtons of biomass, be fuel choice enabling vehicles in an unspecified timeframe. In or less than 5% of the biomass production potential. the late 1980s, legislation was adopted in California to require fuel retailers to add methanol pumps if methanol FFV sales Carbon-constrained world. The technology to capture in the state reached 20,000 vehicles. This was a well-meaning carbon dioxide emissions from chemical and power plants—and attempt to encourage the parallel growth even the atmosphere—for methanol proof a methanol fueling infrastructure and ■ Methanol is becoming part duction is now moving from the lab to the FFV vehicles. But, in reality, it led the pilot-plant scale, and is expected to reach fuel retailers to encourage automakers to of the energy solution as an commercial market introduction quickly. ensure that the fleet of methanol FFVs In a carbon-constrained world economy, never reached the 20,000 vehicle “trig- alternative fuel. methanol could be the solution. Not only ger.” We are concerned that the House can methanol be used directly as a vehicle version of the energy bill may encourage a similar situation—in fuel, but it can also be used to produce gasoline (through processes this case, with the automakers encouraging the fuel retailers to developed by ExxonMobil and others), as well as in the manufacslow the growth of alcohol-fuel pumps. ture of important gasoline components such as olefins. The Open Fuel Standard Act is all about choice. By ensuring that new cars can run on gasoline, ethanol and methanol fuels, ‘Retooling’ for alternative fuels. US Energy Secretary the consumer can decide which fuel to pump. For fuel providers, Steven Chu recently stated that the cost of upgrading these cars the OFS opens new opportunities to produce clean transportation is “about $100 in gaskets and fuel lines,” which we believe to be fuels from natural gas, coal and renewable biomass feedstocks. still higher than the actual cost. A review of replacement part The US may do well to follow the Chinese example and embrace costs for FFVs and conventional vehicles shows virtually the methanol as a strategic transportation fuel. HP same parts for each model, with close to zero incremental cost. The automakers have complained that passage of the OFS would “divert important limited resources away from the development of other advanced vehicle technologies,” a tired argument used in promoting decades-away hydrogen-fuel cell vehicles over nearterm improvements in fuel economy for today’s cars. Only a few months ago, the CEOs of General Motors, Chrysler and Ford appeared before Congress and each committed that they would make 50% of their cars FFVs by 2012. Now, they want to renege on this commitment to alternative fuels. As New York Congressman Eliot Engel states, “It is a simple and inexpensive modification that should be standard in cars, like seatbelts or airbags.” Methanol can be produced from a wide variety of feedstocks, including natural gas, coal, biomass, and even atmospheric carbon dioxide. On a global basis, methanol consumption in 2008 was approximately 42 million metric tons or nearly 14 billion gallons. This is roughly equivalent to global fuel ethanol demand. There is significant potential to produce vast quantities of methanol in the US and other parts of the globe from a wide variety of feedstocks. According to the US Energy Information Administration (EIA), 19.28 trillion cubic feet of dry natural gas was produced in the US in 2007. Since it takes about 100 cf of natural gas to produce one gallon of methanol, the production of 10 billion gallons of methanol would require 1,000 Bcf of natural gas, or just 5% of current US natural gas production. Again, according to the EIA, the US produced 1,146 million short tons of coal in 2007. With about 5,000 short tons of coal needed to produce one million gallons of methanol using proven gasification technology, production of 10 billion gallons of methanol would require 50 million short tons of coal, or just 4% of current coal production. Finally, according to a joint report by the Note: The Methanol Institute serves as the trade association for the global methanol industry. Select 156 at www.HydrocarbonProcessing.com/RS

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HPI VIEWPOINT Reality over rhetoric: Is the road to energy independence a dead end? Charles T. (Charlie) Drevna is the president of the National Petrochemical & Refiners Association (NPRA), a national trade association with more than 450 members, including those who own or operate virtually all U.S. refining capacity and most all petrochemical manufacturers in the U.S. Prior to his election as president in 2007, Mr. Drevna served as NPRA’s executive vice president and director of Policy & Planning. Mr. Drevna has an extensive background in energy, environmental and natural resource matters, with more than 36 years of broad energy industry experience in legislative, regulatory, public policy and marketplace issues. Prior to joining NPRA, Mr. Drevna served as director of State and Federal Government Relations for Tosco, Inc., the nation’s largest independent petroleum refiner, where he was responsible for liaison with Congress, federal regulatory agencies and state governments. Mr. Drevna also served as director of Government & Regulatory Affairs for the Oxygenated Fuels Association, where he held similar responsibilities, and as vice president at Jefferson Waterman International, a Washington, D.C.-based consulting group where he specialized in domestic and international energy issues. Mr. Drevna also served as vice president of Public Affairs at the Sun Coal Co., a Knoxville, Tennessee-based unit of Sun Co., Inc. (Sunoco), and with the parent company as manager of public policy at its corporate headquarters in Philadelphia. Mr. Drevna has a significant background in environmental management that includes service as director of environmental affairs for the National Coal Association in Washington, D.C., and as supervisor of environmental quality control for the Consolidation Coal Co. in Pittsburgh. He received his BA in chemistry from Washington and Jefferson College and performed graduate work at Carnegie-Mellon University.

“Let this be our national goal: At the end of this decade, in the year 1980, the United States will not be dependent on any other country for the energy we need to provide our jobs, to heat our homes, and to keep our transportation moving.” — President Richard Nixon, State of the Union, January 30, 1974

hroughout January of 1974, President Nixon was addressing a number of crises both at home and abroad, not least of which was the survival of his presidency. In the midst of a political challenge or crisis, Washington politicians frequently turn to energy supply as an issue to demonstrate leadership. For 35 years this Beltway tactic has remained unchanged, for today’s politicians, on both sides of the aisle, frequently embrace the notion of “energy independence” as an issue to boost party popularity and candidate support. It’s pure rhetoric, and by 1980, with all due respect to Presidents Nixon, Ford and Carter, the United States had come no closer to reducing dependence on other countries for energy.

Refiners in the crosshairs. As yesterday’s rhetoric continues to bleed into today’s reality, we find the domestic refining sector in the center of several heated political debates ranging from federal

greenhouse gas controls to higher taxation for more government spending to potential supply restrictions. In late June, the U.S. Congress narrowly approved, 219-212, H.R. 2454, the American Clean Energy and Security Act of 2009 or the so-called “WaxmanMarkey Bill.” So contentious and divisive is this legislation that the Senate, July 9, publicly announced that it would defer committee debate on it in until the fall. Under H.R. 2454, American refiners must meet the earliest compliance mandate for fuels in 2013, while other sources would not be phased in until 2014. Compared to other industries, domestic refiners receive a disproportionately low number of emissions allowances to meet H.R. 2454’s requirements – just two percent to cover nearly half of the total U.S. carbon dioxide emissions as defined in the bill. Assuming a conservative carbon price of $26 per ton with two percent of the emissions allowances, a domestic refinery with 100,000 barrels per day of capacity would have to spend roughly $330 million annually if it were required to purchase emissions allowances for the fuels it produced. Aggregated, these costs would total roughly $58 billion per year for the American refining community, and escalate over time as the cost of the program increases. Climate bill counterproductive. The largest challenge pre-

sented by H.R. 2454 is the unfair burden it places on American refiners by mandating responsibility for emissions resulting from the use of their products, including home-heating oil, gasoline, diesel, jet fuel and industrial fuels. With this new and unprecedented burden comes a significant cost advantage for foreign refiners who are already preparing to target U.S. retail markets for fuels and other refined products. Given this distinct disadvantage for domestic refiners, the Waxman-Markey bill is blatantly counterproductive to the concept of “energy independence,” much less enhanced energy security. H.R. 2454 and other proposals targeting climate change also present challenges to American petrochemical manufacturers. Unrealistic greenhouse gas reduction targets imposed by such legislation in the near-term will likely result in a dramatic increase in the reliance on natural gas for electricity generation. Fuel-switching from coal to natural gas by utilities will drive up production costs for domestic petrochemical producers as natural gas supplies tighten. Because natural gas is a vital feedstock in petrochemical production, our domestic petrochemical businesses will be put at a severe competitive disadvantage within the global marketplace and may be forced to relocate overseas to regions where supplies are abundant and affordable. While recent reports suggest that the United States is rich in natural gas supply, Congress has expressed little interest in tapping those resources and facilitating its distribution. In the waning days of the 110th Congress, legislators allowed the moratorium on offshore exploration and production to expire, one case of where taking no action was the best action for American consumers. Unfortunately, the momentum behind the movement on Capitol Hill to unlock our own resources seems to be declining given that 2009 is not a “political year” culminating in November elections. Instead, Congressional leaders will soon seek new ways to generate funding for new government spending, and will HYDROCARBON PROCESSING SEPTEMBER 2009

I 43

HPI VIEWPOINT undoubtedly look to the domestic oil, gas and refining community to help pay the bills with punitive tax hikes that specifically target our businesses. Already, legislation has been passed to freeze tax benefits for oil and gas producers they would ordinarily receive as part of the American Jobs Creation Act of 2004. American refiners compete in a global marketplace, and the Section 199 tax deduction helped domestic refineries compete with foreign entities, bolstering national energy security. Increasing taxes on domestic producers and refiners will not result in lower energy costs – it will increase them, and will also ultimately impact supply. Congress’ own independent research arm, the Congressional Research Service, states that increasing taxes on domestic producers would reduce domestic oil and gas investment and actually result in increased oil imports. A realistic energy policy. A realistic energy policy expands and diversifies our nation’s fuel mix to meet increasing demand. A realistic energy policy recognizes the importance of global supply to our nation’s energy security in times of emergency or natural catastrophe. Unfortunately, the political approach we see today

only creates winners and losers by isolating the domestic oil, gas and refining industries for punitive taxes that would discourage reinvestments in new technologies and facility efficiency upgrades, to say nothing of hurting their competitiveness with state-owned oil companies in unstable regions of the world. The economy, as is always the case with a downturn, will recover, and demand for fuels and petrochemical feedstocks will eventually increase from its present levels. In meeting that future demand, whenever it may arrive, policymakers should consider methods for maximizing the safe, clean exploration and utilization of our own domestic resources. Selective use of certain resources, or political favoritism toward one fuel type over another, is not a recipe for building and sustaining a dynamic American economy. We should make use of what we have, enhance our nation’s energy security by continuing our supply relationships with close and friendly nations such as Canada, and continue to invest heavily in improving on existing technologies. The investments, to the tune of billions of dollars annually, will preserve our economic strength in the face of global competition and also significantly enhance our global economy. HP

olicymakers worldwide find themselves increasingly confronted by the need to balance economic development with an effective, secure yet environmentally benign energy policy. The myriad of new alternative energy and fuels options has fundamentally changed the rules of the energy game, at the same time, significantly increased the complexity of the policymaking process. The heat arising from this challenge is most acutely felt by policymakers across Asia. The region’s rapid economic growth in the past two decades has led to a sharp increase in the consumption of energy resources throughout the region. Indeed, Asia has been responsible for the majority of the new demand for energy and transportation fuels. Under the present economic recession, Asia remains the crucible of economic progress, with China powering the growth locomotive. The US Energy Information Administration (EIA), in its International Energy Outlook 2009 report, expects China, 44

I SEPTEMBER 2009 HYDROCARBON PROCESSING

Total vehicles and motorization index

450 400 350 300 250 200 150 100 50 0

800 700 600 500 400 300 200 100 0

2005 2008 2015 2025 2035 2005 2008 2015 2025 2035 2005 2008 2015 2025 2035

Total vehicles in millions

Clarence Woo is executive director of the Asian Clean Fuels Association. He is a member of the Coordinating Council of Clean Air Initiatives for Asian Cities funded by the World Bank and Asian Development Bank. He was involved as project director in a highly successful China Auto-Oil Program in collaboration with the then China State Environment Protection Agency (now the Ministry of Environment Protection) and Tsinghua University. Mr. Woo is an industry member of the Partnership for Clean Fuels and Vehicles under the United Nations Environment Program, as well as a member of the Asian Society of Automotive Engineers. Mr. Woo has more than 20 years of experience in the oil, gas and petrochemical industries. He started his career with Mobil Oil Singapore where he held various responsibilities in the fields of lubricants, fuels, chemicals and LPG. As senior manager at Ethyl Corp., Mr. Woo was responsible for petroleum additive sales in the Asia-Pacific. He also served as product manager of fuel additives, where he managed fuel additive sales and fuel additive developments in Asia.

Motorized index (vehicles per persons)

Energy policy from Asia’s perspective

India

Asean (major countries)

China

Source: USAID Asia Report, “Biofuels in Asia: An Analysis of Sustainability Options,” March 2009.

FIG. 1

Growth in number of vehicles and Motorization Index for Asian countries.

India and the other developing countries of non-OECD Asia to contribute almost one-half of the increase in world GDP from 2006 to 2030. A slice of the energy pie: Transportation fuels. The

underlying growth drivers and rise of the middle class in Asia have propelled the strong growth in the transport vehicles population. Both China and India have become major vehicle markets. China is now the global automotive manufacturing hub of the world, having taken over the mantle from the US recently. The US Agency of International Development (AID) projects the total vehicles to double in major ASEAN nations, triple in China and expand five-fold in India up to Year 2035 (Fig. 1). The EIA separately forecasts transportation energy consumption in non-OECD Asia (for both passenger and freight transportation) to increase more rapidly than in other non-OECD countries from 2006 to 2030 (Fig. 2).

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HPI VIEWPOINT Annual average change in GDP, population and energy consuption

6 GDP Population Passenger Freight

5 4 3 2 1 0 -1 Europe/Eurasia

Asia

Middle East

Africa

Central/South America

Source: 2006 - Derived from EIA, International Energy Annual 2006 (Jun-Dec 2008). Projections – EIA World Energy Projections Plus (2009).

FIG. 2

Transportation energy use as an average annual change in GDP, population and energy consumption for transportation by non-OECD region, 2006–2030.

What does this mean for policymakers? Due to the

transportation fuel options without sacrificing the environment. This requires presenting scientific and economic facts and data that can withstand scrutiny by all stakeholders in the government and private sectors. Relevance of traditional vs. alternative fuels. Up until the 1970s, policymakers primarily focused on gasoline and diesel when deliberating transportation fuel issues. Over the past few decades, a plethora of alternative transportation energy options have surfaced and captured the imagination of policymakers. These include biofuels, liquefied petroleum gas (LPG), compressed natural gas (CNG), electric, gas-to-liquids (GTLs), biomass-to-liquids (BTLs), methanol-to-gasoline (MTG) and solar, to name a few. Alternative fuels have been the subjects of intense interest, discussion and debate. The enthusiasm about the potential benefits from these options has, at times, overshadowed one important aspect of reality. Oil is the world’s vital source of energy and will remain so for many more years to come, even under the most optimistic of assumptions about the pace of development and deployment of alternate technology. Conventional fuels are the lowest-cost option to the consumer as the production and supply infrastructure is already well established, mature and available on a large scale. Major developed economic bodies such as the European Union (EU), the US and Japan have indicated that fossil fuels will remain the primary choice of transportation fuels by up to 80% of their energy mix through 2030, even as they steadily increase the role of alternative fuels.

phenomenal growth in the vehicular pool, transportation fuels have become an integral part of Asian countries and a nation’s energy policy mix. Improved mobility has made possible a wide array of lifestyle enhancements, a continuous flow of trade/goods and higher levels of commercial activity, particularly in auto-producing nations such as China, Japan, South Korea, Thailand and India. Conversely, the costs of affluence in this form include vehicle pollution, poorer air quality and environment, higher medical healthcare costs, higher oil prices and traffic congestions. Challenges in the use of alternative fuels. While Policymakers must deal with the shift in consumer expectait is clear that alternative fuels present a broad range of opportions (which are increasingly sophisticated and demanding) and tunities and potential benefits to understand the weight of such expectathe transportation sector, countries tions on policy decisions. The challenge in Asia still have some ways to go is to strike a balance between economic ■ The real policy challenge before large-scale adoption of these expansion, rising vehicle demand, pollu- is to determine the optimal fuels can be realized. Each of the tion control, the use of conventional and alternatives comes with its unique alternative fuels/energy, energy security combination of fossil fuels and needs and prices for transportation fuels alternative fuels, after thoroughly set of challenges set within countryspecific contexts. in the market. Biofuels transformed from a A confluence of factors is in play when considering macroeconomic niche energy source to a globally one considers transportation energy and drivers and conditions relevant traded commodity that is a magnet fuels policy: cost and benefit to the confor billions of investment dollars sumer, producer and the government; to the country, and how to within a few years after the US and energy security; crude oil prices; envi- use conventional fuels to the EU announced policies and incenronmental protection (air quality and tives to support its increased use in greenhouse gases); current and future country’s maximum advantage. 2004–2005. Asian governments fuels/energy options (including domeswere quick to follow in their footsteps and announced ambitic production capacity); technology and infrastructure readiness tious plans to promote biofuels production for both domestic and political considerations. consumption and export. Developments of vehicle transportation fuels/energy in Asia are A recent report by AID summarizing the benefits and risks of not homogenous. Asian countries have achieved varying degrees biofuels development in Asia estimated total biofuels production of success, and each nation must identify country-specific prioriin Asia to have grown more than five-fold since 2004, from just ties and issues. The crux is to identify the key policy drivers for over two billion liters to almost 12 billion liters in 2008. Despite each country and recognize that every nation has specific needs this accelerated growth, biofuels only accounted for 3% of the and resource endowments/limitations. region’s transport fuel mix. Consumers expect the government to do the right thing The report pointed out that, even at this scale, it is evident that for the people and the country. The best bet that governments biofuels incur significant trade-offs and economic and environhave to ensure its political longevity is to adopt a thorough and mental risks. Critics of biofuels argue that biofuels compete with fact-based approach while examining the viability of various 46

I SEPTEMBER 2009 HYDROCARBON PROCESSING

HPI VIEWPOINT food crops for land, water and agrichemicals, which aggravate food insecurity issues, contribute to higher food prices and adversely impact biodiversity. Biofuels also do not deliver cost-effective carbon emissions reduction. From a technical perspective, studies have shown that biofuels have a lower calorific value (i.e., they have lower energy content) as compared to conventional fuels. Agriculture uncertainty renders supply availability (of ethanol) unpredictable. In practice, implementing a biofuels mandate is not economically viable without substantial fiscal support in the form of government subsidies and financial incentives. Massive investments in the production and delivery infrastructure may also be needed to accommodate direct ethanol-blended gasoline products, depending on the mandated ethanol level in gasoline. The AID report purports that large-scale biofuel production is unlikely to make a significant contribution to Asia’s future transport energy demand. By 2030, biofuels are expected to account for an estimated 3%–14% of the total transport fuel mix in China, India, Indonesia, the Philippines, Thailand and Vietnam. This projection is predicated on the premise that these countries will rapidly expand cultivation of efficient first-generation biofuels crops on under-utilized land while promoting second-generation “cellulosic ethanol” using agricultural residues. Electrical energy sources have their fair share of challenges to overcome. Infrastructural readiness is the immediate concern, as well as its feasibility over short-distance travel. The gradual electrification of a light-duty transportation fleet and development of low-cost, affordable light-duty vehicles will require time. Battery technology advancements look promising but it is too early to tell if this can be applied on a broad-based basis.

LPG and CNG-compatible vehicles are already available but yet to become mainstream options due to cost constraints, as like solar-powered vehicles, which must successfully achieve miniaturization of solar panels. There is also the issue of emissions of LPG and CNG compared to high-quality clean conventional fuels. Other alternatives under serious considerations include GTLs, BTLs and MTG. GTLs are synthetic liquid fuels derived from natural gas. While they burn cleaner than conventional fuels, current production volume is a fraction of demand and natural gas sources need to be available. BTL fuels may be produced from almost any type of lowmoisture biomass, residue or organic waste. This is the primary advantage as almost any biomass type can be used, with little pre-treatment other than moisture control. However, high production costs and low yield factor do not support its mass commercial application. MTG converts crude methanol directly to low-sulfur, lowbenzene gasoline that can be sold directly or blended with conventional refinery gasoline. Originally commercialized by ExxonMobil 20 years ago, production was discontinued in 1996 due to economics. However, escalating crude oil prices have revived interest in MTG products. Asian countries continue to face persistent, broad challenges related to energy and environmental issues of varying degrees. The process of exploring, evaluating and deliberating the suitability of various transportation fuels options is highly complex. It involves many decision variables and thus cannot be lent to generalization. Policymakers need to understand their countryspecific context in deciding an effective energy policy mix for their respective countries. HP

Adapting to the evolving times Eric Benazzi is Axens’ marketing director. He has over 21 years experience in catalysis applied to fuels and petrochemicals. Dr. Benazzi joined Axens in 2004 as strategic marketing manager in charge of market analysis, business planning and acquisition evaluation. He started his professional career as a research engineer at IFP, where he worked in the field of catalysis, specializing in zeolites and in hydrocracking processes. Later, he moved to the economic department, where he was responsible for investment profitability studies for refining and petrochemicals projects. Dr. Benazzi holds a PhD in chemistry from the University of Paris, and he graduated as a chemical engineering from the ENCSP. He holds over 110 US patents in the field of refining and petrochemicals areas.

he hydrocarbon marketplace is influenced by many factors: governmental energy policies, legislation, economic growth, access to resources and technological innovation. As a technology suppliers’ success depends on how well they fulfill the needs of the marketplace at the present, short-term and long-term, they must be acutely aware of and adapt to the evolving market.

Demand outlook. Our current petroleum product demand

forecast shows that recovery back to 2007 levels—86 million bpd

(86 MMbpd)—should occur around 2012, rise to 94 MMbpd–95 MMbpd by 2020 and approach 102 MMbpd in 2030—essentially the level predicted for 2020 just a year ago. From now until 2020, demand growth for petroleum products will occur mainly in the Asia-Pacific region (+6 MMbpd) and the Middle East (+2.4 MMbpd). In contrast, demand for petroleum products is forecast to decrease in the North Atlantic basin. This trend confirms that refining investment is moving from mature markets to developing countries. Growth in on-road diesel demand, currently at 1.8%/yr, should continue at a rate higher than that of gasoline (0.5%/yr) for which new demand will be mainly located in emerging nations. Reduced US gasoline consumption, combined with an ever-increasing share of ethanol in the gasoline market, is threatening one of the principal outlets for excess European gasoline, (about 1 MMbpd in 2007). If this problem wasn’t enough for the European producers, the diesel fuel deficit for this region is expected to increase, from 0.5 MMbpd in 2007 to more than 1 MMbpd in 2020. Adding flexibility to the refining structure. Given the market changes described here, refiners in developed countries will consider optimizing and adding flexibility to their existing facilities. The continuing gasoline-diesel imbalance in the Atlantic markets will result in introducing innovative processes and HYDROCARBON PROCESSING SEPTEMBER 2009

I 47

HPI VIEWPOINT BTL ex-waste wood

1st

Stage

2nd

3rd

Stage

Common makeup compressor

To fuel Common HP and MP gas amine PSA and MPU

Diesel engine

VGO

H-OilRC reaction

Naphtha

VGO HyK separation and Euro V ULSD fractionation

H-OilRC separation and fractionation

Naphtha and gas oil Low-sulfur fuel oil

Gasoline engine

Flow diagram of an integrated hydrocracking unit with an ebullated-bed VR hydrocracker.

selective catalysts that enable higher diesel production. Notable examples are those technologies that allow optimizing light cycle oil (LCO) production from existing fluid catalytic cracker (FCC) units. Additional hydrotreating or hydrocracking capabilities will be required to upgrade LCOs due to their high sulfur content and low cetane number. The new capacities will apply catalysts whose improved performance enable better LCO hydrotreatment and favor more selective chemical reactions that improve cetane number. Incidentally, light FCC cuts contain olefins, which can be transformed via oligomerization to a good quality blending stock for the diesel pool. Some refiners may consider equipping their FCCs with mild hydrocracking units to pre-treat the FCC feedstock and to produce additional diesel. A mild hydrocracking section integrated with a finishing middle distillates hydrotreater enables direct production of on-specification diesel while upgrading the LCO and light coker gasoil (LCGO) streams. Squeezing the most from the bottom-of-the-barrel.

Higher crude prices and resurgence in demand will renew interest in bottom-of-the-Barrel (BoB) conversion projects—notably those producing the highest motor-fuel yields over carbon rejection technologies. These projects should particularly favor technologies such as vacuum residue (VR) hydrocracking in ebullated beds coupled with a solvent deasphalting unit permitting maximized motor fuel yields, ultimately reducing the amount of heavy residue. To minimize capital expenditure and to optimize energy efficiency, integrated schemes will be preferred. An interesting example is integrating a hydrocracking unit with an ebullated-bed VR hydrocracker (H-OilRC ). This enables both vacuum gasoil (VGO) from the hydrocracker and straight-run VGO to be converted to diesel (Fig. 1). This scheme applied optimized management of its high-pressure pure-hydrogen network feeding two hydrocracking units and includes an amine section. In other examples, schemes such as a VR hydrotreater upstream of a residue fluid catalytic cracker (RFCC) and a VGO hydrocracker, which will respond to demand for a more balanced production of gasoline and diesel. 48

I SEPTEMBER 2009 HYDROCARBON PROCESSING

GTL

EtOH ex-cellulose EtOH ex-sugar beet

Biodiesel

+6% +26% Conventional diesel

-76% -54%

DISI 2010

Bioethanol Conventional gasoline

0 20 40 60 80 100 120 140 160 180 200 WtW GHG emissions (g CO2 eq./km) BTL = Biomass-to-liquids; FAME = fatty acid methyl ester; GTL = Gas-to-liquids; CTL = Coal-to-liquids; CCS = Carbon Capture and Storage; LCB = Lignocellulosic biomass; DICI = Direct injection compression ignition; DPF = Diesel particulate ﬁlter; DISI = Direct injection spark ignition Source: Eucar-Concawe-JRC “Well-To-Wheels” Report, Version 3, November 2008

FIG. 2 FIG. 1

-52%

DICI 2010 +DPF

VGO ex H-Oil

VDU

-93%

CTL + CCS

H2 rich gas

VGO HyK reaction

FAME ex-Rapeseed

Well-to-wheels CO2 emissions for various transportation fuels and their feedstock.

We forecast that the global amount of additional conversion projects, to be realized before 2020–2025, should be about 5 MMbpd including hydrocracking, coking and catalytic cracking. Product quality trends. Since the 1990s, successive regula-

tions have improved fuel quality in the US and EU. Nowadays, gasoline and diesel in these regions have become products with almost no sulfur and low levels of aromatics and olefins. European legislators are turning their attention to reducing sulfur content in heating oil from the 1,000 ppm level to a lower value such as the case in Germany, where it has been reduced to 50 ppm. Other changes in sight are lower sulfur levels (10-ppm S) for off-road engine fuels, e.g., locomotives and agricultural and construction equipment; in the domestic marine sector, sulfur content will be reduced from 300 ppm to 10 ppm in 2012. A similar trend is observed in the US. As hydrotreating capacity is fully utilized, the new 10-ppm sulfur specifications will increase the product volume to be desulfurized. This will be in addition to on-road fuel hydrotreating capacity requirements. Through 2020, to meet both the global demand for desulfurized fuels and specification trends, Axens estimates the additional hydrotreating capacity will approach 10 MMbpd (including naphtha, middle distillates and residue hydrotreating). It is expected that catalyst performance, specifically activity, will continue to improve as the commercial experience curve at ultra-low-sulfur levels progresses. Coker feedstocks can be particularly challenging because impurities can be problematic when chasing the last traces of sulfur. In-depth understanding of hydrotreating and hydrocracking reaction kinetics has advanced through progress made in the analytical area. Catalyst modeling and engineering will continue to progress, providing the industry with more active, selective, stable and resistant formulations. Marine bunker fuel issue. One of the most important challenges could come from the proposed changes to bunker-fuel quality. The current Emission Control Area (ECA) standards specify 1.5% maximum sulfur content in bunker fuel for applicable areas. By 2010, this limit will drop to 1% maximum, with a further reduction to 0.1% in 2015. Outside the ECAs, the

HPI VIEWPOINT maximum sulfur content would be limited nology suite for converting synthesis gas to 3.5% in 2012 compared with the current ■ Innovative processes (H2 + CO) from various origins—natural 4.5%. A further reduction to 0.5% is schedgas, biomass and coal—into waxy materials uled for 2020. This step will be subject to a and catalysts will be used that are hydrocracked into ultra-clean liquid study in 2018. However, if an availability to resolve the continuing fuels (XTL). issue appears, it can be delayed to 2025. To comply with the GHG emission limiThe reduction to 3.5% sulfur outside gasoline-diesel imbalance. tations, refineries will need to implement a ECAs and to 1% within ECAs can be combination of new technologies, energy achieved by excluding high-sulfur streams efficiency improvements and projects such from the blends. The further reductions to 0.5% and 0.1% respecas clean development mechanisms (CDM). Axens has developed tively outside and within ECAs are much more problematic. In a comprehensive Energy Efficiency Improvement Package that 2020, marine bunker fuel demand is forecast to be about 3.9 enables the identification, technical feasibility and economics MMbpd and represents 50% of the heavy fuel-oil market. Howof projects having potential to reduce energy consumption and ever, with limited availability of low-sulfur crudes, segregating comply with CDM criteria. residues from low-sulfur crudes will probably be insufficient to meet the growing demand in low-sulfur bunker fuels. What’s next? To meet future demand in motor fuels, coal will Moreover, if residue hydrodesulfurization (RDS) Hyvahl techplay a key role in areas with large coal resources and lacking crude nology could produce bunker fuel at 0.3% sulfur, current technoloils. Axens’ direct coal liquefaction (DCL) process is available to ogy is not able to reach values as low as 0.1%. Considering the produce high-quality distillate fuels using commercially proven high investment only to desulfurize residue, refiners will prefer ebullated-bed reactor system. While indirect coal-to liquids (CTL) to convert residue into higher value products such as distillates. technologies are based on Fischer–Tropsch technology, both DCL Investment decisions will depend on location, specific conditions and CTL plants should integrate CCS solutions owing to their and economy of scale. RDS investments could be profitable only higher well-to-wheel CO2 emissions (Fig. 2). if the bunker fuel prices rise into the middle distillate range. Alternative liquid fuels, i.e., first- and second-generation ethanol, biodiesel, gas-to-liquids (GTL), BTL, CTL and DCL, repBeyond quality product: GHG emissions reduction. resent about 2.5% (energy content) of the on-road demand. We For many years the focus has been on air quality. Vehicle manuestimate that they could represent up to around 7% in 2020 and factures and refiners have met the challenge by increasing vehicle 9%–10% in 2030. HP fuel efficiency and producing cleaner fuels. Recent and future changes will focus on reducing greenhouse gas (GHG) emissions while demand and quality changes continue to push refining carbon dioxide (CO2) emissions higher, notably those related to Sulzer SMVTM Static Mixer diesel demand growth and stricter sulfur specifications for marine The key to crude oil desalting and fuel oils. In Europe, the Energy and Climate Package targets a 20% increase in energy efficiency by 2020, a 20% cut in GHG emissions, compared with 1990 levels, and a 20% share of renewable fuels in the EU energy consumption. The objectives of the EU program could probably not be met without contributions from renewable fuels and commercial deployment of carbon capture and sequestration (CCS) technologies. For these reasons, the Renewable Energy policy and Climate Change package includes: • Low-carbon biofuels directive targeting a 10% energy content in transport fuels by 2020 and sustainability criteria for biofuels • Proposed directive to promote CO2 capture and storage (CCS) • New vehicle efficiency targets, the objective for 2015 is 130 g/km CO2 emissions equivalent to diesel consumption of 5 liters/100 km. A further decrease is targeted at 95 g/km CO2 in 2020. MOVING AHEAD CT.29e The key technologies of interest for supplying liquid biofuels are mainly vegetable oils to diesel, bio-ethanol from sugar fermen• Excellent desalting efﬁciency due to Sulzer Chemtech tation, cellulosic feedstock and biomass-to-diesel (BTL). large interfacial surface area Europe, Middle East and Africa Axens has developed the first continuous, heterogeneousPhone +41 52 262 67 20 • Smallest settler size due to narrow sulzermixer@sulzer.com drop size distribution catalyst transesterification process that produces high-quality North and South America • Reduced carry-over and carry-under Phone +1 918 446 6672 first-generation biodiesel and glycerin while generating no waste sulzermixer@sulzer.com • Short payback time products. Moreover, to respond to future BTL diesel demand, Asia Paciﬁc For more information, visit Phone +65 6515 5500 which substantially reduces the well-to-wheel CO2 emissions www.sulzerchemtech.com sulzermixer@sulzer.com (Fig. 2), Axens is now expanding its Gasel Fischer-Tropsch techSelect 157 at www.HydrocarbonProcessing.com/RS

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Producing Solutions

REFINING DEVELOPMENTS

SPECIALREPORT

Maximize liquid yield from extra heavy oil Next-generation hydrocracking processes increase conversion of residues G. BUTLER and R. SPENCER, BP International Ltd., Sunbury, UK; B. COOK and Z. RING, BP Products North America, Naperville, Illinois; and A. SCHLEIFFER and M. RUPP, BP Refining & Petrochemicals GmbH, Bochum, Germany

Demand

Oil shale

Russia

Brazil Other North America

US Deepwater West Africa

Iran

UAE Kuwait Other M. East China

Other Central Asia

US Alaska

Gas-to-liquids Coal-to-liquids

Kazakhstan Indonesia

Next phase of in-situ oil sands

Canadian tar sand Ven-Heavy US Stripper

Europe

50 40 30 20 10 0

Saudi Arabia

low-capital-cost resid conversion to marketable fuels has been a long-term goal for the industry. A wide range of resid conversion technologies has been developed and deployed in the refining industry, including various coking technologies, resid fluid catalytic cracking (FCC) and ebullating bed hydrocracking. Historically, the drive for gasoline and reasonably strong markets for petroleum coke have made delayed coking the most

Average supply price*, $/bbl

Options for upgrading. Continuous

prolific resid conversion technology. Future demand for clean low-sulfur products such as ultra-low-sulfur diesel (ULSD), plus potential future limits on fuel oil and petroleum coke due to environmental reasons may prompt different technology choices. Coking and visbreaking are low-pressure, thermal-cracking processes with relatively low capital costs that make them economic in a low crude cost environment. Visbreaking is a low-conversion thermal-cracking process for improving fuel oil viscosity. Conversion is limited such that no solids are produced. Visbreaking is predominantly used in low-conversion hydroskimming refineries that produce large amounts of fuel oil. Coking processes, in contrast to visbreaking, are high-conversion thermal processes that produce large amounts of solid coke as a product. Delayed coking, by far the most prolific residconversion process, is a batch process where the resid is heated in fired furnaces and then conversion and coke production are completed in large coke drums. Solid-coke production often represents 30 wt% or more of the product from delayed cokers. Coke is primarily sold as solid fuel to heavy industry, but small amounts of high-quality cokes are often sold as higher-value speciality cokes, such as anode coke.

North Africa Other Asia Other South America

nvironmental pressures, energy security, changing feedstocks and evolving product preferences will all play a part in transforming refining by 2030. By 2030, there will be more than 2.1 billion vehicles on the worldâ&#x20AC;&#x2122;s roads, compared with just 900 million today. Forecasts suggest that fuels derived from crude oil, chiefly gasoline and diesel, will continue to dominate the transportation-fuels market. So, refineries will continue to provide the largest market share of transportation fuels. Yet, the future of refining will be different for various regions. While the Organization for Economic Cooperation and Development (OECD) countries are expected to have shrinking fuel markets due to improved car efficiency and demographics, all the growth will focus on developing countries, especially China and India. Overall, the International Energy Agency forecasts a global demand for 2030 of 107 million bpd (MMbpd) with variation between 98 MMbpd and 116 MMbpd for low- and high-economic growth scenarios (May 2009). Fig. 1 shows that this demand increase from the current 84 MMbpd will move the supply basis to heavier feedstocks and eventually to unconventional, nonpetroleum-based resources. There will be further pressure on the global refining system due to the decreasing demand for fuel oil. Most prominent is the discussion to significantly lower the bunker fuel sulfur content or to 120 even fuel ships with distillate fuels. The 110 100 ability of a refinery for residue upgrading 90 will become a key factor to its competitive80 Price ness and will lead to a renewed interest in 70 upgrading technologies. 60

5 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90 95 100 105 110 115 Production capacity, MMbpd New technology Existing production

*Break-even oil price for new capacity additions (WTI price at which new investment is economic). Source: EIA; Wood Mackenzie; Mckinsey analysis

FIG. 1

Cost of new crude oil production.

HYDROCARBON PROCESSING SEPTEMBER 2009

I 51

SPECIALREPORT

REFINING DEVELOPMENTS

Fluid coking and flexi-coking processes operate continuously, and, in the case of flexi-coking, eliminate solid coke as a product. Several continuous coking processes have been commercialized, but they have not been as broadly applied as delayed coking. The naphtha and mid-distillate products of coking processes are low quality and require secondary hydroprocessing before final blending into motor fuels. When paired with FCC for cracking of the heavy coker gasoil, delayed coking is ideally suited to produce high amounts of gasoline from petroleum resid. The FCC process has also been adapted to run residue feeds. Resid FCC generally produces higher-quality gasoline product directly, and coke is burned to provide heat for this process. But processing resid adds significant capital expenses (CAPEX) to FCC operations. Resid FCC is relatively limited in the amount and quality of resid processed as high coke make requires more complex regenerator designs with catalyst coolers to remove heat not required by the process. High catalyst coke and high regenerator temperatures contribute to greater catalyst consumptions vs. normal FCC operations. Resid FCC has generally been used for conversion of low amounts of higher-quality resids and has had much lower application than delayed coking. Ebullating bed hydrocracking process. In the 1970s, in response to high oil prices, significant effort was spent in developing resid hydrocracking processes that add hydrogen rather than reject carbon. The processes that achieved widest application were the ebullating bed hydrocracking processes. These processes are continuous and produce higher levels of liquid fuels (no coke). But they are unable to achieve complete resid conversion and still produce resid product. Ebullating bed processes have not achieved

huge deployment due to high capital cost, which makes them the least robust at low-oil price scenarios. Ebullating beds have also been prone to high operating costs, and have sometimes been plagued with low operability. The liquid products, although improved vs. coking, still require secondary processing to produce clean fuels. The inability to achieve near complete conversion still requires processing to convert the unconverted resid. Emerging technologies. Conversion limitations in ebullat-

ing bed hydrocrackers are mainly caused by problems due to solids formation in the high-conversion mode. Slurry-type technologies originally designed for coal liquefaction are able to cope with solids formation that is a result of asphaltene degradation. The slurries are set up either by additives or by catalyst addition. These reactors have no internals and show a high degree of back mixing to ensure temperature and concentration homogeneity. The slurry transports all formed solids safely out of the reactor. Some slurrytype processes can achieve more than 90% residue conversion. The first commercial application of slurry-phase hydrocracking was operated successfully in Germany in the 1950s in modified coal liquefaction units. Later developments took place in Germany (1980s), and in Canada (1980s) and in Italy (1990s). These technologies are differentiated by operating pressures and catalyst additives. One slurry-type process uses higher pressure with a lower cost additive and higher space velocity than other technologies. The differentiating feature is the integrated hydrotreater (IHT), which gives high product qualities and simplification in downstream processing. By comparison, the second type of slurry-phase hydrocracking process operates at low pressure and uses a sophisticated molyb-

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I SEPTEMBER 2009 HYDROCARBON PROCESSING

Select 158 at www.HydrocarbonProcessing.com/RS

REFINING DEVELOPMENTS Ammonia, hydrogen sulﬁde

Residue Hydrogen Additive

Slurry phase hydrocracker

Hot separator

Trickle-bed hydrotreater

Hydrocarbon gases Hydrocarbon liquids

Hydrogenation residue FIG. 2

Next-generation slurry-phase hydrocracking flow diagram.

SPECIALREPORT

Additive Slurry-phase Hot Integrated mixing system reactor separator hydrotreater

Recycle gas puriﬁcation

Additive

Offgas

Vacuum residue Hydrogen

Naphtha

SR VGO

Middle distillate VGO Sour water Hydrogenation residue Preheating

FIG. 3

Vacuum distillation

Cold Product separator fractionation

Next-generation slurry-phase hydrocracking process scheme.

100

Residue C1 – C4 Naphtha Distillate VGO

80 Wt % of feed

denum catalyst. To ensure the stability of the slurry-phase reactor, conversion is limited to a medium range. A solvent-deasphalting unit separates products from the unconverted bottoms that are recycled to the slurry-phase reactor. By using the recycle, this process also achieves high overall conversion. Other slurry-phase hydrocracking technologies are in between these two cases. There are trade-offs between simple operation at high pressure and more complex configurations with lower space velocities, and, therefore, larger pressure vessels are necessary. High pressure ensures higher process stability and flexibility, and the integrated hydrotreating reduces propagation of costs throughout the host refinery during commercial integration. Up to now, none of these developments are in commercial use. However, a low-pressure slurry-phase hydrocracking commercial unit is under construction in Italy for 2012 startup, and in Venezuela, there is an ongoing slurry-phase project.

Next-generation slurry-phase technology. The con-

cept of next-generation slurry-phase hydrocracking technology combines, as shown in Fig. 2, a thermal slurry-phase reaction system with a trickle-bed hydrotreater at the same temperature and pressure level in a fully integrated unit. The linking element is the hot separator, which ensures proper separation and withdrawal of unconverted material. This integration has distinct advantages through CAPEX savings, high product qualities and improved thermal efficiency vs. other technologies. In the more detailed process scheme (Fig. 3), the residue prior to processing is mixed with an additive and then fed into the highpressure section of the conversion unit. Typically, operating pressure is between 180 bar and 230 bar. After adding hydrogen and the preheated recycle gas, the total feed stream is heated to reaction conditions and injected into the slurry-phase reactor system, which is a cascade of reactors to overcome the drawback of back mixing. Reaction conditions are adjusted to provide 95 wt% conversion of the residue on a once-through basis. Residue is defined as a material boiling above 524°C. Asphaltene (C7 insoluble material) conversion is almost on the same level as residue conversion. In the hot separator, the converted material is separated from unconverted material, which is withdrawn as a hot-separator bottom stream. This stream still includes a certain amount of distillates that are recovered by vacuum distillation, leaving the hydrogenation residue as a drag stream. These distillates together with the hot separator overhead stream, are fed into the integrated hydrotreater. Syncrude option. There is the option to add straight-run distillates directly to the hydrotreater feed stream, which allows wholebitumen processing in heavy-oil upgrading. Within the integrated

20 0 85% FIG. 4

90% Residue conversion, wt % of feed

95%

Process yields for different primary conversion levels.

hydrotreater, the syncrude composition and quality are adjusted. Effluents from the integrated hydrotreater are routed back to the preheat train of the primary conversion section for heat recovery. After cooling and depressurizing, the associated water and gas are separated from the syncrude. The stabilized syncrude is then fractionated according to the requirements the refinery. Gases, separated from the syncrude, are purified by means of a lean-oil wash or an amine system. The hydrogen-rich gas stream gained from this purification step is recycled and added to the feed stream of the slurry-phase step. It is also used as quench gas for reactor temperature control. The hydrogenation residue containing the additive, metals and unconverted material can be further processed either directly (e.g., coker cofeed) or solidified, stored and transported for offsite use (cement, coke oven, gasification). Yields. Fig. 4 shows the yield distribution of the next-generation slurry-phase hydrocracking process for primary conversion levels of 85%, 90% and 95% at similar second-stage severity. Naphtha HYDROCARBON PROCESSING SEPTEMBER 2009

I 53

SPECIALREPORT

REFINING DEVELOPMENTS TABLE 1. Product qualities

Wt % of feed

50 40

Slurry phase step Low severity IHT High severity IHT

Naptha (IBP–350°F)

(350°F–650°F)

10 0 Naphtha

Middle distillate

Vacuum gasoil

Yield distribution depends on 2nd stage severity.

and distillate yields rise with increasing residue conversion, but the vacuum gasoil (VGO) yield remains constant. Gas formation increases with conversion. The severity of the integrated hydrotreater operation has a strong impact on yield distribution. Fig. 5 shows the impact of high- and low-severity operations compared to the yield distribution of the primary conversion step. Naphtha yields increase with severity from 10 wt% to 20 wt% and diesel from 40 wt% to 60 wt%. Correspondingly, the VGO decreases from 50 wt% to 20 wt%. This flexibility can be used by space velocity selection in design or by adjusting inlet temperatures to the 2nd stage during operations. The absolute values are dependent on the feedstock and can also be influenced by catalyst selection. Flexibility is normally limited by product quality requirements.

Elemental Analysis of Fuels

Determination of Sulfur and other elements at-line and in the laboratory 54

~2 ppm

Reformer feed

~2 ppm

(assumes S trap) Diesel blending

Distillate

FIG. 5

Sulfur Nitrogen

I SEPTEMBER 2009 HYDROCARBON PROCESSING

Sulfur

< 10 ppm

Cetane No.

> 45

Cloud point

< –15°C

Vacuum gasoil (650°F–1,050°F)

Sulfur

100–300* ppm

CCR

< 0.15 wt%

Metals

< 1 ppm

FCC feed

* assumes Athabasca 6 w/o sulfur content

High-product qualities are special features of the next-generation slurry-phase hydrocracking process and they accordingly minimize the impact on downstream processing within refinery integration. Stable, tradable products and intermediates are produced directly from the integrated unit. Table 1 shows that naphtha is almost at reformer feed spec, and that it will be no burden for the reformer pretreater or it can be finished by a sulfur trap. Diesel is at pool spec for ULSD and VGO can be sent to the FCC without pretreating. Not shown is the kerosine cut, which complies with jet fuel requirement for smoke point and cloud point. Specifications for diesel typically determine operating severity of the next-generation slurry-phase hydrocracker-integrated hydrotreater. Going along with a diesel of less than 15 ppm of

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REFINING DEVELOPMENTS

and oil and coal liquefaction are being progressed with the expectation that they will compare favorable economically and environmentally with other process schemes.

Coker Ebullated bed New slurry-phase hydrocracking process

Future of heavy-oil upgrading. The next-generation

NPV

Base x 5

Base 0.0 50 FIG. 6

75 US $/bbl Brent

SPECIALREPORT

100

Comparative economics.

sulfur and a cetane number greater than 45, the sulfur content of VGO is less than 300 ppm and sulfur content of naphtha is less than 5 ppm. Kerosine smoke point is above 20 mm and the cloud point is below –30°C. Economics. The next-generation slurry-phase hydrocracking

technology has distinguished margin and quality advantages over delayed coking and ebullating bed hydrocracking. The drawback is seen in the higher CAPEX for the high-pressure process. To get clarity about comparative economics, a case study on a refinery upgrade for heavy-oil processing based on medium- and longterm market expectations was conducted. Key features of the next-generation slurry-phase hydrocracking process in this study compared to coking were the high liquid yield and the high product qualities that reduce downstream hydrotreating requirements and partly offset the capital disadvantage. Ebullating bed hydrocracking requires a much larger unit to support a lower space velocity and lower conversion rate; all result in significantly higher CAPEX. Fig. 6 shows the influence of crude price scenario on net present value (NPV). All three options benefit from an increasing crude price scenario. Due to the higher yield, this is more pronounced for the hydrocracker options than for coking. The nextgeneration slurry-phase hydrocracking process becomes more economically attractive at crude prices above $50/bbl than coking, whereas ebullating bed hydrocracking needs at least crude price scenarios of 90 to 100 $/bbl. This analysis also factored in additional CAPEX for the next-generation slurry-phase hydrocracking technology for being the first commercial unit; it proves its viability even under the present economic environment. Look ahead. Since 2006, new engineering and experimental

capabilities have been invested to fully use the next-generation slurry-phase hydrocracking technology. Plans include applying this technology as part of a large upgrade project for a major refiner. Current development programs are focusing on process and engineering improvements. Design modifications based on new metallurgy can increase hydraulic capacity by more than 30%, resulting in significant capital-cost savings. Incorporation of new hydrotreating catalyst generations will lead to further capital and operational cost savings and will increase process flexibility and improve distillate qualities targeting European or CARB diesel standards. Currently, process improvements to the demonstrated co-processing of coal

slurry-phase hydrocracking technology was successfully operated at a demonstration scale (3,500 bpd) for more than one decade. Distinguishing features include residue conversion of more than 95%; high stability and availability due to high-pressure operation; high feedstock availability; flexible yield pattern; high product qualities matching clean fuel standards and simple refinery integration, low downstream impact. Refining case studies show that the technology is break-even in NPV terms to delayed coking at crude prices of about $50/bbl and is significantly advantaged at higher price scenarios. HP BIBLIOGRAPHY Niemann, K. and F. Wenzel, “The VEBA-COMBI-CRACKING-Technology: An Update,” Fuel Processing Technology, No. 35, 1993, pp. 1–20 and subsequent unpublished results. Montanari, R. et al., “Convert heaviest crude bitumen into extra-clean fuels via EST--ENI Slurry Technology,” NPRA Annual Meeting, March 2003, San Antonio, Texas.

Graham Butler has a DPhil in chemistry from the University of Sussex, UK. Dr. Butler joined BP in 1985 to lead the syngas conversion program. Dr. Butler was a key contributor to BP’s long-term technology strategy development, while serving as new technology manager in BP’s global refining business from 2000–2009. His current position is manager, special project in BP’s Refining and Logistics Technology organization.

Bruce Cook is currently BP advanced refining manager. He has a PhD in chemistry from the University of Illinois at UrbanaChampaign. He holds over 35 US patents and is the co-author of 17 publications.

Andreas Schleiffer graduated from the University of Clausthal Zellerfeld with an MS degree in process engineering before joining the VEBA Oel VCC development team in 1987. In 1998, he joined the BP/Mobil JV to manage technical modifications for the lube oil refinery in Hamburg, Germany. In 2008, Mr. Schleiffer joined BP’s Refining and Logistics Technology. His role is to support reactivation and future development of VCC technology as team leader for residue hydrocracking engineering.

Zbigniew Ring is currently BP leader of technology development, residue hydrocracking. He graduated from the Polytechnic University of Warsaw, Poland, and obtained a PhD in chemical engineering from the University of Toronto, Canada. After graduation, Dr. Ring joined Shell Canada Research. Later, he was manager of secondary upgrading and refining, and then program manager of the Canadian National Centre for Upgrading Technology.

Richard Spencer is a principal process engineer in the commercial and strategic support group of BP’s Refining and Logistics Technology organization. In this role, he is responsible for management of refinery configuration studies including development of capital costs, heat and material balances and economics. He has 10 years of experience within BP’s petrochemicals and refining businesses. He is a UK Chartered Engineer. Mr. Spencer holds an MEng degree in chemical engineering from the University of Cambridge, UK.

Martin Rupp is currently program manager for residue hydrocracking technologies in BP’s Refining and Logistics Technology organization. He holds a Diploma in chemistry followed by a PhD in chemical engineering from the University of Karlsruhe, Germany. He has more than 25 years of experience in the refining industry in VEBA Oel and BP, mainly in research and technology. HYDROCARBON PROCESSING SEPTEMBER 2009

I 55

Results

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REFINING DEVELOPMENTS

SPECIALREPORT

Greenhouse gas emissions: Characterization and management Proposed federal measures may require that refiners report and mitigate greenhouse gas emissions P. GUNASEELAN and C. BUEHLER, Exponent, Inc., Houston, Texas; and W. R. CHAN, Exponent, Inc., Seattle, Washington

ecent developments in US climate change legislation and regulation of greenhouse gases (GHGs) are encouraging refiners to take a serious look at the GHG emissions from their facilities, and to explore strategies to reduce their GHG footprints. The refining process involves separation and reaction processes that have significant energy requirements that are largely met through the combustion of fossil fuels, resulting in both direct GHG emissions at refineries, and indirect emissions when the energy is imported. Additional GHG emissions are generated from the combustion of accumulated carbon during catalyst regeneration, during hydrogen (H2) production via steam reforming of hydrocarbons and from numerous other sources and activities throughout the refinery. Increasingly stringent specifications on the allowable sulfur content in gasoline and diesel fuel have boosted H2 consumption in US refineries, while the processing of heavier crude oil has necessitated additional conversion processes, resulting in greater energy and H2 consumption. With the ongoing trend of heavier and more sour crude oil feeds to US refineries,1 the GHG footprint of refining is expected to increase unless active mitigation steps are taken. Strategies for reducing the refining GHG footprint may include energy efficiency improvements, fuel switching, carbon capture and increasing the share of transportation fuels that have lower life cycle GHG emissions. Legislation and regulation. In recent years, there has been an increasing political initiative in the US at the state and federal levels to introduce legislation

to curb GHG emissions. Some of the early milestones of US climate change action were at the state level and include formation of the Regional Greenhouse Gas Initiative (RGGI) in 2005 comprising 10 northeast states to curb power-plant GHG emissions;2 passing of the California Global Warming Solutions Act of 20063 (more commonly known as Assembly Bill 32); establishment of a low-carbon fuel standard (LCFS) in California in January 2007 by the governor’s executive order;4 and a landmark decision by the Supreme Court in April 2007 in favor of several states against the US Environmental Protection Agency (EPA), authorizing the EPA to regulate GHG emissions under the Clean Air Act and to set GHG emission standards for motor vehicles.5 These developments have motivated US refiners and manufacturing firms to more actively manage the GHG footprint of their existing and planned assets, and also assess the life cycle GHG intensity of their products. Thus far, 2009 has seen a greater urgency for climate change action at the federal level, with the proposed American Clean Energy and Security Act (also known as the Waxman-Markey bill) being passed by the House of Representatives in June 2009,6 and EPA’s proposed GHG endangerment finding7 and proposed rule for mandatory reporting of GHG emissions,8 both signed and published in the Federal Register in April 2009. Industry stakeholders and advocates caution that the cap-and-trade provisions in the Waxman-Markey bill allocate inadequate allowances to the refining sector to help offset the GHG emissions that it will be held accountable for, which would encumber it with compliance costs that may dimin-

ish its global competitiveness and drive up transportation fuel prices.9–12 While the bill is yet to receive senate approval, the aforementioned developments increasingly point to more stringent federal and state oversight in the future on GHG emissions from the US refining sector. GHG footprint of refining. According to a 2002 report by the Energy Information Administration (EIA) based on its Manufacturing Energy Consumption Survey (MECS),13 GHG emissions from petroleum refineries totaled about 278 million metric tons of carbon dioxide (CO2) equivalent (MtCO2e) in 2002. More than half of the GHG emissions were from the combustion of petroleum-based fuels in refineries, namely refinery fuel gas (RFG) and petroleum coke (pet-coke). The remaining CO2 emissions resulted from the use of natural gas and electricity.* GHG emissions from US refineries are modest relative to the total emissions from the transportation sector, which is a significant source of GHG emissions in the US. According to the EPA’s 2007 GHG inventory,14 the transportation sector was responsible for GHG emissions of about 2,000 MtCO2e, which represented 28% of the total US GHG emissions in 2007. About 60% of the 2007 GHG emissions from transportation resulted from gasoline combustion in automobiles. The remaining GHG emissions mainly originated from other transportation activities, such as the use of diesel fuel in heavy-duty vehicles * It is unclear whether the EIA estimate includes noncombustion process CO2 emissions from refinery hydrogen plants based on steam reforming, which can be substantial. HYDROCARBON PROCESSING SEPTEMBER 2009

I 57

REFINING DEVELOPMENTS

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Residential 1,178 (17%) Commercial 1,151 (16%) US territories 53 (1%)

Industrial (excluding reﬁning) 1,774 (25%)

Industrial 2,052 (29%)

Agriculture 595 (9%) Transportation 1,952 (28%)

Petroleum reﬁning 278 (4%) of total

Total 2002 US GHG emissions 6,981 MM metric tons of CO2 equivalent (MtCO2e) All emissions in MtCO2e Figure data sources: 2008 US EPA Report: “Inventory of US Greenhouse Gas Emissions and Sinks: 1990-2006”, and Schipper (2006), EIA: “Energy-related Carbon Dioxide Emissions in US Manufacturing”.

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Select 160 at www.HydrocarbonProcessing.com/RS

FIG. 1

GHG footprint of refining compared to other US sectors, 2002.

80%

Oil extraction

Oil transport

1% 2%

10%

Oil reﬁning

Fuel distribution

Fuel combustion

Figure data: “Development of Baseline Data and Analysis of Life Cycle Greenhouse Gas Emissions of Petroleum-Based fuels”, National Energy Technology Laboratory, Ofﬁce of Systems, Analyses, and Planning; 2009; DOE/NETL-2009/1346.

FIG. 2

Contribution of refining to US transportation fuel life-cycle GHG emissions.

and jet fuel in aircraft, and also include a small contribution from hydrofluorocarbon (HFC) emissions from mobile airconditioning and refrigerated transport. The EPA estimate of the transportation sector GHG footprint does not include emissions generated during the extraction of petroleum and its subsequent refining to transportation fuels. Fig. 1 compares the refining GHG emissions estimated in the 2002 EIA report to contributions from other US economic sectors, as defined in the EPA GHG inventory.14 Per these estimates, refining emissions comprised 4% of the total US GHG footprint, and amounted to 15% (or about

1/7) of the size of the GHG footprint of fuel-combustion emissions in the transportation sector.** Transportation fuel life cycle. Unlike

a GHG emission inventory that typically only accounts for the direct emissions from a given sector or facility, a GHG life cycle analysis (LCA) considers the broader supply chain and takes into account emissions associated with preceding and subsequent activi** The calculation excludes mobile HFC emissions from air-conditioning and refrigeration from the transportation GHG footprint, because they do not originate directly from transportation fuels.

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SPECIALREPORT

REFINING DEVELOPMENTS

ties for a given product, facility or TABLE 1. Potential refinery GHG emission sources20,21 mates are summarized in Fig. 2, sector. There are three key comand agree well*** with estimates Representative sources ponents of an LCA for the trans- Category from a 2006 EPA study19 based portation sector: vehicle, fuel and Combustion devices on two leading transportation Boilers, heaters, engines, turbines, incinerators infrastructure. Each of the three Stationary sources emissions models: the Lifecycle and flares components has its associated Emissions Model (LEM),15 and Mobile sources Vehicles, barges, ships and railcars upstream, direct and downstream the Greenhouse Gases, Reguemissions. The transportation fuel Vent sources lated Emissions, and Energy FCC catalyst regeneration, H2 plants and life cycle is directly relevant to the Process vents Use in Transportation (GREET) fluid coking units refining industry and will be dis- Other vents model.16 Fig. 2 also illustrates Storage tanks and loading racks 15–17 cussed further. Other sources that refining GHG emissions Area sources provide more detail on the vehicle Fugitive emissions are ⅛ (or about 13%) the size of Fuel gas system and other equipment leaks and infrastructure components of Other non-point sources the estimated footprint of transWastewater collection and treating equipment the transportation life cycle. portation fuel combustion based Nonroutine activities In a 2009 report, the National Maintenance/turnaround on the NETL estimate for 2005, Equipment blowdown and heater/boiler tube Energy Technology Laboratory which is reasonably consistent decoking (NETL) establishes baseline Other releases with our earlier estimate of 15% Pressure relief valves and emergency shutdown life cycle GHG emissions using (or about 1/7) based on the 2002 devices 2005 data for US petroleum- Indirect sources EIA report 13 and EPA GHG Offsite production of electricity, steam and H2 based fuels to serve as a benchinventory data,14 and helps frame mark for evaluating alternative fuels.18 According to the NETL estimate, attributable to refining. This is closely fol- *** The EPA study19 predicts higher noncombustion fuel cycle emissions for gasoline than for direct emissions from gasoline and diesel lowed by oil production (7%), with the rest diesel (in contrast to the respective NETL fuel combustion account for about 80% of the life cycle GHG emissions originating estimates that are very similar for both fuels), of the transportation fuel life cycle emis- from oil transportation (2%) and refined but the averaged EPA estimates for gasoline sions. About half of the balance, or 10% of fuels distribution (1%). and diesel are in good agreement with NETL the total fuel life cycle GHG emissions are The NETL fuel life cycle GHG estiestimates.

Light ends to gas plant

Hydrogen

Feed hydrotreating Naphtha

Naphtha hydrotreating

Catalytic reforming

Product hydrotreating

Gasoline

Diesel

Gasoline hydrotreating

Diesel hydrotreating

Gasoil hydrotreating

Hydrocracking

Hydrogen Upgrading Bottoms H Fired heater CO2 from fuel combustion Process CO2 source Reﬁnery fenceline

Delayed coking

Reﬁnery fuel gas system Boilers

Pet-coke

Primary CO2 emission sources within refineries.

I SEPTEMBER 2009 HYDROCARBON PROCESSING

Turbine

Utilities

Steam imports FIG. 3

Hydrogen plant

Power imports

Fuel imports

Hydrogen imports

Diesel

Gasoils

H Fluid catalytic cracking

Gasoline

Crude distillation units

Crude feedstock

Catalytic conversion

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SPECIALREPORT

REFINING DEVELOPMENTS

the relative size of refining GHG emissions in the transportation life cycle. Estimating GHG emissions. The

refining of crude oil to produce gasoline, diesel and other finished products involves reaction processes such as cracking, coking and reforming, as well as distillation steps that separate mixtures of hydrocarbons into various fractions. These processes have significant requirements of heat, steam and

electrical power that are met through the combustion of fossil fuels and result in substantial CO2 emissions. Regeneration of catalysts through the oxidation of accumulated carbon deposits, such as in fluid catalytic cracking (FCC) and H 2 production via steam-methane reforming (SMR), generate additional large quantities of CO2 that contribute significantly to a refinery’s overall GHG footprint (which comprises both direct

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CO2 emissions, such as from fuel combustion or processes within the refinery fenceline, and indirect emissions, such as those resulting from imported electric power and steam produced by fossil-fuel combustion). There is wide variation between individual refineries based on the volume and types of crude oils processed and their product slate. However, GHG emissions from a refinery generally occur from the following source categories: 1) combustion sources, 2) vent sources, 3) area sources, 4) nonroutine activities and 5) indirect sources. Table 1 lists examples of sources within each of these categories. Fig. 3 is a simplistic illustration of the refining process highlighting the major CO2 sources. In the spring of 2009, EPA proposed a rule that establishes mandatory GHG emissions reporting requirements for certain facilities, including all US petroleum refineries, beginning in 2010.8 The general monitoring, reporting, record-keeping and verification requirements are described in subparts of the rule for various source categories. The source category for petroleum refineries (subpart Y) provides specific details for individual GHG sources within a refinery, although in a few cases, the detail is provided within another source category, such as emissions from stationary combustion sources (subpart C), non-merchant hydrogen production (subpart P), onsite landfills (subpart HH) and onsite wastewater treatment (subpart II). In developing the GHG monitoring and reporting options, EPA considered a number of existing programs and guideline methodologies,22 such as the American Petroleum Institute (API),21 the Intergovernmental Panel on Climate Change,23 Environment Canada, 24 and the US Department of Energy.25 The EPA proposed rule is reportedly consistent with the methodologies used in existing programs and guidelines. The California Air Resources Board has also published a guideline for estimating refinery GHG emissions for the purpose of mandatory reporting,26 and has recently rolled out an Internet-based reporting tool for refinery GHG emissions.27 The specific GHGs of concern from refining include CO2, methane (CH4) and nitrous oxide (N2O). However, the CH4 and N2O emissions combined account for less than 1% of the total GHG emissions from a typical refinery on a CO2 equivalent basis.22 Accordingly, we will focus primarily on CO2 as it represents over 99% of the refining GHG emissions.

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SPECIALREPORT

REFINING DEVELOPMENTS

Stationary combustion sources.

Nearly all refinery processes require heat that is supplied through combustion of fossil fuels. Because of the high heat demands throughout a refinery, stationary combustion sources are a significant source of GHGs, primarily CO2. The predominant fuel used within refineries is RFG, which is a byproduct of several refining processes, and is a mixture of light hydrocarbons and H2. While the

quantity and composition of RFG produced can vary greatly between refineries based on the crude slate and processes in operation, the variation should be less within an individual refinery. In cases where RFG will not meet all of the refinery’s energy needs, purchased natural gas may supplement the RFG supply. There are four basic annual CO2 emission calculation methodologies or tiers in the EPA proposed rule based on the mea-

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sured parameters available, fuel type and rated heat input capacity for the source.8,22 Tier 1 uses the quantity of fuel consumed (based on measurements or other records) and values provided in the rule of the higher heating value (HHV) and CO2 emission factor for the specific fuel. Tier 2 is essentially identical to Tier 1, except that it requires measured HHVs for the fuel. For both Tiers 1 and 2, the rated heat input capacity for the stationary combustion unit must be less than 250 MMBtus. It is worth noting that the proposed rule does not provide HHV and emission factor values for RFG. Further, a portion of the RFG HHV is from H2 that does not result in GHGs on combustion. Tier 3 uses data for the fuel consumed and measurements of the fuel carbon content, while Tier 4 uses continuous emission monitoring system (CEMS) measurements for CO2 concentration and exhaust flowrate. Based on the source characteristics, reporting entities are required to use a specific tier calculation methodology, but they also have the option to use any higher tier. FCC regenerator. As the FCC process converts, or cracks, heavy hydrocarbon feed into light products by using a fine solid catalyst, coke tends to deposit on the catalyst surfaces and reduces its ability to crack the feed hydrocarbons. To restore the catalyst activity, coke is continuously combusted in the FCC catalyst regenerator generating CO2. Some regenerators operate in a partial-burn mode to produce carbon monoxide (CO) that is fed to a CO boiler for further combustion and heat recovery. In the calculation methodologies for FCC processes in the proposed rule, CO2 emissions are calculated from the exhaust gas volumetric flowrate, (either measured or estimated) and CEMS measurements of CO and CO2 concentrations in the exhaust stack.8,22 For partial-burn FCC units that do not have a CO2 CEMS, if a supplemental fuel such as natural gas or RFG is used in a CO boiler, then stationary combustion source methods are used to calculate the CO2 emissions resulting from the supplemental fuel. Additional monitoring may be required to avoid double counting the CO2 emissions from the FCC regenerator and a CO boiler operating with supplemental RFG when CO2 CEMS data from the final exhaust stack are used in accordance with Tier 4 methodology.

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Select 59 at www.HydrocarbonProcessing.com/RS

SPECIALREPORT

REFINING DEVELOPMENTS

Hydrogen plant. Steam reforming of

natural gas is the most common method of commercial H2 production; some plants do operate with refinery fuel gas or naphtha as the feedstock. The feedstock hydrocarbons and steam are converted to CO and H2, with additional H2 produced through water-gas shift conversion of the CO to CO2. There are two options for calculating CO2 emissions from an H2 production process in the EPA proposed rule.8,22 Either

CO2 concentration and exhaust flowrate data from CEMS or a feedstock material balance approach can be used to calculate the CO2 emissions. The feedstock material balance approach requires the quantity and carbon content of the feedstock to calculate the CO2 emissions. CO2 mitigation strategies. We will

discuss broad strategies to reduce CO2 emis-

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sions from US refineries rather than prescribe tactical solutions. This is because refineries are distinct from one another in many respects, and CO2 reduction at the individual refinery level is a highly customized and sitespecific activity. Strategies to reduce refinery CO2 emissions can be broadly grouped into three main categories: • Energy and process efficiency improvements • Substitution of fuel, feedstocks or utilities with alternatives that have lower carbon content and life cycle GHG emissions • Process modifications or substitutions to facilitate CO2 capture from exhaust gas streams that would otherwise be vented. Process fired-heaters are collectively a major source of refinery CO2 emissions, but they are individually small sources with low CO2 concentrations as a result of using air for combustion that introduces large amounts of N2 diluent in the exhaust gas. As a result, the post-combustion capture of CO2 from process fired heaters, while technically viable, is currently considered economically infeasible28,29 because of the high costs. Using energy efficient burners and fuel substitutions with lower carbon alternatives can realize some net reductions in the CO2 emissions from process fired heaters. FCC regenerators also generate exhaust gases that are dilute in CO2 due to the customary use of air for combustion,**** making post-combustion capture of the FCCgenerated CO2 economically challenging. For FCC regenerators operating in the partial-burn mode, a downstream CO boiler can improve the energy efficiency by recovering some energy from the regenerator exhaust as steam and thereby offset fuel combustion elsewhere within the refinery. While not always practically feasible, this approach can provide a marginal reduction in net refinery CO2 emissions. Hydrogen production. H 2 production in refineries is largely based on steam reforming. This process produces two distinct exhaust gas streams containing CO2. One is the raw H2 product stream that is relatively concentrated in CO2; the second is the air-combustion exhaust gas from the reformer furnace that is largely diluted with N2. Over the past decade, improvements in process efficiency have significantly reduced the CO2 intensity of H2 production, but absolute CO2 emis**** At certain refineries, the combustion air is periodically enriched with oxygen (O2) for the purpose of debottlenecking capacity.

REFINING DEVELOPMENTS sions have increased due to the remarkable growth in installed H2 capacity to meet clean fuels requirements and to process the progressively heavier and more sour crude oil feedstock to US refineries. There is, however, a significant opportunity to further reduce the H2 plant CO2 emissions by capturing it from the raw H2 product stream where it is relatively concentrated. CO2 removal is commonly accomplished using either absorption or pressure swing adsorption (PSA), the former being favored when the CO2 needs to be captured in high purity, such as for use in the beverage industry, or possibly for enhanced oil recovery. In recent decades, PSA units have increasingly replaced absorbers for H2 purification because of their superior energy efficiency. However, the PSA process typically produces a low-pressure purge gas stream of moderate CO 2 purity that is typically commingled and combusted in the reformer furnace for its fuel value and is vented to atmosphere. Thus, CO2 capture downstream of PSA units is typically uneconomical, and other options need to be considered, such as installing an absorber upstream of the PSA unit. Most US refineries are associated with significant indirect emissions of CO 2 because they import electrical power, steam and hydrogen that are largely based on fossil-fuel combustion or processing. The indirect emissions from imported power and steam are exacerbated by efficiency losses in generation, transmission and distribution, and can be greatly reduced by integrating a cogeneration plant within or adjacent to the refinery. Cogeneration, also referred to as combined heat and power, involves the combustion of a fuel in a turbine to generate power, followed by heat recovery from the exhaust gases to produce steam, which in turn can be used to generate additional power in a steam turbine. The process has an average efficiency of about 70% compared to 34%28 on average for imported power from conventional coal-fired plants. Steam produced can facilitate the retirement of old, inefficient boilers, and thereby enabling additional CO2 reductions. Cogeneration units can also be integrated with refinery H2 plants to realize additional efficiency benefits. CO2 reduction from the use of cogeneration has been estimated at about 7% of a typical refinery carbon footprint.28 Besides reducing CO2 emissions, there is a strong financial incentive to improve the energy efficiency of

petroleum refineries due to the potential savings in fuel costs. Gasification with CO 2 capture. In addition to the prevalent sources of refinery CO2 emissions discussed here, a few US refineries have large point sources of CO2 emissions such as fluid-cokers or gasifiers. If pure O2 is used for gasification, the resulting product gas will contain relatively high concentrations of CO2, making it amenable to pre-combustion capture, which has

SPECIALREPORT

relatively favorable economics compared to post-combustion capture following airbased combustion. Although not common in US refineries, these large combustion point sources offer promising opportunities for significant reductions of CO2 emissions via pre-combustion capture at the facilities where they exist. This approach can also be leveraged by adding a gasification unit to a refinery to convert heavy residuals such as petroleum-coke or asphaltenes into a syn-

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thesis gas (syngas). In turn, the syngas can be converted to H2, power and/or steam while producing a concentrated stream of CO2 that can be captured and sequestered. The resulting reduction or elimination of conventionally produced H2, steam and power will provide an additional reduction in CO2 emissions. Another approach to reduce or prevent further increases in refining GHG emissions is to increase the share of transportation fuels produced via potentially low GHG footprint routes such as biofuels, hydrogen or synthetic fuels based on the Fischer-Tropsch (FT) reaction of syngas derived from coal, natural gas or biomass. When O2 is used for syngas generation via gasification or reforming, the raw syngas product has relatively high concentrations of CO2, enabling its economical capture using absorption. A recent NETL study suggests that the co-processing of coal and biomass feedstock in a gasifier followed by FT synthesis can provide synthetic liquid transportation fuels with dramatically lower CO2 emissions compared to conventional petroleum-based fuels.30 Viewpoint. Petroleum refineries are sig-

nificant point sources of GHG emissions in the US, accounting for total emissions of 278 MtCO2e in 2002. This represented 4% of the US GHG footprint and equated to about 15% of the direct fuel combustion GHG emissions from the transportation sector. About 10% of the fuel life cycle GHG emissions for gasoline and diesel are attributable to refining. Recent developments in the US by way of proposed climate change legislation to monitor and regulate GHG emissions are motivating refiners to take a comprehensive look at the GHG emissions from their facilities and across their supply chain, and to explore strategies to manage and ultimately reduce these emissions. A refinery contains numerous direct sources of GHG emissions such as process heaters, boilers, flares, H2 plants, FCC regenerators, storage tanks, loading racks and leakage from equipment. Indirect CO2 emissions result from consumption of electricity, steam and H2 that are produced offsite. Methodologies to calculate the CO2 emissions for a particular source generally involve either measured stack CO2 concentrations and exhaust flowrates from CEMS or mass balance calculations that require source-specific process data (e.g., fuel consumption, HHV, carbon content) and emission factors. 68

I SEPTEMBER 2009 HYDROCARBON PROCESSING

Several avenues exist to reduce CO 2 emissions from refineries, ranging from energy-efficiency improvements, to switching to low-carbon fuels and feedstocks, to the capture of CO2 prior to emission. Some of these alternatives have been implemented over the years at several refineries, generally for reasons other than climate change mitigation. There are significant opportunities for further CO 2 emission reductions from refineries via capture from H 2 plantproduct gases, from large point sources such as fluid cokers or gasifiers, where present, and the construction of integrated cogeneration plants to displace imported power and steam. At refineries where heavy residuals such as petroleumcoke are abundant, integrated gasification units that capture and sequester CO2 can significantly reduce the GHG footprint by generating H2, steam and power, and thereby largely eliminate the emissions associated with the conventional production of these utilities. Reductions in refinery CO2 emissions can also be achieved at the sector level by increasing the share of transportation fuels that have lower life cycle GHG emissions. HP ACKNOWLEDGMENT Revised and updated from an earlier presentation at the Air and Waste Management Association Annual Conference and Exhibition, June 16–19, 2009, Detroit, Michigan. 1

LITERATURE CITED Gunaseelan, P., and C. Buehler, “Changing US crude imports driving refinery upgrades,” Oil & Gas Journal, Aug. 10, 2009. Regional Greenhouse Gas Initiative history and timeline, Pew Center on Climate Change, http:// www.pewclimate.org/what_s_being_done/in_ the_states/rggi/ (last accessed July 2009). Haneman, W. M., “How California Came to Pass AB 32, the Global Warming Solutions Act of 2006,” University of California, Berkeley, 2007. “Low Carbon Fuel Standard,” California Energy Commission, http://www.energy.ca.gov/low_carbon_fuel_standard/ (last accessed July 2009). Massachusetts et al. v. EPA et al. summary, Pew Center on Climate Change, http://www.pewclimate.org/epavsma.cfm (last accessed July 2009). The American Clean Energy and Security Act (H.R. 2454, Committee on Energy and Commerce, July 2009; http://energycommerce. house.gov/Press_111/20090724/hr2454_housesummary.pdf (last accessed July 2009). “Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act,” U.S. Environmental Protection Agency; http://www.epa.gov/climatechange/endangerment.html (last accessed July 2009). U.S. Environmental Protection Agency, proposed rule, “Title 40 Code of Federal Regulations Part 98—Mandatory Greenhouse Gas Reporting,” Federal Register, Vol. 74, no. 68, April 10, 2009; http://www.epa.gov/climatechange/emissions/ ghgrulemaking.html (last accessed July 2009).

Hodges, G.T., Testimony on behalf of American Trucking Association at Subcommittee on Energy and Environment hearing titled, “Allowance Allocation Policies in Climate Legislation,” June 9, 2009; http://energycommerce.house.gov/ Press_111/20090609/testimony_hodges.pdf (last accessed July 2009). 10 Cousins, S., Testimony on behalf of Lion Oil Company at Subcommittee on Energy and Environment hearing titled, “Allowance Allocation Policies in Climate Legislation,” June 9, 2009, http://energycommerce.house.gov/ Press_111/20090609/testimony_cousins.pdf (last accessed July 2009). 11 Drevna, C.T., Testimony on behalf of National Petrochemical and Refiners Association before Energy and Commerce Committee; Washington DC, April 24, 2009, http://www.npra.org/files/ pdf/EC_Climate_Testimony_4-24-09.pdf (last accessed July 2009). 12 Josten, R. B., Letter to Congress on H.R. 2454, the American Clean Energy and Security Act of 2009, U.S. Chamber of Commerce, Washington DC, June 24, 2009. http://www.uschamber.com/ issues/letters/2009/090624_cleanenergy.htm (last accessed July 2009). 13 Schipper, M., “Energy-Related Carbon Dioxide Emissions in U.S. Manufacturing,” Energy Information Administration, US Department of Energy; Washington, DC, 2006, DOE/EIA-0573 (2005). 14 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2007,” Office of Atmospheric Programs, US Environmental Protection Agency, Washington, DC, 2009, EPA 430-R-09-004. 15 Delucchi, M., “A Lifecycle Emissions Model (LEM): Lifecycle Emissions from Transportation Fuels, Motor Vehicles, Transportation Modes, Electricity Use, Heating and Cooking Fuels, and Materials,” Institute of Transportation Studies, University of California, Davis, California, 2003. 16 Wang, M. Q., “Development and Use of GREET 1.6 Fuel-Cycle Model for Transportation Fuels and Vehicle Technologies,” Center for Transportation Research, Energy Systems Division, Argonne National Laboratory; Argonne, Illinois,, 2001. 17 Chester, M. V.,” Life-cycle Environmental Inventory of Passenger Transportation in the United States,” Dissertation; Institute of Transportation Studies, University of California; Berkeley, 2008. UCB-ITS-DS-2008-1. 18 “Development of Baseline Data and Analysis of Life Cycle Greenhouse Gas Emissions of Petroleum-Based Fuels,” Office of Systems, Analyses, and Planning, National Energy Technology Laboratory, 2009; DOE/NETL2009/1346. 19 “Greenhouse Gas Emissions from the U.S. Transportation Sector 1990–2003,” Office of Transportation and Air Quality, US Environmental Protection Agency; Washington, DC, 2006; EPA 420 R 06 003. 20 Ritter, K., M. Lev-On and T. Shires, “Development of a Consistent Methodology for Estimating Greenhouse Gas Emissions from Oil and Gas Industry Operations,” In “Emission Inventories— Partnering for the Future,” Proceedings of 11th International Emission Inventory Conference: Atlanta, Georgia, April 15–18, 2002. 21 Shires, T. M. and C. J. Loughran, “Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry,” American Petroleum Institute, 2004. 22 “Technical Support Document for the Petroleum Refining Sector: Proposed Rule for Mandatory Reporting of Greenhouse Gases,” US

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Environmental Protection Agency, Sept. 8, 2008. Intergovernmental Panel on Climate Change; “2006 IPCC Guidelines for National Greenhouse Gas Inventories,” Prepared by National Greenhouse Gas Inventories Programme; Eggleston H. S., Buendia L., Miwa K., Ngara T. and Tanabe K. (eds.); Institute for Global Environmental Strategies; Japan; 2006. http://www.ipcc-nggip. iges.or.jp/public/2006gl/index.html (last accessed July 2009). 24 “Technical Guidance Manual on Reporting Greenhouse Gas Emissions,” Environment Canada, 2006. http://www.ghgreporting.gc.ca/ ghg-ges/page15.aspx (last accessed July 2009). 25 “Technical Guidelines: Voluntary Reporting of Greenhouse Gases” (1605(B)) Program, US Department of Energy, 2007. 26 “Instructional Guidance for Mandatory GHG Emissions Reporting,” Chapter 10: Petroleum Refineries; California Air Resources Board, California, December 2008. http://www.arb. ca.gov/cc/reporting/ghg-rep/ghg-rep-guid/10_ PetroRefine.pdf (last accessed July 2009). 27 “GHG Emissions Reporting Using the California ARB On-Line Reporting Tool: Petroleum Refineries, Hydrogen Production Facilities, Oil and Gas Production Facilities,” California Air Resources Board, California, March 30, 2009. http://www.arb.ca.gov/cc/reporting/ghg-rep/ghgtool.htm (last accessed July 2009). 28 Phillips, G., “CO Management in Refineries,” 2 Gasification V conference, Noordwijk, The Netherlands, 2002. 29 Thernez, A. et al., “CO capture—New challenge 2 in refinery industry,” MOL Scientific Magazine, 23

MOL Group, Hungary, 2008. Gray, D. et al., “Increasing Security and Reducing Carbon Emissions of the U.S. Transportation Sector: A Transformational Role for Coal with Biomass,” National Energy Technology Laboratory report, 2007, DOE/NETL-2007/1298.

Praveen Gunaseelan is a manager in Exponent’s engineering management consulting practice, and advises clients on the technoeconomic feasibility and greenhouse gas aspects of projects, technologies and products in the oil & gas, refining, chemicals and clean energy sectors. Prior to joining Exponent, he was an energy market analyst in the tonnage gases division at Air Products & Chemicals specializing in the refinery hydrogen market. Dr. Gunaseelan holds a PhD in chemical engineering from Purdue University and a BS degree in chemical engineering from the University of Bombay. He is a member of the Society of Petroleum Engineers and the Gas Processors Association, and has spoken and served as a committee member at meetings of the National Petrochemical & Refiners Association.

Christopher Buehler is a senior managing engineer in Exponent’s thermal sciences practice. For over 18 years, he has investigated numerous fires, explosions, process upsets and

atmospheric releases at petroleum refineries, natural gas and chemical process facilities. He holds a BS degree in chemical engineering from Villanova University, and an MS degree and PhD in chemical engineering from Purdue University. He is a registered chemical engineer in Texas. Dr. Buehler is a member of the American Institute of Chemical Engineers, American Chemical Society and National Fire Protection Association. The production and use of hydrogen, biogas, and other alternative sources of energy are of particular interest, and he has spoken at several conferences on the use of gasification systems to produce hydrogen and synthetic fuels.

Wanyu Rengie Chan is a senior scientist in Exponent’s environmental and earth sciences practice. She advises clients on indoor and outdoor air quality, and greenhouse gas emissions. She has performed onsite sampling and computer modeling to evaluate potential human health and environmental impacts from airborne pollutants. Prior to Exponent, she conducted research at Lawrence Berkeley National Laboratory to develop a model that predicts indoor concentrations in homes and commercial buildings in the event of an outdoor chemical release. Her work has been applied by the National Atmospheric Release Advisory Center to advise emergency responders. She holds a PhD in environmental engineering from the University of California at Berkeley.

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REFINING DEVELOPMENTS

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Increase the flexibility of your Claus unit Novel approach incorporates liquid redox methods to manage refinery sulfur loading G. J. NAGL, Gas Technology Products Division, Merichem Chemical & Refinery Services LLC, Schaumburg, Illinois

nhanced features such as sophisticated ratio control, oxygen (O2) enrichment, improved burner design, etc., facilitate more operating flexibility of Claus units to rapidly adjust to changing feed conditions. Varying feedrates are normal operating conditions in petroleum refineries and natural gas processing facilities. However, even with these mentioned advancements, some process applications still challenge the capability of adjusting Claus units to large turndown ratios while maintaining high sulfur removal and onstream efficiencies. New processing methods incorporate a liquid redox process with a Claus unit. Such combinations can achieve turndown ratios of 100%, removal efficiencies of 99.9+% and onstream efficiencies approaching 100%. In some cases, the typical Claus incinerator can be eliminated, which will greatly reduce carbon dioxide (CO2) and sulfur dioxide (SO2) emissions and energy requirements to operate the incinerator. All of this can be accomplished without having to recycle gas back to the Claus unit. More effective sulfur recovery. Liquid reduction-oxidation (redox) processes use aqueous-based solutions containing metal ions, usually iron. These solutions are capable of transferring electrons in redox reactions. In the liquid redox process, a non-toxic, chelated iron catalyst accelerates the reaction between hydrogen sulfide (H2S) and oxygen to form elemental sulfur (S):

H S + O2 S°+ H 2 O (1) Fe 2 As implied by its generic name (liquid redox), all of the reactions occur in the liquid phase in spite of the fact that Eq. 1 is a vapor-phase reaction. In this process, sour gas is contacted in an absorber with the aqueous, chelated iron solution. In the absorber, H2S is absorbed into the solution and ionizes into sulfide and hydrogen ions: H 2 S + H 2O 2H+ + S=

(2)

The ionization reaction (Eq. 2) is very fast, while the mass transfer is relatively slow. The dissolved sulfide ions react with chelated, ferric ions to form elemental S:

S= + 2Fe+++ S° + 2Fe ++

(3)

This reaction (Eq. 3) is very fast and is not equilibrium limited. In addition, since the reactions are occurring at ambient temperatures, the sulfur is formed as a solid. The solution is then

Flue gas

Acid gas

Washwater

Centerwell Vacuum-belt ﬁlter

Air

Sulfur slurry Autocirculation vessel

FIG. 1

Filtrate tank

Sulfur cake

Filtrate pump

Process diagram of a typical autocirculation liquid redox unit.

contacted with air in an oxidizer where oxygen is absorbed into the solution, and the ferrous ions are converted back to the active ferric state: O2 + H 2O + 2Fe++ 2Fe+++ + 2OH –

(4)

Again, the oxidation of the ferrous ions is very fast, and the mass transfer of the oxygen into the solution is slow. Adding Eqs. 2, 3 and 4 yields Eq. 1. Liquid redox processing schemes. Depending on the gas being treated, different processing streams are available to optimize the liquid-redox operation. As illustrated in Fig. 1, autocirculation-type liquid redox units are used when treating acid-gas streams. These streams can be mixed with air without creating a safety problem or contaminating the product gas. In this unit design, the absorber, where Eqs. 1 through 3 occur, and the oxidizer, where Eq. 4 occurs, are contained in one vessel separated by baffles. Due to the large differences in aerated densities between the liquids in the absorber and oxidizer sections, large circulation rates are achieved between the various vessel compartments without using pumps. The acid gas enters the absorber section of the vessel (centerwell). It is contacted with oxidized liquid redox solution in which the H2S is absorbed and converted to elemental S. The partially HYDROCARBON PROCESSING SEPTEMBER 2009

I 71

SPECIALREPORT

REFINING DEVELOPMENTS

reduced solution circulates to the oxidizer section where it is contacted with air. Now the iron is reoxidized according to Eq. 4. Exhaust air from the oxidizer and the sweeten acid gas from the absorber are combined and are generally exhausted to the atmosphere. In the conical portion of the vessel, the sulfur settles into a slurry of approximately 10 wt% to15 wt% solids. A small stream is withdrawn from the cone and sent to a vacuum-belt filter where the sulfur is further concentrated to an approximately 65 wt% S cake. Some units stop at this stage and sell the sulfur cake as a fertilizer. Drier sulfur cake can be formed by installing pressure filters. If molten sulfur is required, the cake is reslurried and melted. Removal efficiencies of greater than 99.99% and turndowns of 100% can easily be achieved with an autocirculation unit.

genation/hydrolysis reactor, which will convert all of the sulfur vapor, SO2, carbon disulfide (CS2) and carbonyl sulfide (COS) to H2S followed by a cooler and a liquid redox unit. Both methods will result in removal efficiencies exceeding 99.9%. The only difference between these methods will be in operating costs. The first approach has a higher operating cost than the second method. When considering a liquid redox unit to treat Claus tail gas without the hydrogenation/hydrolysis reactor, the amount of SO2 in the tail gas is an important operating parameter. Since liquid redox units operate at alkaline pH, in the range of 8 to 9, any SO2 in the tail gas will be easily absorbed, and will form sulfates and sulfites as shown in Eqs. 5 and 6:

SO2 + 2NaOH + O2 Na 2 SO4 + H2 O

(5)

NaOH + SO2 NaHSO3 (6) approaches to coupling a liquid redox process with a Claus unit. More important, SO2 does not interfere with the liquid redox The first method involves processing the Claus tail gas through chemistry, and, consequently, does not affect the H2S removal effia cooler and then directly into a liquid redox unit. The second ciency of the process. However, Eqs. 5 and 6 do affect the operatmethod involves processing the Claus tail gas through a hydroing costs of the process in two ways. First, caustic is consumed for each mole of SO2 absorbed, which increases the unit operating cost. Secondly, the resultant sulfate/sulfite product will accumulate Flue gas Washwater in the liquid redox solution. Eventually, a continuous blowdown will be required and Chemical addition will result in a loss of catalyst solution that Vacuum-belt Mobile bed must be replaced—again, increasing operatﬁlter absorber Cooling Quench ing costs even further. Consequently, if this water tower process configuration is to be applied, it is advantageous to minimize SO2 formation Sulfur Filtrate cake in the Claus unit by operating the Claus Claus SWS tank Sulfur tail gas gas unit with sub-stoichiometric quantities of Venturi slurry oxygen, thus increasing the H2S:SO2 ratio absorber Oxidizer Filtrate Solution vessel in the tail gas. pump circulation Fig. 2 is a flow diagram of a typical liquid pumps Air redox unit treating Claus tail gas directly. Air blower MU H2O To Since the liquid redox system is aqueousSWS to oxidizer based, elevated temperatures will cause water-balance problems. Consequently, FIG. 2 Flow diagram of a liquid redox process to treat Claus tail gas directly. the tail gas is first passed through a quench tower where the gas temperature is reduced from approximately 135°C to 50°C. A portion of the sour condensate produced in the Flue gas Flue gas Washwater cooling operation can be used as makeup Air water in the liquid redox unit. However, Quench Chemical Burner some produced condensate must be sent to tower addition Claus tail gas Mobile bed a sour-water stripper, and the vapor routed Vacuum-belt absorber Cooling back to the liquid redox unit. ﬁlter water For direct treatment of Claus tail gas, the liquid redox process would use venturi SWS Sulfur absorber followed by a mobile bed absorber gas Filtrate cake (MBA). The venturi not only supplies the tank Sulfur much needed draft to the system, but it also Hydrogenation/ Venturi slurry hydrolysis provides a sizable level of H2S removal. The absorber Oxidizer reactor Filtrate MBA applies hollow, ping-pong-like spheres vessel pump Solution as the contacting media which, when fluidcirculation Air ized, are self-cleaning. pumps Air blower To MU H2O This mode of operation (Fig. 2) will still SWS to oxidizer yield overall H2S removal efficiencies of FIG. 3 Flow diagram applying an indirect approach in which all sulfur compounds from the 99.99+%. In addition, effluent gases from Claus tail gas are first converted into H2S. the liquid redox unit will probably not

Coupling liquid redox with a Claus unit. There are two

I SEPTEMBER 2009 HYDROCARBON PROCESSING

Energy conservation and optimization are key issues for process plant profitability. Proper evaluation and correction of energy losses can help bring significant cost savings and emission reductions. Our complete optimization program can assist in numerous ways: ■

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REFINING DEVELOPMENTS Acid gas

Claus unit

Flue gas

Washwater

Chemical addition

Quench tower

Cooling water

Vacuum-belt ďŹ lter

Mobile bed absorber

SWS gas Venturi absorber

Sulfur Filtrate cake tank

Sulfur slurry Oxidizer Solution vessel circulation pumps Air

a hydrogenation/hydrolysis, catalytic reactor at elevated temperatures. Eqs. 7 and 8 (hydrogenation) and Eqs. 9 and 10 (hydrolysis) represent the major process reactions that occur in the reactor:

SO2 + 3H 2 H 2 S + 2H2 O

(7)

S2 + 2H 2 2H 2 S

(8)

CS2 + 2H 2O CO2 + 2H 2 S

(9)

COS + H 2 O CO2 + H2 S

(10)

As shown in Fig. 3, fuel gas is subjected to partial oxidation, which not only generates sufficient heat to raise the tail gas to reaction temperatures but also generates Air blower MU H2O To hydrogen to satisfy the reaction requireSWS to oxidizer ments of Eqs. 7 and 8. After passing through the reactor, the FIG. 4 Flow diagram of direct treatment of Claus unit tail gas that includes a liquid redox effluent gas must be cooled to 50Â°C, which process. will generate sour condensate. Again, a portion of the sour condensate may be used as makeup water for the require incineration since the tail gas will contain only a very liquid redox unit. However, some of the produced sour condensmall amount of H2S and no SO2. The effluent tail gas will be diluted with the effluent air from the oxidizer. Equally imporsate must be sent to a sour-water stripper with the vapor being tant, there is no recycle stream sent back to the Claus unit. Thus, routed back to the liquid redox unit. The operating scheme of the capacity of the Claus unit will not be reduced by adding a the liquid redox unit will be identical to those described for the liquid redox system to treat the tail gas. indirect treat treating case. In the indirect processing scheme, all sulfur compounds in a Claus tail gas are converted to H2S by passing the tail gas through Achieving 100% turndown. Operating a Claus unit in a turndown mode will generally result in operational problems as the amount of turndown increases. By installing a liquid redox unit in parallel with a Claus unit, these operating problems can be eliminated by base loading the Claus unit at a condition that results in acceptable Claus operation. Any variation below the base load will be diverted to the liquid redox unit, and the Claus unit will be put into standby mode. If the liquid redox unit is also used as the tail gas unit, the operation will be as illustrated in Fig. 4 for direct treatment by the tail-gas unit. To accommodate this operating scheme, the operating capacity of the autocirculation vessel should be equivalent to that of the turndown capacity of the Claus unit. November 11-13, 2009 All of these flow schemes will yield overall H2S removal effi6DFUDPHQWR &RQYHQWLRQ &HQWHU Â&#x2021; 6DFUDPHQWR &$ ciencies of 99.99+% and turndowns of 100%. In addition, the effluent gases from the liquid redox unit will not contain any SO2 and only a very small amount of H2S. Consequently, incineration Learn Network Explore may not be required, which will save energy and will not increase greenhouse gas emissions. It is also important to note that there s Public Policies is no recycle stream back to the Claus unit. Thus, the capacity of the Claus unit will not be reduced by adding a liquid redox system s Business Strategies to treat tail gas. HP

s s s

Technologies

Economics Project Development

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Filtrate pump

Gary J. Nagl is vice president and general manager of Gas Technology Products Division of Merichem Chemical & Refinery Services LLC. He is a member of AIChE, the Gas Processors Association, the National Petrochemical and Refiners Association, and The Geothermal Research Council. Mr. Nagl has been involved in the development and design of sulfur-recovery systems for a myriad of applications for the past 25 years. He has published numerous articles on the subject and holds 10 US patents. Mr. Nagl earned a BS decree in chemical engineering from the University of Illinois.

REFINING DEVELOPMENTS

SPECIALREPORT

‘Green up’ air and water pollutant control Recycling spent activated carbon can offer economic benefits and environmental credits K. R. TARBERT, Siemens Water Technologies, Houston, Texas

etroleum refineries are faced with a number of purification needs, driven by increasingly stringent regulatory requirements as well as improving product quality. One traditional technology, activated carbon, remains a cost-effective method for refineries to comply with federal, state and local regulations, and handle product purification needs. Activated carbon is successfully used in many “clean up” applications in a typical refinery. Recent cost increases for virgin activated carbons, however, have created a renewed interest for “green” solutions for many carbon applications, such as substituting virgin activated carbons with reactivated carbons. Reactivated carbon is spent carbon that is recycled by being regenerated at very high temperatures. In refineries, reactivated carbons can be used for volatile organic compounds (VOCs) abatement in vapor-phase applications, wastewater treatment and groundwater remediation.

• Stage 2 (furnace temperature of 400°F–1,200°F)—Pyrolysis of higher boiling point organics occurs on the carbon surface. • Stage 3 (furnace temperature of 1,350°F–1,800°F)—Gasification of the pyrolysis residues occurs. Reactivation gases containing volatilized organics and residues, exit the furnace, where they pass through an afterburner to mineralize any remaining organic compounds. Inorganic gases are removed via a wet scrubber. Two furnace types are used to thermally reactivate carbon: multiple hearth furnaces and rotary kilns. Each has distinct advantages and disadvantages: Multiple hearth furnace (MHF): • High degree of control over reactivation process, especially the furnace atmosphere for steam ratio as well as gas use

Green benefits. The most important benefit of using reac-

tivated carbon is cost savings. Recycling carbon reduces operating costs since the expense for reactivated carbon is typically 20%–40% less than the cost of virgin carbon. In addition, some facilities also receive environmental credits issued by regulatory agencies for waste minimization. The reactivation process ends the chain of custody for adsorbed contaminants, thereby eliminating liabilities associated with handling and disposal of spent carbons. Reactivated carbon is considered a recovered resource. Reactivation process. Thermal reactivation uses steam

and high temperatures to remove and to destroy the organic compounds that have been adsorbed onto the carbon. Fig. 1 shows a typical reactivation unit. The reactivation process has three goals: • Restore the spent carbon’s activity level to as near as original as possible • Maintain the internal pore structure of the media • Minimize product losses due to gasification and attrition. During reactivation, residence time in the furnace, reactivation temperature and gas composition must be carefully controlled to obtain the desired reactivated carbon quality. The reactivation process typically has three stages: • Stage 1 (furnace temperatures of 200°F–500°F)—The carbon is dried, and more volatile/low-boiling point organics are volatilized off the spent carbon.

FIG. 1

Multiple heart furnace plant in Parker, Arizona.

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APPLICATIONS TO USE ACTIVATED CARBON IN REFINERIES

Activated carbon is a versatile adsorbent material that has several common applications within a typical petroleum refinery. Regulatory compliance and improvement in product quality are the two main drivers for using activated carbon. Common applications include: • Vapor-phase VOC treatment and control. Compliance with the Benzene NESHAP or local air emission regulations drives the need for VOC control at sewer sumps, covered API separators and DAF units, storage tanks, and other sources. Adsorbers using either virgin (pelletized coal-based or granular coconut shell-based) or reactivated carbons can be applied. • Vapor/solvent recovery. Economically valuable products at refineries and terminals can be recovered via pressure swing or temperature swing systems that use activated carbon. Carbon type is driven by the boiling point of the solvent; volatile solvents often require microporous carbons (e.g., coconut shell-based), while higher boiling point solvents require macroporous (coal-based) carbons. Carbons with high working capacities (allowing for effective adsorption/desorption cycles) are desired. • Hydrogen sulfide removal. Sour crude oils are often the source of hydrogen sulfide (H2S) emissions. Specialty grades of carbon (impregnated or catalytic grades) can remove H2S. • Wastewater treatment. Activated carbon can help refineries meet wastewater discharge permits (COD, BOD, TOC and • Reduces losses due to gasification • Less physical attrition losses • More energy efficient on energy consumption per unit of product • Offers better carbon/gas contact. Rotary kiln: • Provides flexible operation • Creates clean breaks between product runs • Operation and maintenance require less operator skill than MHFs • Lower labor and equipment maintenance costs than MHFs. The decision about which furnace type to use is determined by such factors as fuel sources, requirements for operating flexibility, local technology sources and emission constraints. Evaluating reactivated carbon performance. The performance of reactivated carbon can be measured by several methods including Iodine and Butane Numbers. These ASTM and AWWA standard adsorption capacity tests are used as an initial basis for comparing reactivated carbon with virgin carbon. While these tests are sufficient for most applications, some applications require comparing the removal efficiency of targeted compounds. For these applications, bottle point isotherms or the Rapid Small Scale Column Test (RSSCT) should be used, which compares the adsorption performance of reactivated vs. virgin carbons with a sample of the influent water stream. Reactivation services. A number of vendors provide reactivation services. Different programs are available to suit the users’ application. These include: React and return is a highly controlled program in which activated carbons are removed, reactivated and returned for reuse to the same client. It is most commonly applied to potable water 76

I SEPTEMBER 2009 HYDROCARBON PROCESSING

biotoxicity). Reactivated carbons are most commonly used in this application that often requires upfront testing or piloting to properly size the system. • Groundwater remediation. Organic compounds (BTEX, MTBE) often migrate into groundwater supplies from leaking underground storage tanks or holding ponds. Reactivated or virgin coal-based carbons are often used to remediate BTEX, while coconut shell-based carbons (with higher adsorptive capacity for trace removal) are often selected for MTBE removal. • Boiler feedwater treatment. Organic impurities in boiler feedwater can cause scaling, corrosion, foaming or other problems. A low-silica coconut shell-based carbon (to prevent silica leaching into the feedwater stream) can successfully adsorb organic contaminants. • Amine purification. Various alkanolamines are used in refineries to purify gas streams. The amine solution picks up hydrocarbons and organic acids. A slipstream of the amine solution is passed through a carbon adsorption system to prevent a buildup of these hydrocarbons. Virgin coal-based carbons are the best fit for this application. • Decolorization. Activated carbon can be used for color, odor or contaminant removal from desired end products such as jet fuel, kerosine, gasoline and lube oil. Powdered carbons can be used in batch treatment processes, or granular carbons can be applied in continuous processes. applications. The carbon is segregated from other spent carbons during reactivation and storage. Virgin carbon is used to offset normal losses that occur during handling and reactivation to ensure 100% of the original carbon is returned to the customer. Pool reactivation is a program whereby spent carbons are segregated and then pooled according to application type (vapor phase/liquid phase) and mesh size. These pooled carbons can then be sold into many applications as a substitute for virgin carbon to lower the operating costs. Field services associated with reactivation programs include spent carbon profiling, spent carbon removal and packaging, nonhazardous and/or hazardous waste handling and transportation to the reactivation plant or hazardous waste reactivation plant, carbon vessel inspection with minor repair and vessel reloading with reactivated carbon. Vendors performing reactivation services can offer a certificate of reactivation for each shipment, confirming that the spent carbon has been recycled in a manner that meets or exceeds all applicable Resource Conservation and Recovery Act (RCRA) and Benzene National Emissions Standards for Hazardous Air Pollutants (NESHAP) regulations. Prior to reactivation, spent carbon must be profiled and tested to ensure that it can be safely and efficiently reactivated within the permit limits of the reactivation facility. Typically, a profile form on the spent carbon is completed and a small sample of the spent carbon is provided for testing. Some contaminants, such as polychlorinated biphenyls (PCBs), may not be accepted at certain vendors’ plants. Determination of the spent carbon’s regulatory status (RCRA hazardous, state hazardous, nonhazardous or falling under the sludge exemption) is the responsibility of the generator of the spent carbon. Green advantage. Besides recycling spent carbon and elimi-

nating waste to the environment, reactivation can offer other environmental advantages. A refinery that reactivates its spent carbon

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may be eligible for environmental credits from regulatory agencies for waste minimization. One example is the sludge exemption, which allows spent carbon to be handled as a nonhazardous waste, and is exempt from the regulations for hazardous waste as described in 40 CFR 262. The sludge exemption only applies to spent carbon that is not exposed to any wastes specifically listed in 40 CFR 262, and is only used when the generator of the spent carbon intends to send it to a facility where the material will be reactivated for reuse. As defined in 40 CFR 260:10, “sludge means any solid, semi-solid or liquid waste generated from a municipal commercial or industrial wastewater treatment plant, water-supply treatment plant or air pollution control facility exclusive of the treated effluent from a wastewater treatment plant.” The US Environmental Protection Agency (EPA) further provides that a spent carbon may be classified as a sludge when it contains no listed hazardous waste and is returned to a reactivation facility where the spent carbon is reclaimed. Since the spent carbon in these applications meets the definition of a sludge, it is not considered a solid waste and therefore, is not considered a hazardous waste. The sludge exemption must be accepted by the governing state environmental regulations in both the generator’s home state and the state in which the reactivation facility resides. To claim the exemption, the refinery must contact its state environmental regulatory agency to obtain its approval. Spent carbon profiled as RCRA sludge exempt can be transported either as a DOT-regulated hazardous material or as a non-DOT-regulated material. The choice is determined by the quantity, in one container, of the hazardous substance on the

spent carbon. If that quantity equals or exceeds the reportable quantity (RQ) for the hazardous substance, the spent carbon is a DOT-regulated Class 9 hazardous material. If that quantity is less than the hazardous substance’s RQ, the spent carbon is not DOT regulated. Case Study: US West Coast refinery. A refinery in Wash-

ington state is using reactivated carbon to meet environmental compliance for VOC emissions. The refinery was using virgin carbon in many carbon adsorbers for VOC emissions at its sewer vents and effluent plant to meet the requirements of a consent decree associated with the Benzene NESHAP rule. This rule requires a 95% reduction of VOCs (or 98% benzene reduction) from vapor emissions at various points throughout the refinery. The refinery was also using significant manpower from its personnel and an onsite contractor to service these carbon filters. In addition, the refinery was shipping approximately 200,000 lbs annually of hazardous spent carbon to a disposal facility for landfill or incineration. This refinery wanted to reduce costs, manpower requirements, hazardous waste and safety risk/liability while ensuring continued compliance with the consent decree requirements. Solution. After contacting a water-treatment systems/services vendor, the refinery chose a turnkey solution that would standardize their activated carbon equipment, significantly reduce their cost, lower manpower requirements, reduce overall safety risks/liability and eliminate onsite hazardous waste. The solution consists of two types of standardized carbon adsorbers to replace

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more cost-effective and environmentally beneficial solution for refineries to consider. HP BIBLIOGRAPHY Furstenberg, J. L., “ Risk Evaluation of Covered API and DGF Tanks Treating Refinery Wastewater,” American Petroleum Institute, Autumn Refining Meeting. Oct. 8, 1991. Schultz, T. E., “Get the most out of API separators,” Chemical Engineering, July 2005, pp. 38–42.

NOMENCLATURE API American Petroleum Institute BOD Biological oxygen demand EPA Environmental Protection Agency BTEX Benzene, toluene, ethylbenzene and xylene COD Chemical oxygen demand DAF Dissolved air flotation DOT Department of Transportation MTBE Methyl tertiary butyl ether NESHAP National Emission Standards for Hazardous Air Pollutants PCB Polychlorinated biphenyls RCRA Resource Conservation and Recovery Act RQ Reportable quantity TOC Total organic compound VOC Volatile organic compound Karen R. Tarbert, P.E., is a manager of applications engineering, Environmental Services–Carbon, at Siemens Water Technologies in Houston, Texas. Ms. Tarbet holds a BS degree in chemical engineering from Arizona State University. She has 25 years of working experience in the area of activated carbon applications. Ms. Tarbert has been working in the Houston area for 10 years with Siemens and has been the branch manager in Siemen’s Houston Water Technologies Group.

FIG. 2

Activated carbon remains a cost-effective treatment technology for air, water and process purification.

the various adsorber types in use and a service contract that provides offsite carbon change-out for new adsorbers. The adsorbers are staged in a separate area and shipped to the vendor’s facility in another part of Washington, where the carbon is replaced; the fresh filters are then shipped back to the refinery. The vendor provides reactivation services for the spent carbon, and provides fresh reactivated carbon for refilling the vessels. Results. The new system/service combination will allow more efficient exchange of adsorber vessels under the consent decree timeline constraints (8 hours or 24 hours) and will reduce manpower requirements at the refinery. Since the spent carbon is being reactivated, it is considered an exempt waste, not a hazardous waste. Accordingly, the refinery will completely eliminate the transport and disposal of hazardous waste from its processes, and will meet environmental compliance for handling of spent carbon, as the carbon will be reactivated in lieu of landfilling or incineration. The refinery will also reduce safety liability for its workers. Because of all these factors, the refinery has projected an annual cost savings of approximately $300,000 to $500,000. Greener options. Achieving regulatory compliance while

operating profitably and producing quality products via the refining process can be challenging. Fortunately, for the removal of organic contaminants, activated carbon remains a tested, reliable technology to help achieve regulatory compliance and product purification goals. Using reactivated carbon provides an even Select 169 at www.HydrocarbonProcessing.com/RS 79

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Consider advanced modeling to control air emissions Computational fluid dynamics methods improve designs for NOx reduction applications D. DAKSHINAMOORTHY, Technip USA, Houston, Texas, and A. GUPTA, KTI Corp., Houston, Texas

itrogen oxide (NOx) emissions are considered one of the six common air pollutants by the Environmental Protection Agency (EPA).1 A major NOx source is the burning of fossil fuels by fired heaters and furnaces. The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for controlling NOx emissions. To meet these standards, the hydrocarbon processing industry is adopting various technologies to reduce NOx emissions. The technology selected usually depends on the NOx emission requirement. Selective catalytic reduction (SCR) is a post-combustion NOx reduction technology. This technology requires an effective duct design to optimize flue gas and ammonia (NH3) flow patterns through the SCR unit. The proposed duct design should be analyzed before fabrication to ensure performance. This is possible only by flow modeling studies. Computational fluid dynamics (CFD) is a flow modeling tool that is widely used in analyzing and enhancing the duct design for industrial flow problems. The presented examples show how CFD methods can be used to optimize the duct design for two NOx reduction projects that apply SCR technology. The CFD model led to design changes that proved to be critical in achieving the required flow patterns through the SCR unit. These examples highlight the power of CFD to provide visual presentations. Using these models, design teams could more effectively analyze the root cause for problems and quickly devise corrective actions. Background. The two projects under study involve reducing NOx emissions from the flue gas of a new crude furnace and a new vacuum furnace being installed at an existing refinery. SCR technology was selected to meet the EPA NOx standards set for the projects. The facilities installed as part of the NOx reduction projects are the following: • Flue gas train from the furnace convection section outlet to the outlet of the SCR unit • Ammonia injection grid and ammonia injection skid • SCR unit • Air preheater (APH) • ID fan • The stack. Method. Using in-house CFD expertise, the design team examined the duct design for both projects. The first step in the inves-

tigation is to agree upon the desired criteria against, which the design is tested and judged using CFD modeling. Threshold limits are selected for each criterion defining the point of minimum acceptable performance. The agreed upon design criteria and threshold limits for both projects are: • Flue-gas velocity maldistribution across the SCR catalyst surface is within ± 15% RMS • Ammonia–NOx maldistribution across the SCR catalyst surface is within ±5% RMS. The next step is to model the preliminary physical layout for the design conditions using CFD. Results from the CFD model are presented as a study report that elaborates on the flow characteristics of the designs. This study also highlights concerns or short-comings in the preliminary design, and recommends modifications. The design team can analyze the problems and proposed solutions for feasibility. The feasible solutions are tested in the CFD model before approving the design for fabrication. Having in-house CFD experts who are knowledgeable in the setup and workings of the CFD tools enables a close working relationship with the design engineers who are knowledgeable in the total system and constraints associated with the implementation. This working arrangement allows the CFD experts to gain an understanding of the overall project requirements and to have a close contact and dialog with the design team. The design engineer, in turn, gains valuable insight on the workings of the CFD model and is able to guide the modeling effort to a cost-effective solution in a timely manner. This interaction allows inclusion of successive incremental improvements into the CFD models until acceptable solutions are obtained. These solutions are presented to the design team for approval and fabrication. SCR technology. It is a post-combustion NOx reduction process in which NH3 reacts with NOx in the presence of a solid catalyst to form nitrogen (N2) and water. The effectiveness of this reduction technology depends on various design parameters. Proper mixing of NH3 with NOx in the flue gas is a parameter of special interest. The mixing is usually challenging, since the amount of injected NH3 is very small compared to the flue-gas volume. A common NH3 injection method is an installed injection grid in the flue-gas duct work upstream of the SCR unit. This installation is commonly referred to as the ammonia injection grid (AIG). Designs for AIGs vary widely and are dependent on many HYDROCARBON PROCESSING SEPTEMBER 2009

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factors. The effectiveness of AIG design in achieving a uniform NH3 distribution within the flue-gas stream should be tested by flow modeling. Another critical design parameter is proper distribution of flue gas and NH3 at the catalyst surface. The flue gas ducting details, which vary from one project to another, have a major impact on this parameter. To ensure proper distribution of flue gas and NH3 at the catalyst surface, engineers should investigate the flue-gas flow pattern at the SCR catalyst surface. These parameters again should be improved by flow modeling.

TABLE 1. Process conditions for vacuum unit (Case A) Description

Vacuum

Crude

170,000

330,000

730

690

Flue-gas properties Flue-gas flowrate in wet basis, lbs/hr Flue-gas inlet temperature, °F

Flue-gas composition, vol%, wet Oxygen (O2), %

2.47

Nitrogen (N2), %

71.16

Water (H2O), %

16.52

CFD modeling. CFD is now widely used in industrial flow

Carbon dioxide (CO2), %

8.98

applications as a flow-modeling tool. Using CFD tools in SCR applications has been discussed in technical articles.2–4 Details of the models and results expected from the CFD model are not clearly depicted. It is essential that the design engineer understands the details of the CFD model and CFD results to fully utilize the extent of modeling capabilities. CFD involves solving equations for mass, momentum and energy in a solution domain, which comprises the geometry of interest. In NOx reduction projects, the geometry of interest involves a flue-gas train—from the furnace convection section outlet to the outlet of the SCR. It includes the flue-gas duct, AIG, SCR unit and the SCR catalyst bed.

Argon, %

0.85

Geometry and grid. The first step in building a CFD model

Molecular weight of flue gas, wet, lb/lbmole

is creating the physical geometry to be studied as a mathematical representation called solution domain. The solution domain is decomposed into finite volumes called meshes or grids. Commercial grid-generation tools can be used to generate the solution domain and grids. Fig. 1 shows the geometries considered in the NOx reduction projects. Fig. 1a shows the SCR system for the vacuum furnace and Fig. 1b shows the SCR system for the crude furnace. Figs. 1a and 1b also show the location of the AIG and SCR unit, and location of the catalyst beds within the SCR unit. The geometry for the crude furnace included an additional element in the flow path, the trolley beams, which are used during catalyst replacement. The path of the flue gas is marked by the red dashed arrows in the figures. A close-up view of the AIG, for both projects, is shown in Fig. 2. This figure illustrates that an AIG consists of series of lances (or pipes), which are arrayed with injection nozzles. The AIG

Aqueous NH3 consumption, lbs/hr

Total flowrate through AIG, lbs/hr

724

1,374

AIG AIG

Flue gas from convection outlet

SCR unit

Catalyst

(a) SCR for vacuum unit FIG. 1

Corrected inlet NOx at 3 % O2, ppmvd Inlet NO/NO2, volume basis, %

90/10

Aqueous ammonia properties Dilution air flowrate, lbs/hr Ammonia/NOx ratio: NH3/NO and NH3/NO2 Ammonia concentration in water, wt%

690

1,350

1 and 1.3

4.5

Catalyst bed Pressure drop across the catalyst bed, in. WC Calculated quantities

is installed inside the flue-gas duct and disperses NH3 into the flowing flue-gas stream. As shown in Fig. 2, the number of lances and nozzles, diameter of lances and nozzles, angle of injection (see red arrows in Fig. 2) and location of the AIG in the flue-gas duct vary between the two projects. During CFD grid generation, efforts are made to have finer grids near the AIGs to capture the NH3 injection. Around 2 million finite volume grids are used to model each project. Configuration details and process conditions. The CFD model is solved using a commercial CFD program. The flue-gas flow is fully turbulent and a Realizable K-␧ model with standard wall functions is applied in modeling this flow. The CFD model also accounts for the heat transfer between the flue gas and AIG pipes. The flue gas heats the NH3 and dilution medium before injection. To capture this phenomenon, an additional equation for energy conservation is solved. Since the flow involves the

Flue gas from convection outlet

Catalyst

SCR unit

Catalyst trolley beam

(b) SCR for crude unit

A CFD model illustrating the geometry of SCR system NOx reduction projects.

I SEPTEMBER 2009 HYDROCARBON PROCESSING

(a) AIG for vacuum unit FIG. 2

(b) AIG for crude unit

Close-up view of the NH3 injection grid for vacuum unit (a) and crude unit (b).

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distribution of NH3 into the flue gas stream, species conservation by the catalyst bed. The flue-gas flow distributes as it reaches the equations are solved along with the flow equations. catalyst surface, but there are problems in this design. The velocity To reduce the computational effort, the flue gases, aqueous NH3 distribution indicates the presence of recirculation zones or dead (NH3 is injected in aqueous form to reduce hazards) and dilution zones in front of the catalyst bed. In Fig. 4b, the velocity profile air are defined as unique components interacting, but not reacting, for the crude unit and the effect of the catalyst bed, as well as the in the CFD model. Thus, the CFD model accounts for only three presence of the trolley beams just upstream of the catalyst bed are components for defining species transport. illustrated. The model clearly simulates This approach was adopted in the past by how the flue gas flows around the trolSayre and Milobow.2 The flue gas and the â&#x2013; Real engineering value ley beams and then redistributes across AIG inlets are modeled as mass flow inlets, the catalyst surface. Fig. 4b also identiand the SCR outlet is modeled as a pres- can be added projects fies a problem upstream of the SCR unit sure outlet. The catalyst bed is modeled in the flue-gas duct of the crude furnace. using a porous-media model, and pressure by using CFD models to There is excessive flow separation (nondrop across the catalyst is incorporated as uniform velocity profiles) caused by bends a source term in standard flow equations. examine design plans before in the flue-gas ducting. Since the AIG is The viscous losses are neglected, and only located near a bend, ideally the design frabrication. coefficients for inertial losses are calculated recommends streamlining the flue gas as and assigned in the CFD model. Pressureit reaches the AIG for uniform injection. velocity couplings are obtained using a When the flow is not streamlined, aquesimple algorithm, and the solution is solved using second-order ous NH3 injection with flue gas is not uniform. This will be upwind discretization schemes. discussed further. Table 1 summarizes details of key process conditions that are The CFD model is then used to investigate the flue-gas velocity essential in solving the CFD model. The design engineer should distribution across the catalyst surface and to determine whether provide the process conditions. From available information, some the first key design criteria is within the acceptable threshold. The quantities are calculated and used in the CFD modeling. Table 1 contours of the velocity profile for the preliminary designs are also lists the calculated quantities and values. plotted across the catalyst surface, as shown in Fig. 5. The CFD results are then used to calculate the percent root mean square (RMS) deviation of velocity distribution on the catalyst surface. CFD model results. The converged CFD models are then The percent RMS deviation is calculated using Eq. 1: used to analyze flow behavior in the duct designs. Various view planes are cut across the volume, and contours of pressure, velocity and species concentrations are plotted to provide a visual understanding of the effectiveness of various designs. The contours of pressure for both projects are plotted in a mid-plane and are shown in Fig. 3. From Fig. 3, the CFD model is successful in capturing the pressure drop across the catalyst bed for both projects. This is one of the results that a design engineer should check for in the CFD results. Contours of the flue-gas velocity for the preliminary system designs are plotted in mid-plane and are illustrated in Fig. 4. This figure provides additional details of the flow profile inside the SCR unit by showing an additional side view that is at a 90Â° rotation to the main view. The velocity distribution shown in Fig. 4a (the velocity profile FIG. 4 Velocity contour in mid-plane, ft/sec. for the vacuum unit), depicts the effect of pressure drop created

FIG. 3

Pressure contour in mid-plane, in. WC.

I SEPTEMBER 2009 HYDROCARBON PROCESSING

FIG. 5

Velocity contour on catalyst surface, ft/sec.

REFINING DEVELOPMENTS

FIG. 6

FIG. 7

SPECIALREPORT

by plotting the contours of aqueous NH3 on different cross-sectional planes, which are cut at various distances from the injection point. The contours of aqueous NH3 distribution across the catalyst surface for the preliminary designs of both projects are also shown in Fig. 6. For the vacuum-unit preliminary design, the aqueous NH3 mixes thoroughly with flue gases before it reaches the catalyst surface, and the calculated percent RMS deviation is less than the required ± 5% (see Fig. 6a) design criteria. In the crude-unit preliminary design, the aqueous NH3 distributes into the flue gas as the distance increases but the distribution is nonuniform. This occurs because the flue-gas flow is not streamlined at the injection point (near AIG). Most of the flue Velocity contour of aqueous NH3 concentration in different planes, in ppm. gas flows through the top section as it flows through the first 90° bend. The nonuniform injection and improper mixing stems from flow separation in the flue-gas stream caused by locating the AIG too close to a bend in the duct work. Result: The percent RMS deviation at the crude furnace SCR catalyst surface is greater than ± 5%, and the preliminary crude unit design fails the second design criteria. As shown, both projects have concerns that are problem specific. In the vacuum unit, the flue gas is maldistributing on the catalyst surface because of the low catalyst-bed pressure drop. For the crude unit, the aqueous NH3 is not mixing uniformly in the flue-gas stream before it reached the catalyst bed. CFD models successfully identified that both preliminary designs failed to meet at least one of the threshold design criteria. The identified problems are unique for both projects, and the causes for the problems identified from the CFD model can be applied to develop solutions. Effect of porous plate in vacuum unit; path lines and velocity profile highlighted.

Percent RMS =

1 N (x x )2 N 1 i=1 i

1 N

(1)

i=1

where N is number of data points, x is variable, which is of interest, and x is average. The calculated percent RMS deviation for the vacuum unit is greater than ± 15%; whereas, the value for the crude unit is less than ±15%. For the vacuum unit, the pressure drop across the catalyst bed is not adequate to properly distribute the flow over the catalyst surface. Recirculation or dead zones existing within the flow path inhibits proper distribution. The CFD model does not predict maldistribution for the crude unit preliminary design. In this case, the pressure drop across the catalyst is adequate to evenly distribute flue gases over the catalyst surface. Next, the CFD model is used to investigate the effectiveness of the AIG nozzle layout and the mixing of aqueous NH3 into the flue gas stream. An illustration of aqueous NH3 injection through the AIG is captured in Fig. 6. The degree of mixing is studied

CFD model: Proposed changes. The developed CFD models can be used to investigate solutions to solve design problems. For the vacuum unit, the inadequate pressure drop across the catalyst bed and the recirculation zone upstream of the catalyst bed are identified as causes of maldistribution. To eliminate the recirculation zone and to provide additional pressure drop, CFD study recommended installing a porous plate in front of the catalyst surface. The design team validated that this modification would not impact the total system operation and requested the CFD engineer to examine the proposed design change using CFD. The geometry is changed to include the porous plate. Fig. 7 shows modeling results with the porous plate and the pressure drop across the plate using porous media formulations. The CFD results clearly show the effect the porous plate in Fig. 7. The path lines indicate that the recirculation zone upstream of the catalyst bed is eliminated and the velocity distribution is more uniform across the catalyst surface (see Fig. 7 for path lines). The calculated percent RMS deviation for velocity is within the required ± 15%. For the crude unit, flow separation across the bend in the duct work upstream of the AIG is identified as the cause for improper injection and mixing. To eliminate the flow separation and to improve injection the CFD team recommended installing turning vanes in the bends upstream and downstream of the AIG. The team also recommended adding a porous plate in front of the catalyst surface as well. The design team approved both modiHYDROCARBON PROCESSING SEPTEMBER 2009

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FIG. 8

LITERATURE CITED http://www.epa.gov/air/urbanair. Sayre, A. N. and M. G. Milobow, “Validation of numerical models of flow through SCR units,” EPRI-DOE-EPA Combined Utility Air Pollutant Control, Aug. 16–20, 1999, Atlanta. Cho, S. M. and J. F. Borowsky, “On the optimization of SCR system flue design,” NETL Conference on Selective Catalytic Reduction (SCR) and Selective Non-Catalytic Reduction (SNCR) for NOx Control, May 16–17, 2001, Pittsburgh. Signer, A., “Mixing and flow conditioning in front of a catalyst bed for a SCR process,” NETL Conference on Selective Catalytic Reduction (SCR) and Selective Non-Catalytic Reduction (SNCR) for NOx Control, May 16–17, 2001, Pittsburgh. Adams, B. and C. Senior, “Improving design of SCR systems with CFD modeling,” DOE Environmental Controls Conference, May 16–18, 2006, Pittsburgh.

Effect of turning vanes in crude SCR installation; aqueous NH3 profile is highlighted. Duraivelan Dakshinamoorthy is a process engineer and

fications, and the CFD engineer examined the proposed design modifications using CFD. The geometry is changed with the turning vanes and porous plate. Fig. 8 shows the additions to the model as well as the changes to the aqueous NH3 profile after modification. The CFD model for the modified design clearly shows the effect of the turning vanes. The turning vanes mitigated flue-gas flow separation at the AIG and the aqueous NH3 distribution is greatly improved. Zones of high NH3 concentration at the SCR catalyst surface are now eliminated. The calculated percent RMS deviation of NH3 distribution at the catalyst is within the required ± 5% limit, and the design meets both key design criteria. HP

a computational fluid dynamics expert. He is currently working for Technip USA Inc. He has a PhD in chemical engineering from Wayne State University. He has been working as a CFD expert since his graduation. He has authored various articles related to CFD applications. His current interest focuses on expanding the extent of CFD applications in the oil and gas industry.

Amit Gupta is the director of technical sales with KTI Corp., Houston. He has 14 years of experience in the design of process fired heaters, steam-methane reformers, cracking furnaces and air-emission reduction systems. Mr. Gupta holds a BS degree in chemical engineering from the department of chemical engineering and technology, Panjab University, India.

H y d r o c a r b o n P r o c e s s i n g . c o m

WEBCAST Live Event September 10 , 2009

Heinz Bloch—Maintenance and Reliability Trends in the Refining, Petrochemical, Gas Processing and LNG industries Hydrocarbon Processing’s Reliability/Equipment Editor Heinz Bloch will be interviewed in his first webcast on maintenance and reliability trends in the refining, petrochemical, gas processing and LNG industries. With forecast maintenance spending of $59.1 billion in 2009 (source: HPI Market Data 2009) and concerns about profitability, efficiencies and the need to maintain operability, this webcast is a must watch for maintenance professionals worldwide. Heinz, as an editor for Hydrocarbon Processing for 10 years, has built a dedicated following worldwide in his area of responsibility. He holds six US patents and has authored over 460 technical papers and 17 books on machinery. He was an Exxon Chemical Co. machinery specialist and held positions worldwide before retiring after 24 years with Exxon. His deep personal and technical understanding in the area of maintenance and reliability and current trends will be presented via an interview with Les Kane, Hydrocarbon Processing’s Editor. The format will be three 15-minute segments followed by a live question-and-answer segment. To be a part of this exciting, one of a kind event for the HPI, visit www.HydrocarbonProcessing.com and click on the HP Webcast link to register for the one-hour live event on September 10, 2009. Attendees of the live event will have the opportunity to submit questions to the speaker. For those unable to make it, the webcast will be available on-demand for 12 months. Please contact Bill.Wageneck@GulfPub.com if you have any questions or need further details. Sponsored by |

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Improve efficiency of furnaces and boilers Novel â&#x20AC;&#x2DC;controlâ&#x20AC;&#x2122; scheme optimizes operations and reliability of combustion units F. RODRĂ?GUEZ, E. TOVA, M. MORALES, M. A. PORTILLA and L. CAĂ&#x2018;ADAS, INERCO, Seville, Spain; and J. L. VIZCAĂ?NO, CEPSA, Process Engineering, Huelva, Spain

ew technologies enable optimizing combustion processes for hydrocarbon processing facilities. Economic and environmental drivers require improving operating efficiency while mitigating emissions of carbon dioxide (CO2), nitrogen oxide (NOx), carbon monoxide (CO) and particulates. â&#x20AC;&#x153;Smootherâ&#x20AC;? operations increase the safety for combustion units. In the following case history, a Spanish refiner applies a novel combustion control technology to the crude oil furnace. The article describes the overall technological approach and the latest results, regarding combustion efficiency improvement (overall CO2 emissions reduction) and parallel effects in NOx emissions control, through the implementation of a novel combustion control technology to a crude oil furnace of a Spanish refinery. Project goals included reduced CO2 and NOx emissions with better reliability.

Background. Combustion improvement offers the greatest potential for economic savings regarding the operation of industrial boilers and furnaces. Nevertheless, the combustion process is opaque from the operatorâ&#x20AC;&#x2122;s point of view. For this operating unit, fuel costs are the greatest operating expense; yet, how this fuel is utilized remains unclear. Despite the economic and environmental importance of combustion processes, these operations involve a low level of monitoring and control. These processes are governed by a few global variables such as excess oxygen (O2) or process stream yields, with no direct control of combustion conditions. Furnace or boiler operations are supported by standardized procedures and operator experience, rather than by effective online information and optimized flame control. Moreover, in most cases of multiburner application, standard monitoring applied for global excess O2 control in the combustion unit does not represent the true average excess O2 value at the furnace level, thus introducing a critical restriction when trying to optimize tuning of combustion conditions. This situation heavily contrasts with the current state-of-theart level of most industrial processes, in which comprehensive monitoring and advanced control systems ensure process safety, plant availability and maximum efficiency. It is surprising that a chemical process such as combustion, with an impressive economic and environmental impact worldwide, still relies on nearly archaic controls.

Recently, considerable attention has been directed to combustion adjustments for efficiency optimization and emissions limitation. Nevertheless, the cost-effectiveness of these adjustments is limited by mentioned restrictions over combustion monitoring and control. This gives rise to the erroneous decision to upgrade the burner system without first attempting to optimize the present combustion system. This situation is even more relevant in scenarios with high variability in fuel properties, loading profiles and/or burner arrangements for multiburner systems. In these cases, uncontrolled combustion conditions may force operators to apply â&#x20AC;&#x153;too conservativeâ&#x20AC;? boiler settings and to move away from optimum tuning. Controlled furnace technology. Efficiency and emissions (NOx, CO, CO2, particles, SOx, etc.) in industrial furnaces and boilers depend largely on the correct distribution of fuel and air supplies to the combustion process. Moreover, inappropriate fuel/ air ratios on critical locations severely impact important furnace parameters (Fig. 1). Therefore, stricter combustion controls are a function to balance the combustion process.

1 Imbalances typicallyÂ foundÂ in combustion process: t &YUSFNFMZ WBSJBCMF BTĂ¸B function of the loading scenario) t 3FMBUFEĂ¸UPĂ¸JNCBMBODFE design and operationÂ of air/fuelÂ supplyÂ systems t #SJOH POĂ¸PQFSBUJPOBM limitations and restrictions onÂ resultsÂ of optimization strategies

Oxygen excess

3FTVMUT /FHBUJWFĂ¸FGGFDUT &GmDJFODZ &NJTTJPOT /0x, CO, CO2, particles, SOx, etc.) Corrosion,fouling 1JQFĂ¸PWFSIFBUJOH OperationalÂ safety

2 Lack of combustion process TVSWFJMMBODF QPPS BWBJMBCMF monitoring): t Ă¸PSĂ¸ Ă¸QPJOUTĂ¸POĂ¸FYJUJOH excess oxygen t 'VFMĂ¸BOEĂ¸DPNCVTUJPOĂ¸BJS globalÂ supply

Usual monitoring capabilities Â

FIG. 1

'VFMĂ¸BOEĂ¸BJS globalÂ supply

Air 'VFM

Key optimization operating criteria for HPI furnaces and boilers. HYDROCARBON PROCESSING SEPTEMBER 2009

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Local combustion monitoring

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Optimized tuning for balanced combustion

Combustion optimization strategies

EfďŹ ciency NOx

Local monitoring: (proďŹ le with variable locations) t "EWBODFE NPOJUPSJOH (O2, NOx, CO, CO2, etc.) t 5FNQFSBUVSFT

CO2

Basic option (measurements at post combustion zone)

"EWBODFE PQUJPO EJSFDU JO GVSOBDF measurements)

Controlled furnace 3 Combustion control: expert TZTUFN PQFO DMPTFE MPPQ

Tuning for uniform, stable and safe combustion conditions FIG. 2

Maximum NOx and efďŹ ciency control using implemented capabilities

Alternative or complement to design modiďŹ cations (LNB, windbox)

"JS GVFM BOE PS ESBGU regulation: improvement capabilities

FIG. 3

Air Fuel

Operating points of controlled furnace approach to optimize combustion.

Logic diagram for controlled furnace approach.

Combustion optimization technology relies on the adequate closed-loop control of local combustion conditions, promoting what is called a â&#x20AC;&#x153;controlled furnaceâ&#x20AC;? (Fig. 2). This controlled operation is a critical factor to ensure the maximum benefits of combustion variables adjustment whose tuning directly impacts unit efficiency and NOx formation. The controlled furnace approach enables individual optimization for any single burner. Result: Total optimization of the combustion process. This application improves unit efficiency and reduces CO or NOx emissions by applying specific optimization strategies in multiburner systems. Consequently, this approach is both a cost-effective alternative to implementing combustion-system modifications (burner substitution) and is an additional improvement tool if these modifications are finally installed. Also, installing this technology to an existing combustion unit requires minimum modifications to existing equipment and a shorter shutdown to install the associated new elements. As shown in Fig. 3, controlled furnace conditions involve an integrated approach and require: â&#x20AC;˘ Advanced monitoring technologies â&#x20AC;˘ Novel regulation systems for combustion optimization â&#x20AC;˘ Expert software for optimized combustion control.

etries, identifying the optimum number of active burners for each operating load, measuring flame stability, and/or reducing NOx generation. Particular applications of this technology include: â&#x17E;¤ Direct assessment of local combustion conditions at any furnace area, not limited by existing furnace viewing ports. â&#x17E;¤ Correct determination of actual excess-air levels within the furnace, which facilitates identifying possible air leakages, as well as, safe implementation of combustion optimization strategies. â&#x17E;¤ Supervision of real combustion conditions: scenarios of load regulation and fuel property variations to support the decisionmaking process on the number and location of active burners for each loading, optimizing excess-air levels for each load, and identifying maintenance problems. â&#x17E;¤ Surveillance and tuning of combustion conditions for scenarios with significant fuel property variations. â&#x17E;¤ Control tool for managing NOx reduction while maintaining an adequate control of safety limits for boiler regulations. Also, controlled furnace conditions can enhance complementary combustion monitoring capabilities: â&#x20AC;˘ Pyrometers grid to determine furnace temperature distribution â&#x20AC;˘ Online measurement of fuel and air flowrates â&#x20AC;˘ Gas-emissions monitoring. The scope of the monitoring approach is to be decided for each case according to plant design, operation characteristics and performance objectives.

Advanced monitoring technologies. Monitoring in-

furnace combustion conditions enables developing accurate combustion surveillance, which is essential to implement controlledfurnace conditions. Local-furnace monitoring guides the operator to obtain the most adequate tuning for any individual burner. Such actions facilitate the total optimization of the combustion unit. Improved operations increase unit operating efficiency and mitigates emissions as well as provide a safer, more reliable and flexible unit operation. Also, in-furnace monitoring technologies aid in identifying hidden furnace or boiler malfunctions that can increase CO levels, even though the unit is working under correct combustion conditions. Also, such monitoring enables adjusting flame geom88

I SEPTEMBER 2009 HYDROCARBON PROCESSING

Novel regulation systems for combustion. Implementing controlled furnace conditions involves, in most cases, better boiler tuning capabilities. Better boiler operations can involve one or a combination of the following conditions: â&#x17E;¤ Automation of existing manual regulations from the control room â&#x17E;¤ Implementation of other fuel and air regulation dampers and valves â&#x17E;¤ Modification in the design of existing burners to increase their tuning potential. By applying these operating conditions, existing regulation capabilities are improved as if new burners, i.e., low-NOx burners (LNB) were installed. When further NOx reductions are

REFINING DEVELOPMENTS

Expert software optimizes combustion control.

Controlled-furnace conditions are established in closed-loop control scenarios by integrating the previously described monitoring and regulation capabilities with advanced combustion control systems, which are configured for each specific application. This integration allows applying combustion optimization strategies with the maximum reliability and profitability. Main features of these strategies are implemented within an appropriate expert combustion control design that establishes a subordinate manner to the combustion unit master control. Both control systems do not interfere, as the expert combustion control will only affect adjustments not related to the unit master control. The expert system is configured individually for each combustion unit through specific combustion tests.

10,000 CO conccentration, vppm, 3% O2

demanded, these regulation systems are totally complementary to more substantial plant modifications (such as LNB or windbox redesign.)

SPECIALREPORT

9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 0

Controlled O2 reduction: (after application) Averaged excess O2 :1.9 % Maximum CO level: 0 vppm

Dispersion below 1.8% FIG. 4

Uncontrolled O2 reduction: Averaged excess O2: 3.3% Baseline operation: Maximum CO level: Averaged excess O2: 6.9% > 7,900 vppm Maximum CO level: 0 vppm

3 4 5 Excess O2, %

Dispersion above 3.5%

Performance data of controlled furnace application at refinery.

II. Disagreement between O2 figures detected by the original O2 monitoring system (averaged figures within the 3.5%–4.5% optimization project of a direct-fired heater to the crude oil unit interval) and the more accurate values resulting from complete at a Spanish refinery. This furnace is equipped with 32 horizontal controlled furnace approach (with average O2 levels of 1% to oil-and-gas burners placed in two opposite 3.5%+). Manual measurements carried out at furnace exit sections demonstrate rows. A refractory division wall is located the full agreement between the averaged in the middle of the furnace for bending ■ Efficiency and emissions in measurements from the implemented systhe flames and defining two independent industrial furnaces depend tem and global furnace excess O2 levels. in-furnace areas. Therefore, the existing monitoring sysFor the base case of the furnace, moni- on the correct distribution of tem does not represent the total excess O2 toring of the incoming combustion air was levels in this furnace. Furthermore, the carried out by an O2 probe placed in the fuel and air supplies to the center of the east side wall. Two manual global excess O2 monitoring is not comdraft regulating dampers, located at north combustion process. parable, in terms of combustion optimizaand south furnace chimneys, were used for tion potential, with valuable information overall combustion air control. Burners were also equipped with provided the advance monitoring system. manual primary and secondary air regulation capabilities. III. As a consequence from items I and II, the high excess O2 and minimum CO levels at the furnace outlet section were meaNew optimization. The scope of the optimization study of sured (Fig. 4). High NOx generation associated with O2 levels is the crude unit furnace settled using controlled furnace conditions. also produced. The averaged furnace O2 values measured by the This approach is aimed at attaining optimized furnace efficiency local in-furnace monitoring system ranged between 5%–7%. scenarios, while covering every possible operating situation via: • An in-furnace monitoring system to characterize the comControlled-furnace system performance. Following bustion process at each individual burner. the installation of improved combustion control strategies via a • Automation of the air-regulation dampers in both rows of controlled-furnace approach, a clear evolution of excess O2 levels, the multiburners; optimized flame tuning and furnace stacks via recorded by the local in-furnace monitoring system, could be better control of the furnace draft. observed from the baseline operation to the controlled operation • A control approach and an expert system for the closed-loop (Fig. 4). The resulting final O2 average values were around 2% control of the total process. (from initial average values around 5%–7%). Final combustion conditions via the controlled furnace strateProcess baseline characterization. The combustion furgies enabled safer, sustainable (negligible CO levels), homogenace baseline is determined by a thorough testing campaign using neous and efficient combustion scenarios. The controlled furnace new monitoring and regulating capabilities. This testing campaign conditions were reached via appropriate global and individual air is designed to cover all possible furnace operating scenarios in regulations tuning carried out by the expert combustion control terms of duty requirements, nature and proportions of fuels used, system following a fully automated process. burners in service, etc. Results of this combustion diagnosis for The reported 3%–5% excess O2 minimization was coupled to a the furnace base case are: gas temperature reduction and resulted in an overall fuel consumpI. Identify important imbalances between individual burntion savings above 5%. An equivalent reduction was obtained for ers. Measured differences above 3.5% in excess O2 levels (and CO2 and SOx emissions. Results included in Fig. 4 show a clear even higher for uncontrolled global O2 reduction scenarios) limit reduction in the results dispersion for controlled operation. efficiency optimization efforts through uncontrolled combustion The controlled operation enables identifying burner maltuning strategies that generate unsustainable CO levels. (Fig. 4 functions. These types of malfunctions can remain hidden when shows the baseline operation.) conventional monitoring is applied. Burner malfunction idenCase history. The following example discusses the combustion

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NOx concentration, mg/Nm3, 3% O2

700 600

Conventional burner

Base Case

500

Optimized Case 2

400 300

Optimized Case 3

200

Low NOx burner

Optimized Case 1

100

Burner retroﬁtting Combustion optimization

0 0 FIG. 5

4 5 Excess O2, %

Applicability of controlled furnace approach for conventional and low-NOx burner applications.

tification is an essential tool for a cost-effective burner maintenance program. Result: Optimized maintenance schedules can be achieved via a controlled furnace approach. Improve combustion. When facing combustion optimization challenges, such as efficiency improvement and/or emissions reduction (NOx, CO, CO2 or particles), the controlled furnace approach can provide an advantageous alternative, and is an essential complement, to large-scale combustion installations. Benefits from such applications include:

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• Improved unit combustion efficiency resulting in fuel consumption savings above 5% (with equivalent CO2 and SOx emission reductions). • Simultaneous reductions in total NOx emission (tph) up to 45%–50% (resulting in NOx emissions levels ranging 300 mg/ Nm3–350 mg/Nm3, referred to 3% O2). • Control of unburnt fuel and CO emissions yields negligible CO levels even for the most stringent low-excess-air scenarios (average excess O2 is approximately 2%). Applying the controlled-furnace approach to the crude oil furnace can result in improved combustion control that fosters higher unit reliability, safer operation and reductions in maintenance costs. Crucial information for preventive maintenance action is obtained by immediately identifying burners malfunctions (before major failures or damages are produced) and by continuous control of CO or unburnt fuel, which are also associated with fouling and coke deposits scenarios. The potential of this optimization strategy is significantly increased under scenarios of variable fuel supplies or operation loads, where combustion unit operators are otherwise totally “blind” to the changes occurring in the combustion process. This approach is a cost-effective alternative and/or a valuable complementary tool to larger-scale combustion system retrofits, which would necessarily lead to combustion facilities with more complex designs and greater needs for surveillance and control (Fig. 5). In addition, the important parallel reductions in NOx emissions achievable through controlled-furnace applications could make it feasible, from an environmental point of view, and espe-

HYDROCARBON PROCESSING is the leading monthly magazine for staying connected to the hydrocarbon processing industry. Published since 1922, HYDROCARBON PROCESSING provides operational and technical information to improve plant reliability, profitability, safety and end-product quality. The editors of HYDROCARBON PROCESSING bring you first-hand knowledge on the latest advances in technologies and technical articles to help you do your job more effectively. November 2009: Plant Safety and Environment • Safety systems facility compliance, global security issues • Flare systems, design, management, maintenance • Emissions control valves, vessels, pumps, piping December 2009: Plant Design and Engineering • Project management • CAD/CAM • Laser scanning January 2010: Gas Processing Developments • Sulfur removal technologies • Liquefied natural gas (LNG) and gas-to-liquid (GTL) advances • Catalyst developments As a paid subscriber you will receive, in addition to your 12 monthly issues, in print or digital:

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REFINING DEVELOPMENTS cially in NOx saturated industrial areas to request and authorize new projects involving facility/capacity expansions. HP ACKNOWLEDGMENTS The authors gratefully acknowledge the collaboration of other personnel involved in activities resulting in this article. Special thanks are given to the technical staff of CEPSA’s La Rábida Refinery and to INERCO’s Industrial Processes Division. Foundations of controlled-furnace technology were developed with partial financial grants from the ECSC European Programme, the Spanish Industry and Environment Ministry and the Andalusian Regional Government.

SPECIALREPORT

Miguel Portilla is the analyses and testing head of INERCO’s Industrial Processes Division. He has worked for the last 15 years in the validation and industrial application of technologies for optimizing industrial combustion systems and abatement of pollutants. Mr. Portilla holds a degree in chemical and process engineering from the University of Seville’s School of Engineering. He has collaborated in the publication of one scientific paper in an international journal, as well as in the development of two papers given at international conferences, and is also co-inventor of one patent related to the technologies involved.

BIBLIOGRAPHY 1

Rodríguez, F. E. Tova, M. Morales, M., Portilla, L. Cañadas and J. L. Vizcaíno, “Efficiency Improvement and Emissions Reduction in Refinery Boilers and Furnaces,” 19th World Petroleum Congress, Madrid, 2008. Rodríguez, F. E. Tova, M. Morales, M., Portilla, L. Cañadas and J. L. Vizcaíno, “Application of controlled furnace technology for efficiency improvement and emissions reduction in refinery combustion units,” 12th European Refining Technology Conference, Barcelona, 2007. Rodríguez, F., E. Tova and M. Morales, “Efficiency and environmental optimization of boilers through controlled furnace technologies,” Control and Automation of the Combustion Process in Power Generation Boilers Conference, Szczyrk, Poland, 2007. Rodríguez, F., E. Tova and L. Cañadas, “ABACO technology for NOx control and efficiency improvement,” International Symposium “Strategic Approach for Implementation of Primary DeNOx Measures in Large EU Pulverised Coal and Lignite Fired Units”, Athens, 2005. Rodríguez, F., L. Salvador-Camacho, M. Morales, L. Cañadas, P. Otero, P. Gómez and M. Ramos, “NOx control and heat rate improvement through primary measures based on advanced furnace control,” DOE-EPRI-U.S. EPA-A&WMA 2003 Mega Symposium, Washington, D.C., 2003. Rodríguez, F., E. Tova, V. Cortés and L. Cañadas, “ABACO-Opticom: Advanced automatic monitoring system of local combustion conditions for improving boiler performance in PC power plants,” Fuel, Vol. 81, No. 5, pp. 637–645, 2002. Copado, A., F. Rodríguez, L. Cañadas, V. Cortés, P. Gómez and E. PérezSantos, “Boiler efficiency and NOx optimization through advanced monitoring and control of local combustion conditions,” Clean Air Conference, Technologies and Combustion for a Clean Environment, Oporto, Portugal, 2001.

Prof. Dr. Luis Cañadas is the Engineering and Operations Director of INERCO S.A. He has more than 20 years of experience in the optimization of industrial combustion systems and in the abatement of pollutants emissions. Prof. Dr. Cañadas holds a Ph D in chemical and process engineering from the University of Seville’s School of Engineering, where he is a Full Professor. He has published more than 20 scientific papers in national and international journals. Dr. Cañadas, along with other co-inventors, holds five patents associated with combustion optimization technologies.

José Luis Vizcaíno is the process engineering manager of La Rábida Refinery (CEPSA). He has more than 20 years of experience in process engineering. Previously, he worked in ERT Research Center and in a waste water treatment plant. Mr. Vizcaíno holds a MSc degree in chemistry from the University of Seville. He has also collaborated with INERCO in the publication of a scientific paper in an international journal and in the preparation of two papers given at international conferences.

Dr. Francisco Rodríguez is the director of INERCO’s Industrial Processes Division. He has worked for the last 20 years in developing optimization technologies for industrial combustion systems and abatement of pollutants. Dr. Rodríguez holds a PhD in chemical and process engineering from University of Seville’s School of Engineering, where he is a Professor. He has published more than 10 scientific papers in national and international journals. Dr. Rodríguez, along with other co-inventors, holds five patents associated with the technologies developed within this research line.

Let Tray-Tec assist you with your next installation of process equipment in your towers, reactors and drums. From refineries, chemical plants to ethanol, gas and fabrication shops, Tray-Tec is ready and able to work safely in your facility.

Enrique Tova is the process engineering department manager of INERCO’s Industrial Processes Division. He has 20 years of experience in the design and industrial validation of advanced technologies for combustion optimization and pollutants abatement. Mr. Tova holds a degree in chemical and process engineering from the University of Seville’s School of Engineering and is co-inventor of five patents related to the technologies developed by INERCO. He has published seven scientific papers at national and international journals and has also collaborated in the development of seven papers given in international conferences.

Miguel Morales is the business development head of INERCO’s Industrial Processes Division. He has more than 10 years of experience in the validation and industrial application of technologies for combustion optimization and pollutants abatement. Mr. Morales holds a MSc degree in chemical and process engineering from the University of Seville’s School of Engineering. He has been co-author of two scientific papers published in international journals and has also collaborated in the development of five papers given in international conferences. Select 172 at www.HydrocarbonProcessing.com/RS 91

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SPECIALREPORT

Residue upgrading: Challenges and perspectives New hydrocracking technology efficiently ‘cracks’ heavy end cuts for distillates D. STRATIEV and K. PETKOV, Lukoil Neftochim Bourgas AD, Bourgas, Bulgaria

‘Dirtier’ crude slate. Conventional oil reserves are approxi-

mately about 3 to 4 trillion bbl. In contrast, heavy oils and extraheavy plus bitumen reserves total nearly 8 trillion bbl.1 In the near-term, high-quality transportation fuels will still be crude-oil based. Research efforts for alternative fuels will make significant contributions in the future, but these technologies are still commercially unavailable.2,3 Pricing trends. Current economic conditions further empha-

size developing heavy residual oil conversion technologies. Previously, a slow-down in applying residue upgrading methods occurred in refining configurations.4 However, due to sky-rocketing crude oil prices in 2008, conversion technologies once again became a key driver to improve refinery profitability.5 Fig. 1 shows how high crude prices can be a benefit for complex refineries that include residue-conversion facilities. As crude oil prices rose from $40/bbl to $90/bbl, the price for transportation fuels and fuel oil increased from $18/bbl to $46/bbl. Unlike the price for other fuels, coke pricing exhibited no dependence on crude oil prices. From 1998 to 2007, coke prices varied from nearly $0 to $1.67/MMBtu.6 For example, when comparing the price of residual fuel oil—$315/metric ton (mton) to pet-coke ($1.67/MMBtu), petcoke heat of combustion = 30.33 MMBtu/mton and is priced at $50.6/mton at a crude price of $65/bbl.7 A difference of about $264/mton favors residual fuel oil. Under these conditions, the coking process is less profitable as compared to residue upgrading technology. Heavy-upgrading processes. Residue conversion processes are divided into two categories: carbon rejection and hydrogen

130 120 110 100 90 80 70 60 50 40 30 20 10 0

Gasoline, diesel, residual fuel oil, prices $/bbl

rowing demand for transportation fuels requires “squeezing out” the maximum distillates from every barrel of crude oil refined. The global switch to heavier, sourer crude feedslate makes this task even more difficult. As refiners process more opportunity crudes to improve margins, more complex processing operations such as residue upgrading will be required to produce “cleaner” transportation fuels. Most resid operations use thermal methods to crack long, complex hydrocarbon compounds into desired blending-pool products. New nano-sized catalysts are redefining upgrading operations, especially in hydrocracking processes. Such catalyst systems facilitate hydrogen in addition to vacuum resid products to produce higher value distillates.

Gasoline Diesel Residual fuel oil Delta = $46/bbl per barrel

Delta = $18/bbl per barrel 0

40 50 60 Crude oil, $/bbl

100

Source: Energy Information Administration

FIG. 1

Dependence of gasoline diesel and residual fuel prices on the crude oil price.

addition. Carbon rejection is divided into residue catalytic cracking (RCC) and thermal conversion processes (coking and visbreaking). RCC can be used to upgrade relatively “clean” residual oils— Conradson carbon (CCR) not higher than 6% and metals: Ni+V concentration < 35 ppm).4 Coking is the most suitable method to process high CCR and/or high-metals residual oils. Hydrogen addition processes. These processes upgrade residue with a catalyst in the presence of hydrogen. Both coking and hydrocracking processes are thermal conversion methods. 8–12 In hydrogen addition processes, the catalyst’s purpose is to inhibit undesired polycondensation reactions and extend the conversion range.13 The maximum conversion level in hydrocracking processes is limited due to the stability of unconverted products and its resistance to separate into two phases.14 Advanced catalyst developments enable increasing conversion while keeping the sediments within acceptable limits in residue hydrocracking processes.15 Residue hydrocracking processes provide cleaner, higher value products than coking methods. But applying a residue hydrocracking process will encounter difficulties with feedstocks characterized by high metals, CCR and asphaltenes content. Such applications have higher catalyst costs with lower achievable conversion. A review on recent advances on residue upgrading HYDROCARBON PROCESSING SEPTEMBER 2009

I 93

SPECIALREPORT

REFINING DEVELOPMENTS

TABLE 1. Physical and chemical properties of different vacuum resids Vacuum resids

Sulfur, %

d420

Nitrogen, %

CCR, %

Ni, ppm

V, ppm

Saturates, %

Aromatics, %

Resins, %

Asphaltenes, %

C/H ratio, atomic

Daqing1

0.9392

0.15

0.44

8.2

7.6

0.1

41.9

32.7

25.4

1,051

1.79

Shengli1

0.9724

3.01

0.95

55.7

3.3

16.1

30.6

51.1

2.2

967

1.58

Saudi light1

1.0045

3.99

0.45

19.9

60.6

16.5

49.5

26.8

7.3

804

1.47

Saudi

medium1

1.0258

4.79

0.53

36.7

147.4

15.9

33.7

9.3

1,046

1.51

Iranian light1

1.0057

2.92

0.93

19.2

66.4

245.7

18.5

44.8

30.6

6.1

1,052

1.49

Iranian heavy1

1.0222

3.11

0.62

22.1

205.8

12.6

46.6

29.9

10.8

909

1.44

Oman1

0.9637

1.68

0.45

13.8

21.8

26.3

40.6

31.2

979

1.6

Athabasca bitumen1

1.0596

5.29

0.66

27.1

160

422

6.3

29.4

31.4

1,191

1.34

REBCO2

0.9984

2.42

0.42

15.3

207

62.7

10.2

3.2

853

MVBF3

1.0176

4.29

19.8

14.76

67.9

6.4

10.5

871

HRA3

1.0542

4.93

25.7

5.63

68.1

11.9

13.7

1,079

1.53

BHSR3

0.9636

0.45

12.8

32.89

59.8

4.23

4.5

794

2.14

NGSR3

0.9887

0.28

15.36

10.3

58.7

29.2

2.11

Arab

light4

Minas4

17.1

11.1

74.7

8.9

5.3

10.4

51.6

25.4

8.5

14.5

1.52

Dagang5

0.979

0.24

16.3

32.2

37.3

0.5

1,083

Gudao5

0.9945

2.52

1.42

15.6

17.3

48.4

3.3

969

Huabei5

0.33

0.59

37.6

31.4

29.9

1.1

770

Liaohe5

0.34

0.98

20.8

31.8

41.6

5.7

4.22

4,100

18.4

19.7

20.3

816

4,500

18.3

15.7

52.7

31.6

907

SQVR6

1.0173

SZVR6 1

1.0209

Source: Ref. 18;

Source: Ref. 28;

4.77 3

Source: Ref. 10;

Source: Ref. 34;

Source: Ref. 26;

1.59

960

Source: Ref. 12

2.0

1.8 25

1.6 1.4 H/C atomic

CCR,%

1.2

1.0

0.8 0.6

0.4

0 0

30 Saturates, %

H/C ratio of vacuum resids H/C ratio of end-cut vacuum resids

0.2 0.0 0

FIG. 2

Vacuum resid Conradson carbon as a function of saturates content. FIG. 3

technologies has been published.16 Yet, this review did not analyze the underlying chemistry for residue upgrading technologies. More research work is needed to fill these gaps and analyze the chemistry for residue conversion processes. Resid process chemistry. Characterizing heavy-oil fractions has always been problematic due to their complexity and intricacy to analysis components. Efforts have been dedicated to developing techniques that can provide in-depth investigation over the chemistry of residual oils and bitumen.17â&#x20AC;&#x201C;28 Many studies have explored the chemical nature of the heavy oils and have tried to correlate residual feedstock properties with conversion and yields obtained through residue conversion processes. 94

I SEPTEMBER 2009 HYDROCARBON PROCESSING

30 35 CCR,%

Relationship between CCR and H/C atomic ratio in vacuum resids and obtained from them by SFEF end-cut.18

Table 1 summarizes the physical and chemical properties of residual oils investigated from various studies. These data clearly show that vacuum residues from varying origins can significantly differ in chemical nature. By analyzing the data, the CCR correlates with saturates content (Fig. 2). However, the data scattering indicates that CCR does solely depend on the resid saturates content. Fig. 3 shows that data can correlate the dependency of CCR on the H/C ratio for heavy oils and end-cut of these residual oils obtained by using supercritical fluid extractive fractionation (SFEF).18 From the data, it is clear that the dependence of bulk CCR for residue is different from that of the end-cut. Result: The end-cut

REFINING DEVELOPMENTS

TABLE 2. Properties of Athabasca bitumen and derived DOA by selective asphaltene extraction and slurry hydrocracking processes

Coke yield,%

Data of the selective asphaltene extraction process7

32 28 24 20 18

FIG. 4

SPECIALREPORT

24 26 CCR,%

Relationship between residual feedstock Conradson carbon and coke yield obtained in the Flexicoking units.29

Athabasca bitumen

Feed

DAO

Yield, wt.%

100

Sp. gravity

1.0158

0.9792

S, wt.%

4.2

Ni, ppm

V, ppm

220

13.4

6.5

CCR, wt.%

Data of the slurry hydrocracking process8 Athabasca bitumen

chemistry is very different from the full-range residual oil. The original focus was on CCR because it best characterizes the tendency of residual feedstocks to coke in conversion processes. Data from a fluid-coking process (Fig. 4) indicate that coke yield directly correlates with the residue CCR.29 In Fig. 4, the data are in line with observation by others that coke yields from fluid coking is 1.3 times that of the feed CCR, and delayed coking is 1.6 times that of the feed CCR.11 Characterizing the cuts include using methods such as residual oil by using SFEF and investigating reactivities of these cuts via thermal cracking and hydrocracking processes. Such characterization methods can reveal that the residue end-cut consists primarily of resins and asphaltenes that cannot be hydrogenated. Also, the mechanism to remove nitrogen, metals and concarbon residue during resid hydroprocessing is possible by partitioning, which is very similar to coking.11,12 The end-cut could be a coke precursor. Condensation and hydrogen-abstraction reactions of the end-cut are predominant at elevated temperatures. Thus, the reaction products from the end-cut are independent from the conversion process. Study. Early research showed that the residue end-cuts inhibit catalytic reactivity of the lighter fractions.17 Other researchers investigated the narrow cuts of Athabasca bitumen pitch, hydrocracking and once-through coker vacuum residues. 18 The study showed that the 524°C+ material in the Athabasca bitumen pitch has the highest H/C ratio (1.33) followed by hydrocracker resid (1.29), coker resid (1.23) and pentaneinsoluble asphaltenes (1.21). 11 These data indicate that the ebullated-bed hydrocracking cannot add hydrogen to heavyboiling materials. From these findings, we can conclude that the end-cut should be removed from residue; it cannot be upgraded via hydrocracking processes. Also, such materials inhibit upgrading catalyst performance for the remaining residue. A selective asphaltenes-extraction process using supercritical extraction fractionation methods was developed.30 In this process, the residue end-cut is extracted from the residue with n-pentane. The provided example shows that, while the end-cut of the Athabasca bitumen separated by selective asphaltene extraction is 15%, the low-value products of coke and gas in the coking process would be 32% (22% coke + 10% gas). Accordingly, yield of lower value products can be reduced by 17%, thus providing a possible substantial profitability increase. The residue without the end-cut could be converted in a packedbed hydroprocessing unit and achieve higher conversion.

Feed

DAO

Yield, wt.%

100

12.8

Sp. gravity

1.042

0.9646

S, wt.%

5.3

1.44

Ni, ppm

V, ppm

240

CCR, wt.%

17.4

Source: Ref. 30;

3.48

Source: Ref. 33

New developments. A breakthrough in the resid conver-

sion uses a novel slurry hydrocracking process that is particularly well-suited for upgrading a variety of “black oil” materials— from conventional vacuum resids up to extra-heavy oils and bitumen.1,31,32 The resid process uses nano-sized hydrogenation molybdenum-based catalysts (molybdenite, MoS2) that allow complete feedstock conversion without producing residual byproducts, such as petroleum coke or heavy fuel oil.33 Testing of the new resid hydroprocessing technology used Athabasca bitumen in a commercial demonstration plant. The new resid conversion process yielded 76.9% distillates, 10.3% gas and 12.8% heavy-boiling material—deasphalted oil (DAO).33 Table 2 compares the yields and quality of DAO applying selective asphaltene extraction and slurry hydrocracking processes. Unlike supported catalysts used in ebullated-bed hydrocracking processes, the nano-sized hydrogenation catalyst in the slurry hydrocracking method promotes hydrogen addition to the heavyboiling material. CCR is reduced from 17.4% to 3.48% in the heavy product (DAO). Assuming that the relation between CCR and H/C ratio is the same as shown in Fig. 3 for original resids, an increase of the H/C ratio from 1.55 in the slurry hydrocracking feed to 1.87 in the heavy-boiling product could be observed. The quality of slurryhydrocracking process DAO is better than that obtained by the selective asphaltene extraction process; it has a lower CCR and does not contain metals. Moreover, the feed in the slurry hydrocracking process (Athabasca bitumen) is heavier than that used in the selective asphaltene extraction process. Therefore, the slurry hydrocracking process can make it possible to upgrade the heavy end of the residues and it excludes producing heavy fuel oil. That was not possible in the supported-catalyst hydrocracking process. The advances in catalysis chemistry have facilitated significant improvements in hydrocracking technology. It is a possibility that the slurry hydrocracking process could replace some present residue upgrading methods—coking process—because it can provide refiners with the opportunity to maximize distillation production. HP HYDROCARBON PROCESSING SEPTEMBER 2009

I 95

SPECIALREPORT

REFINING DEVELOPMENTS

LITERATURE CITED Delbianco, A., N. Panariti, R. Montanari, R. Sartori and S. Rosi, “The Eni Slurry technology process: development and potential application,” ERTC 2005, Vienna, Nov. 14–16, 2005. 2 Gonzales R., “New markets for low-value streams,” Petroleum Technology Quarterly, Q2, 2007, p. 3. 3 Gonzales, R., “Feedstocks for the future,” Petroleum Technology Quarterly, Q3 2006, p. 3. 4 Phillips, G., and F. Liu, “Invest in the future,” Hydrocarbon Engineering, September 2003. 5 Wilcox, M., “Not a Euro more, not a Euro less – time to invest in European refining,” ERTC 2005, Vienna, Nov. 14–16, 2005. 6 http://www.iseee.ca/. 7 www.aseanenvironment.info/scripts/count_ar ticle.asp?Ar ticle_ code=41012922. 8 Singh, J., M. M. Kumar, A. K. Saxena, and S. Kumar, “Studies on thermal cracking behavior of residual feedstocks in a batch reactor,” Chemical Engineering Science, Vol. 59, 2004, pp. 4505–4515. 9 Bozzano, G., M. Dente, and F. Carlucci, “The effect of naphthenic components in the visbreaking modeling,” Computers & Chemical Engineering, Vol. 29, 2005, pp. 1439–1446. 10 Singh, J., M. Kumar, A. K. Saxena, and S. Kumar, “Reaction pathways and product yields in mild thermal cracking of vacuum residues: A multi–lump kinetic model,” Chemical Engineering Journal, August 2005, pp. 239–248. 11 Chung, K. H., and Ch. Xu, “Narrow-cut characterization reveals resid process chemistry,” Fuel 80, 2001, pp. 1165–1177. 12 Yang, C., F. Du, H. Zheng, K. H. Chung, “Hydroconversion characteristics and kinetics of residue narrow fractions,” Fuel 84, 2005, pp. 675–684. 13 Panariti, N., A. Del Bianco, G. Del Piero, and M. Marchionna, “Petroleum residue upgrading with dispersed catalysts. Part 1. Catalysts activity and selectivity,” Applied Catalysis A: General 204, 2000, pp. 203–213. 14 Gragnani, A., and S. Putek, “Resid hydrocracker produces low-sulfur diesel from difficult feeds,” Hydrocarbon Processing, May 2006, Vol. 85, pp. 95–100. 15 Lakhanpal, B., D. Klein, P. Leung, B. Tombolesi, and J. Kubiak, “Upgrading 1

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heavy oils with new catalyst technology,” Petroleum Technology Quarterly, Autumn 2004, pp. 41–47. 16 Rana, M. S., V. Samano, R. Ancheyta and J. A. I. Diaz, “ A review of recent advances on process technologies for upgrading of heavy oils and residua,” Fuel 86, 2007, pp. 1216–1231. 17 Yang, G., and R. A. Wang, “The supercritical fluid extractive fractionation and characterization of heavy oils and petroleum residua,” Journal of Petroleum Science and Engineering, Vol. 22, 1999, pp. 47–52. 18 Zhao, S., Z. Xu, Ch. Xu, K. H. Chung, and R. Wang, “Systematic characterization of petroleum residua based on SFEF,” Fuel 84, 2005, pp. 635–645. 19 Zhao, S., Kotlyar, L. S., Woods, J.R., Sparks, B. D., Gao, J., and Chung, K. H., “The Chemical Composition of Solubility Classes from Athabasca Bitumen Pitch Fractions,” Petroleum Science and Technology, Vol. 21, Nos. 1 & 2, pp. 183–199, 2003. 20 Zhao, S., R. Wang, and S. Lin, “High-Pressure Phase Behavior and Equilibria for Chinese Petroleum Residua and Light Hydrocarbon Systems. Part II,” Petroleum Science and Technology, Vol. 24, 2006, pp. 297–318. 21 Yui, S., and K. H. Chung, “Processing oil sands bitumen,” Oil & Gas Journal, April 23, 2001, pp. 46–52. 22 Zhao, S., et al, A benchmark assessment of residues: Comparison of Athabasca bitumen with conventional and heavy crudes,” Fuel 81, 2002, pp. 737–746. 23 Zhao, S., et al., “Molecular transformation of Athabasca bitumen end-cuts during coking and hydrocracking,” Fuel 80, 2001, pp. 1155–1163. 24 Chung, K. H., C. Xu, Y. Hu, and R. Wang,“Supercritical fluid extraction reveals resid properties,” Oil & Gas Journal, Jan. 20, 1997, Vol. 95, No. 3, pp. 66–68. 25 Zao, S., et al, “ A New Group Contribution Method for Estimating Boiling Point of Heavy Oil, Petroleum Science and Technology, Vol. 24, 2006, pp. 253–263. 26 Lui, C., C. Zhu, L. Jin, R. Shen, and W. Liang, “Step by step modeling for thermal reactivities and chemical compositions of vacuum residues and their SFEF asphalts,” Fuel Processing Technology, 59, 1999, pp. 51–67. 27 D. Stratiev, Z. Belchev, K. Kirilov, and P. Petkov, “How do feedstocks affect visbreaker operations?”, Hydrocarbon Processing, June 2008, pp. 105–112. 28 Stratiev, D. Z. Belchev, P. Petkov, and K. Kirilov, ”Investigation on residual fuel oil stability,” Oil Gas European Magazine, April 2008, pp. 199–203. 29 Flexicoking including fluid coking brochure, 2002, ExxonMobil Research and Engineering (in Russian). 30 Chung, K. H., Z. Xu, Z. Sun, X. Zhao, and, C. Xu, “Selective asphaltene removal from heavy oil,” Petroleum Technology Quarterly, Q4, pp. 99–105. 31 Panariti, N., A. Del Bianco, G. Del Piero, and M. Marchionna, “Petroleum residue upgrading with dispersed catalysts. Part 1. Catalysts activity and selectivity,” Applied Catalysis A: General 204, 2000, pp. 203–213. 32 Panariti, N., et al, ”Petroleum residue upgrading with dispersed catalysts. Part 2. Effect of operating conditions,” Applied Catalysis A: General 204, 2000, pp. 215–222. 33 Delbianco, A., S. Meli, N. Panariti, and G. Rispoli, “Upgrading unconventional oil resources with the EST process,” www.worldenergy.org/documents/ p001718.doc. 34 Kuo, C. J., “Effects of crude types on visbreaker conversion,” Oil and Gas Journal, Vol. 82 No. 39, 1984, pp. 100–103. NOMENCLATURE Ni Nickel V Vanadium Mo Molybdenum

Dicho Stratiev is an associate professor, PhD and executing duty of chief process engineer for Lukoil Neftochim Bourgas, Bulgaria. He is an author of more than 70 papers and has taken several positions in the research and production activities during his 17 years with the Lukoil Neftochim Bourgas, Bulgaria. Dr. Stratiev earned an MS degree in chemical engineering in organic chemistry and a PhD in oil refining at Bourgas University.

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Krasimir Petkov is the manager of technical and strategic development for Lukoil Neftochim Bourgas, Bulgaria. He has held various positions in research, maintenance and strategic planning during his 19 years with Lukoil Neftochim Bourgas, Bulgaria. Dr. Petkov is a mechanical engineer with an MS degree from Rouse Technical University and a PhD from the Technical University in Varna, Bulgaria.

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SINCE 1921... AND WE STILL LOVE IT For more than eighty years, we at Costacurta have been constantly and resolutely committed to the development and manufacture of special steel wire and plate components used in many different industrial processes. Every day at Costacurta, we work to improve the quality of our products and services and the safety of all our collaborators, paying ever-greater attention to the protection of the environment. Within the wide range of Costacurta products you will also find some, described below, that are used specifically in the oil, petrochemical and chemical industries: - RADIAL FLOW AND DOWN FLOW REACTOR INTERNALS; - GAS-LIQUID AND LIQUID-LIQUID SEPARATORS; - ARMOURING OF REFRACTORY, ANTI-ABRASIVE AND ANTI-CORROSIVE LININGS. For more information visit our website or contact the division 'C' components for the oil, petrochemical and chemical industries at tcrc@costacurta.it. Select 71 at www.HydrocarbonProcessing.com/RS

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ROTATING EQUIPMENT

Applying pumps with variable-speed drivers An evaluation carried out for a specific project demonstrated that the technology can result in lower operating and investment costs G. NARDOZI, Technip Italy, Rome, Italy

istorically, in the process industries, and in particular in the refining industries, pumps have used fixed-speed drivers and pump flow control was done by throttling control valve(s) at the pump discharge. Recently, use of pumps with variable-speed drivers (VSDs) is increasing because: • Cost of low-voltage VSDs has dropped • Improvements in VSD technology and increased reliability • Increasing interest in energy-saving issues. In the framework of a big project for a refinery located in northern Europe, an extensive study was carried out for the whole project to evaluate for which pumps applying a VSD was feasible and the impacts on the investment cost, energy savings and operating costs. The main findings of the study are presented in this article.

Use of pumps with VSDs. The typical pumping system is a pump running with a fixed-speed driver and flow through the

pump is regulated by a control valve(s) at the pump discharge (Fig. 1). The control scheme varies the flow through the pump by acting on the control valve(s). In Fig. 2, the pump and system curves relevant to a specific pumping system (pump and circuit) and the pump power curve are shown. When flow through the pump reduces (see H1 and H2 in Fig. 3) the pump differential head increases and the friction losses in the circuit reduce. The result is an increase in the pressure drop through the valve (see H 1-CV 1 and H2-CV 2 in Fig. 3). As a consequence the absorbed power by the pump also changes (see points 1 and 2 in Fig. 3). Use of a VSD allows adjusting the pump performance according to the process requirements by varying the pump speed (Fig. 4). For example, with reference to the scheme in Fig. 4, when the pump flow has to be reduced, the control scheme reduces

300

FC DH, m and w, kW

M FIG. 1

250

H1 CV 1

200 CV 2

150

100

DH (pump) kW DH circ. 200 m3/h DH circ. 150 m3/h

Fixed-speed pump system.

0 0

300 DH, m and w, kW

FIG. 3

Operating point

250 DH (pump) kW DH (circuit)

200 150

100

150

250 200 Q, m3/h

300

350

400

Fixed-speed pump curves.

DH control valve FC

DH friction

100

Absorbed power

50 0 0

FIG. 2

100

150

DH static head 250 300 200 Q, m3/h

Pump and system curves.

350

400

FIG. 4

VSD

Variable-speed pump system.

HYDROCARBON PROCESSING SEPTEMBER 2009

I 99

ROTATING EQUIPMENT TABLE 1. Use of pumps with VSDs 300

DH, m and w, kW

250 H3

200 H4

150

100

50 0 0

100

150

200 250 Q, m3/h

m (rpm 1) m (rpm 2) m (rpm 3) DH circ. 200 m3/h FIG. 5

300

350

400

kW (rpm 1) kW (rpm 2) kW (rpm 3) DH circ. 150 m3/h

VSD pump curves.

the pump speed (see H 3 and H4 in Fig. 5) to decrease the pump differential head thus balancing the head losses in the circuit. It is then possible to regulate the pump absorbed power according to the performance required by the process (see points 3 and 4 in Fig. 5) thus avoiding useless energy losses for friction through the control valve. Therefore, in general use of pumps with VSDs is worthwhile when the process conditions cause frequent and large variations on the pumping requirements (flow and head) such that the average power required by the pumping system is much lower than one corresponding to the pump running at rated speed. Another aspect to be considered is that pumping systems are normally oversized; in a fixed-speed pumping system, this results in having the pump delivering a flow at high differential head and high head loss through the control valve. With a VSD pumping system, the pump speed is adjusted according to the pumping requirements.

Advantages

Disadvantages

• Lower energy required (energy savings, lower operating cost)

• Inverter cost (especially for medium voltage)

• Avoid use of control valve at pump discharge (depending on application)

• Structural resonance (vibration problems). More likely to reach resonance condition due to speed variation

• Soft start capability (preventing overcurrent in the electrical network and pressure spikes in the circuit)

• Motor to be suitable for VSDs

• Possibility to switch from medium- to low-voltage motors

• Motor cooling (an independent cooling of motor at low speed could be required)

• Lower pump maintenance costs (lower speed/load on bearings and seals)

• More space required in the substation (for VSD installation)

• Improved pumping system reliability (reduced wear in bearings and seals)

• Overspeed (higher pump shutoff pressure)

• Improved electric motor restart situation after a common power loss • Lower noise from pump (normally operating below design speed) and control valve (less DP depending on the pumping system)

Control scheme for VSD pumps. During the study it was

For pumping systems with one discharge destination, in a lot of cases it was found feasible to consider the use of a VSD to regulate the pump flow as an alternative to the traditional flow control acting on the control valve at the pump discharge. By implementing the VSD and deleting the control valve at the pump discharge it is possible to eliminate the useless friction losses through the control valve thus achieving energy savings and operating cost reductions. When the control valve is required, use of a VSD is still feasible and in some cases could also be economical (see discussion below). For pumps with more than one discharge destination, it is not possible to avoid use of control valves at the pump discharge since they are needed to regulate the flow to each destination; however, use of VSD pumps is still feasible. In such cases, use of VSD pumps and implementing a proper control scheme makes possible varying the pump performance according to the process needs, thus reducing at minimum the head loss through the control valves. Therefore, when VSD use needs to be done in combination with flow control valve(s), the study evaluated the possibility of implementing a control scheme that controls the opening of the control valves at the pump discharge by acting on the pump speed. The control objective is to maintain the control valves at the pump discharge open at an optimal value that allows proper flow control while minimizing the energy losses for friction through the control valves. Practically, the controller controls the opening of the most open valve at the pump discharge and adjusts the pump speed to maintain the valve opening at the selected optimal value (controller setpoint in Fig. 6).

recognized that it would be useful to group all pumping systems subject to study in two categories: • VSD pumps with one discharge destination • VSD pumps with more than one discharge destination.

VSD pumps—impact on opex and capex. In general, use of VSDs on pumps reduces the energy required by the pumping system. Therefore, it reduces the operating costs. It must also be

Use of pumps with VSDs—advantages and disadvantages. In general, the use of VSDs on pumps is taken into

account to reduce the energy required for pumping, thus achieving energy savings and then lowering operating cost. On the other hand, the use of VSDs has some disadvantages: cost of inverter (high, especially for medium-voltage equipment), additional space required in the substation for installing VSDs and independent cooling for motor could be required. However, as far as the impact on the total investment cost, it should be noticed that in some cases the use of a VSD avoids installing a control valve at the pump discharge. In such cases, when the pump has a low-voltage (LV) motor, usually the additional cost for a VSD is lower than the cost savings due to deleting a control valve loop. In these cases use of a VSD can result also in a reduction in the investment cost. The main advantages and disadvantages of using pumps with VSDs are summarized in Table 1.

100

I SEPTEMBER 2009 HYDROCARBON PROCESSING

ROTATING EQUIPMENT TABLE 2. VSD study results FC

Pumping services in the project

n°

Total absorbed electric power (whole project)

15,000

6,200

gWh/y

Total absorbed electrical power by pumps (at rated cond.) FC

Estimate total yearly energy costs by pumps Pumping services evaluated in the VSD study

FIG. 6

VSD

Multiple discharge system.

noted that use of VSDs on pumps normally has a positive impact on the maintenance cost due to reduced wear of bearings and seals. The main economic issues from the study are presented. As far as the investment cost, in all cases involving low-voltage motors, the investment cost saving relevant to the control valve (including block and by-pass valves) was higher than the additional cost for applying the VSD. In case of medium-voltage motors, due to the high VSD cost, implementing a VSD resulted in a higher investment cost. In case of VSD pumps with more than one discharge destination, since in these cases deleting the control loop is not possible, use of a VSD was always a higher investment cost. For all cases in which use of a VSD gives lower investment cost

15 October 2009

•

n°

Estimate total yearly energy costs by pumps subject to study

gWh/y

29.5

Pumping services suggested with VSD • Total cost for VSD • Cost saving for deleting control valve • Yearly energy savings due to VSD implementation

n° k€ k€ gWh/y

26 1,220 462 7.3

Pumping services suggested with VSD and deletion of CV • Total cost for VSD • Cost saving for deleting control valve • Yearly energy savings due to VSD implementation

n° k€ k€ gWh/y

13 122 462 1.2

(other than lower operating cost), it was suggested that a VSD be implemented. For the other cases (higher investment cost), an economic analysis was carried out case-by-case to evaluate when it was advisable to use a VSD. For the scope of the study, a spreadsheet was developed to perform the economic analysis. With this tool, it is possible to calculate: • Yearly pump energy consumption for both cases, with and without a VSD • Energy savings with a VSD

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ROTATING EQUIPMENT • Operating cost reduction due to energy savings • Payback for the VSD. Data to be given as input are: • Pump operating conditions at minimum, normal and maximum flow • Percent of time that the pump works at each of the above conditions • Electric power cost • Delta investment cost between cases with and without a VSD.

■ In general, use of VSDs on

pump discharge and to control flow by regulating the pump speed. As a result, pumps reduces the energy the investment cost was reduced by about 460 k€. required by the pumping The total cost for all the VSDs sugsystem. Therefore, it reduces gested in the study was evaluated to be about 1,220 k€. In conclusion, for the the operating costs. It must whole project, implementing VSDs for also be noted that use of the pumping services defined in the study required an increase in the total VSDs on pumps normally investment cost of 760 k€ and provided has a positive impact on the a reduction on the operating cost of 365 Study results. The study was based k€/y, corresponding to a payback of about maintenance cost due to on an electric power cost of 0.05 €/kWh. two years. However, it must be noted that The main study results are summarized in reduced wear of bearings the payback is calculated on the total the Table 2. investment for all the VSDs suggested by and seals. The whole project included 64 pumpthe study. This figure is not intended to ing services. From a preliminary screening it was defined that be a “typical” value for applying VSDs because it can vary largely four pumps should have a VSD due to the particular process depending on the case. In fact, in the study for 13 services applyconditions, 37 services were included in the detailed VSD study. ing VSDs resulted in a reduction of the investment cost. For the other services it was early recognized that the VSD option was not attractive. Design considerations. From a technical point of view, use From the VSD study it was found that in 22 services use of of pumps with VSDs is generally feasible without major concerns; VSDs was technically feasible and economical. Therefore, for however, some aspects need to be taken into account in the pump/ these services use of a VSD was suggested. The estimated yearly motor design, in particular: energy savings was about 7.3 gWh/y corresponding to 365 k€/y Flow (and pump) control. In general, for a pump with one (0.05 €/kWh). discharge destination, it is possible to control the pump flow by In 13 cases it was suggested to delete the control valve at the regulating the pump speed instead of using the traditional control by a control valve. However, in some cases, the VSD control may not be good due to a very low turndown and/or the system curve shape. In some cases it could be worth having the flow control valve at the pump discharge and then control the valve opening by adjusting the pump speed to maintain low head loss through the valve. Overspeed and pump shutoff. For a VSD pump, in case the pump outlet is blocked, there is the possibility of having the pump running at shutoff conditions with the maximum speed allowed by the VSD. The result is a pump shutoff pressure higher than one with a fixed-speed pump. Therefore, the need for a higher design pressure for the equipment and lines at the pump The industry-standard software for instrumentation design discharge. The actual pump shutoff pressure value depends on the maximum pump speed allowed by the VSD. According to some Featuring more than 70 routines associated with control valves, rupture VSD manufacturers, the minimum recommended setting for the disks, flow elements, relief valves and process data calculations, overspeed trip should be 3% to provide adequate margin above the rated conditions. InstruCalcTM is one of the industry’s most popular desktop applications for Motor for VSDs. Pump motors with VSDs need to be speciinstrumentation calculations and analyses. fied as suitable for use with a VSD. Independent cooling for the Features: motor could be required depending on the required turndown (at Version 7.1 • Graphs for Control Valves and Flow Elements Now Available low motor speed self-cooling could not be sufficient). No major • Restriction devices cost impact was found for this reason. • Material yield strengths file Distance between motor and VSD. In case the distance • ISO orifice plate calculations have been updated to ISO 5167, 2003 between the motor and VSD is less than 200 meters there is sudden entrance and exit to the calculations. • Relieff VValve alve ve pprograms, ve rg ro no issue. For distances greater than 200 meters, installation of a filter could be required; cost impact is about 10–15% of the inverter cost. HP +1 (71 (713) 13) 3 520 520-4426 20 44 l +1 (800) 231-6275 l Software@GulfPub.com @Gu G lfPuub. b.co coo com www.GulfPub.com Giovanni Nardozi is a process manager with Technip Italy, Rome. He has 10 years of experience in refining. Mr. Nardozi worked on many basic design, FEED and detail designs for grassroots and revamping projects in the refining industry. He also developed many feasibility studies with support of LP models. Select 175 at www.HydrocarbonProcessing.com/RS 102

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LNG DEVELOPMENTS

Designing the LNG terminal of the future New requirements dictate operational flexibility of the design S. P. B. LEMMERS, Vopak LNG Holding BV, Rotterdam, The Netherlands

uture liquefied natural gas (LNG) receiving and regasification terminal designs must be more flexible due to: • Higher unloading rates • Increases in LNG carrier size (LNGC) • New operational modes • Volatility of LNG markets • Natural gas grid specifications.1,2 The conventional LNG terminal, with a single shipper, no longer fulfills the multiple-shipper LNG terminal requirements. Many variables impact LNG terminal design, particularly, larger LNG carrier sizes, higher unloading rates and new operational modes. New LNG terminal operational modes include simultaneous unloading of LNG carriers, back-loading and trans-shipment of LNG, and zero send-out modes.

• • • • •

Unloading and recirculation system LNG storage tanks LNG send-out system Vapor handling system Utilities, off sites and infrastructure.

Holding mode. If no LNG carrier is unloaded at the jetty, cryogenic conditions must be maintained in the unloading system to avoid thermal stresses. Therefore, LNG is circulated via the unloading line to the jetty head and back to the storage tanks or to the send-out system via the recirculation line. Boil-off gas (BOG) is generated due to heat in-leak into LNG storage tanks and process lines and pump energy input. This happens because the LNG is at its atmospheric boiling point. The BOG is compressed by the BOG compressors and routed to the BOG recondenser.

CONVENTIONAL LNG TERMINAL OPERATION

Unloading mode. An LNG carrier is

As shown in Fig. 1, an LNG terminal consists of six main systems: • Marine system (jetty, berth and unloading arms)

moored at the jetty and connected to the storage tank system through the unloading and vapor-return arms. The carrier cargo pumps transfer LNG to the storage tanks;

Vapor return line

BOG compressors

Fuel gas

Recirculation line

LNG unloading line Vapor return/ unloading arms LNG carrier

FIG. 1

Fuel gas Boil-off gas LP in-tank pumps

LNG storage tanks

An LNG terminal.

BOG recondenser LNG vaporizers

HP send-out pumps

BOG generation. BOG generation

takes place in either operation mode. It is caused by processing LNG at cryogenic conditions in an ambient environment. BOG generation during terminal operation is a result of: heat leaking into the LNG carrier; LNG storage tanks; process equipment; LNG lines and mechanical energy input by process equipment. BOG generation is a function of the absolute rates of the above phenomena. It changes significantly between the holding and unloading operation modes. FUTURE LNG TERMINAL DESIGNS

Future LNG terminals need to handle larger LNG carriers and higher unloading rates. These new designs must also have the flexibility to accommodate new operational modes.

Vapor return blower Knock-out drum

displaced vapors from the storage tanks are partially returned to the LNG carrier tanks (with a vapor deficit) and with the balance routed to the BOG compressors. During both operational modes, LNG is pumped continuously at varying rates from storage tanks by low-pressure (LP) pumps. LNG is mixed with BOG in the BOG recondenser and further pressurized by high-pressure (HP) pumps to the vaporizers for send-out into the natural gas (NG) pipeline system.

Users

Increased carrier sizes and unloading rates. Over the last decade, LNG

carrier capacity has increased from 120,000 m3 in the 1990s to 217,000 m3 (Q-Flex) with the new maximum of 267,000 m3 (Q-Max). LNG carriers are typically designed for a steady-state heat in-leak corresponding to a 0.15%/day product loss of nominal inventory. Result: More BOG is generated by the larger LNG carriers resulting in less vapor return during unloading. HYDROCARBON PROCESSING SEPTEMBER 2009

I 105

ĨĨŝĐŝĞŶĐǇ /ŵƉƌŽǀĞŵĞŶƚƐ

LNG DEVELOPMENTS TABLE 1. Flow to BOG increases with larger carrier sizes 120,000 m3 LNG carrier at 10,000 m3/hr From To BOG tanks To LNGC compressors

ŶĞƌŐǇ DĂŶĂŐĞŵĞŶƚ

Ŷ ŽŶůŝŶĞ ŶĞƌŐǇ tĂƚĐŚĚŽŐ ƚŚĂƚ ĂƐƐŝƐƚƐ ǇŽƵ ǁŝƚŚ ƚŚĞ ŽƉĞƌĂƚŝŽŶ ŽĨ ǇŽƵƌ ƵƚŝůŝƚŝĞƐ ƐǇƐƚĞŵƐ ;ƐƚĞĂŵ͕ ĨƵĞů͕ ĞůĞĐƚƌŝĐŝƚǇ͕ ĞƚĐ͘Ϳ ƚŽ ĂĐŚŝĞǀĞ ŵŝŶŝŵƵŵ ĐŽƐƚ ǁŝƚŚŝŶ ĞƋƵŝƉŵĞŶƚ ĂŶĚ ĞŵŝƐƐŝŽŶƐ ĐŽŶƐƚƌĂŝŶƚƐ͘ 'ĞŶĞƌĂƚĞƐ ĞŶĞƌŐǇͲƌĞůĂƚĞĚ <W/Ɛ ;<ĞǇ WĞƌĨŽƌŵĂŶĐĞ /ŶĚŝĐĂƚŽƌƐͿ͘ DŽŶŝƚŽƌƐ ŝŵďĂůĂŶĐĞƐ ĂůůŽǁŝŶŐ ǇŽƵ ƚŽ ŬĞĞƉ ƚƌĂĐŬ ŽĨ ůĞĂŬƐ͕ ŵĞĂƐƵƌĞŵĞŶƚ ŝƐƐƵĞƐ ĂŶĚ ĐŚĂŶŐĞƐ ŝŶ ƚŚĞ ĨŝĞůĚ͘ ĂŶ ďĞ ƵƐĞĚ ŽƉĞŶͲůŽŽƉ Žƌ ĐůŽƐĞĚͲůŽŽƉ͘

Pressure, kPa

121.5

117.9

120.2

121.5

118.3

120.2

Temperature, °C

–158.2

–133.6

–154.4

–158.2

–129.2

–154.4

Mass flow, kg/hr

26,896

14,026

12,870

26,896

11,588

15,308

Actual volume flow, m3/hr

12,696

8,416

6,367

12,696

7,156

7,573

TABLE 2. Unloading rates marginally affect BOG compressor capacity 267,000 m3 LNG carrier at 10,000 m3/hr 267,000 m3 LNG carrier at 12,500 m3/hr From To BOG From To BOG tanks To LNGC compressors tanks To LNGC compressors Pressure, kPa

121.5

118.5

120.2

121.5

116.7

119.2

Temperature, °C

–158.2

–126.2

–154.4

–158.2

–135.9

–155.0

Mass flow, kg/hr

26,896

10,321

16,575

32,152

15,296

16,856

Actual volume flow, m3/hr

12,697

6,504

8,200

15,178

9,116

8,363

TABLE 3. Example 1—Effect of simultaneous unloading Single LNG carrier unloading at 12,500 m3/hr From To BOG tanks To LNGC compressors

Two LNG carriers simultaneously unloading at 15,000 m3/hr From To BOG tanks To LNGC compressors

Pressure, kPa

121.5

116.7

119.2

–158.2

115.9

118.1

Temperature, °C

–158.2

–135.9

–155.0

–158.2

–133.8

–155.5

Mass flow, kg/hr

32,152

15,296

16,856

37,400

13,510

23,890

Actual volume flow, m3/hr

15,178

9,116

8,363

17,655

8,239

11,922

,ǇĚƌŽĐĂƌďŽŶ DĂŶĂŐĞŵĞŶƚ ,ǇĚƌŽĐĂƌďŽŶ DĂŶĂŐĞŵĞŶƚ

WƌŽĚƵĐƚŝŽŶͬzŝĞůĚ ĐĐŽƵŶƚŝŶŐ ƐǇƐƚĞŵ ƚŚĂƚ ďĞĐŽŵĞƐ ƚŚĞ ĨŽƵŶĚĂƚŝŽŶ ĨŽƌ ǇŽƵƌ ůŽƐƐ ĐŽŶƚƌŽů ŝŶŝƚŝĂƚŝǀĞƐ͘ /ƚ ĂƐƐŝƐƚƐ ǇŽƵ ǁŝƚŚ ǇŽƵƌ ĚĂŝůǇ ƐŝƚĞǁŝĚĞ ŵĂƐƐ ďĂůĂŶĐĞ ŽŶ Ă ƚĂŶŬͲďǇͲƚĂŶŬ ĂŶĚ ƵŶŝƚ ůĞǀĞů͘ ĚŝƐĐƌĞƚĞ ĞǀĞŶƚƐ ƐŝŵƵůĂƚŽƌ ŝƐ ĂůƐŽ ĂǀĂŝůĂďůĞ ƚŽ ĐŚĞĐŬ ƚŚĞ ĨĞĂƐŝďŝůŝƚǇ ŽĨ ǇŽƵƌ ŽƉĞƌĂƚŝŽŶƐ ƐĐŚĞĚƵůĞ ŝŶĐůƵĚŝŶŐ ǇŽƵƌ ĚŽĐŬƐ͕ ƚĂŶŬ ǇĂƌĚƐ͕ ƉƌŽĐĞƐƐ ƵŶŝƚƐ ĂŶĚ ƉŝƉĞůŝŶĞƐ͘

h^ ͗ нϭ ;ϮϴϭͿ ϴϮϵͲϯϯϮϮ ƵƌŽƉĞ͗ нϯϰ ;ϵϯͿ ϯϳϱͲϯϱϬϯ >ĂƚŝŶ ŵĞƌŝĐĂ͗ нϱϰ ;ϭϭͿ ϰϱϱϱͲϱϳϬϯ

ŝŶĨŽƵƐĂΛƐŽƚĞŝĐĂ͘ĐŽŵ ͖ ǁǁǁ͘ƐŽƚĞŝĐĂ͘ĐŽŵ Select 176 at www.HydrocarbonProcessing.com/RS

217,000 m3 LNG carrier at 10,000 m3/hr From To BOG tanks To LNGC compressors

TABLE 4. Example 2—Effect of simultaneous unloading Single LNG carrier unloading at 14,000 m3/hr From To BOG tanks To LNGC compressors

Two LNG carriers simultaneously unloading at 18,000 m3/hr From To BOG tanks To LNGC compressors

Pressure, kPa

121.5

115.3

118.6

121.5

112.9

116.5

Temperature, °C

–158.2

–139.3

–155.3

–158.2

–140.8

–155.9

Mass flow, kg/hr

35,308

18,304

17,005

43,746

19,483

24,263

Actual volume flow, m3/hr

16,668

10,751

8,463

20,651

11,557

12,237

This is illustrated in Table 1 (all other process design parameters being equal). From Table 1, BOG flow to BOG compressors increased 20% (6,367 m3/hr to 7,573 m3/hr) when the LNG carrier increased from 120,000 m3 to 217,000 m3. With larger LNG carrier sizes, unloading rates increase up to 14,000 m3/hr (from about 10,000 m3/hr for today’s carriers) with the Q-Max carrier. This affects vapor displacement in storage tanks and the BOG volume that must be returned to the carrier. The vapor-return temperature strongly influences the total vapor mass that is returned to the LNG carrier. At higher unloading rates, vapor return temperature decreases (because the heat-in leak into the

vapor return header is absorbed by a larger vapor return flow), resulting in a higher vapor return density and more vapor mass returned to the LNG carrier. Result: Less gas is sent to the BOG compressors. This effect stabilizes for higher unloading rates (see Fig. 2) (all other process design parameters remain equal). To demonstrate this stabilization effect at higher unloading rates for constant LNG carrier sizes, Table 2 summarizes the impact of raising unloading rates from 10,000 m3/ hr to 12,500 m3/hr. This 25% increase results in an insignificant 2% increase in the required BOG compressor capacity. Therefore, larger LNG carrier sizes increase the required BOG handling capac-

LNG DEVELOPMENTS

BOG, kg/hr

30,000 25,000 20,000 15,000 10,000 5,000 0 6,000 FIG. 2

8,000

10,000 12,000 14,000 Unloading rate, m3/hr

Simultaneous unloading operations. As shippers request more operational

flexibility, future LNG terminals may need to be designed for simultaneously unloading multiple LNG carriers. A direct, but expensive design approach to achieve a simultaneous unloading mode of operation is to duplicate the unloading and vapor-return system for all jetties and connect the jetties to specific LNG storage tanks and unload at double the unloading rate of a single LNG carrier. A cost-effective design approach uses a common vapor return and unloading system for all jetties and operates within the system’s hydraulic limitations accepting simultaneous unloading rates of less than double of a single LNG carrier. Both approaches impact the vapor handling system design capacity. Since the LNG volume doubles at the jetty if two LNG carriers are moored, more BOG must be handled by the vapor-handling system. Result: A significant increase in the BOG compressor capacity, the upstream knock-out facility and BOG recondenser. Consider two examples based on an LNG terminal with a common unloading and vapor return system: • Example 1—An LNG carrier size of 267,000 m3 unloads at 12,500 m3/hr. But two LNG carriers of the same size unload at a combined increased flowrate of 15,000 m3/hr (Table 3). • Example 2—An LNG carrier size of 267,000 m3 unloads at 14,000 m3/hr. But two LNG carriers of the same size unload at a combined increased flowrate of 18,000

FIG. 3

Thermal relief valve Strainer DP

Spacer

Check valve

Unloading valve

Typical unloading arm hook up.

m3/hr (Table 4). As shown in Tables 3 and 4, the unloading rates increase 20% and 28%, respectively. But the BOG compressor mass capacity increases by more than 40% in both examples. However, the BOG volume returned to the carriers decreases by 10% in Example 1 and increases by 6% in Example 2.

Mass flow to BOG compressors stabilizes at higher unloading flowrates.

ity, while higher unloading rates have only a minimal impact.

To unloading system

35,000

N2 to swivel joint and for arm purge

Emergency release system

40,000

0 –10 –20 –30 –40 –50 –60 –70 –80 –90 –100 –110 –120 –130 –140 –150 16,000

Quick connect disconnect coupler

LNG storage tanks Vapor return ﬂow BOG compressor capacity Vapor-return temperature

Temperature, °C

45,000

This 40% increase results in larger BOG compressor knock-out drums, BOG compressors and recondensers. It can be concluded that the increase in required BOG handling capacity is caused by the increase of LNG at the jetties during simultaneous unloading. Again, the impact of increased unloading rates is minimal. This is valid for terminals with a common vapor return and unloading system as well as for terminals

Select 177 at www.HydrocarbonProcessing.com/RS

107

LNG DEVELOPMENTS

Back-loading and trans-shipment operations. Due to volatility on the

BOG quality during zero send-out mode, MJ/Nm3

LNG spot market, some LNG terminals report back-loading and trans-shipment operations. The objective of an LNG backloading or trans-shipment operation is to fill a carrier with LNG from the LNG terminal or from another carrier. Partial filling of a carrier may be required for cool-down purposes, and the creation of an LNG heel. Complete filling of the carrier from terminal storage tanks is normally driven by financial opportunities on the LNG spot market. During back-loading, LNG is pumped from the LNG storage tanks to the LNG carrier by storage tank pumps. Since pumping capacity of the LNG storage tank pumps are smaller than the LNG carrier cargo pumps, the back-loading flowrates are lower than the unloading rates. Future LNG terminal designs need operational flexibility to safely do backloading and trans-shipments. The backloading and trans-shipment operational modes call for new design requirements. Hardware. The new operational modes require verification for flow restrictions (e.g., check valves, bidirectionality of process piping and interconnecting piping sizes) that exist in conventional import terminals. Fig. 3 shows a typical unloading arm hook up at an LNG terminal. An unloading valve, a check valve and a strainer are installed before the line connects to the unloading arm. The check valve prevents LNG flow to the carrier and potential loss of containment. For back-loading and transshipment operations, LNG 56 needs to flow into the carrier 54 (e.g. in the opposite direction 52 50 of normal unloading flow). The 48 check valve, therefore, should be 46 bypassed or a check valve with 44 removable internals that allows 42 for flow into the normally 40 undesired direction should be 38 installed. In addition, a bidirec36 tional strainer should be selected 34 and installed. 32 30 To control the back-loading/ 0.00 trans-shipment flow, flow controllers at the LP pumps and/or FIG. 4 at the unloading/recirculation system must be installed, or the 108

I SEPTEMBER 2009 HYDROCARBON PROCESSING

unloading valves in the process lines to the unloading arms need to be controllable at any position. Installing a check valve allowing bidirectional flow introduces additional operational risk. To avoid operational hazards, recommendations include: • Rely on strict operational procedures and supervision for these operations (e.g., a dedicated key-lock procedure should be in place for manipulating the internals of the check valve) • Develop functionality in the software that prevents the back-loading/trans-shipment flow path from opening when there is no requirement for these operations • During back-loading and trans-shipment modes, the LNG import terminal operates similarly to an export terminal. All relief scenarios valid for an LNG export terminal should be reviewed for applicability. Software. The operational requirements are not only reflected in the LNG terminal hardware but also in its software. Such software design includes process and safety control systems. The safety control system (SCS) consists of fire and gas, and emergency shutdown systems. Designs are based on process-control narratives and process safe guarding memoranda. When operational modes are added to the LNG terminal, these systems should be designed to ensure that the terminal operates in a controlled and safe manner. The check valve opening or the bypass can be considered hazardous. Permission to open can be interlocked in the SCS. A dedicated key- or password-protected function in the control room should be activated as permission to open the check valve or its bypass. Only when the key is activated, can the check valve or its bypass be opened to facilitate the back-loading and trans-ship-

TABLE 5. BOG generation during zero send-out operation Duty, kW

BOG, kg/hr

LNG storage tanks

400

2,820

Process lines

500

3,530

LP pump

580

982

6,930

Total

ment operations. The instrumented protective function shall prevent opening when the back-loading or trans-shipment signal is not active. When the LNG terminal operations remove the permissive for the back-loading or trans-shipment operation, the plant needs to go to its safe position automatically. Emergency shutdown-1 (ESD-1) (stop unloading or stop loading) and ESD-2 (release of an unloading or a loading arm via an emergency release system) have different initiators for the LNG import terminal and the LNG export terminal at the liquefaction plant. Also, the actions initiated by ESD-1 and ESD-2 will differ. A review of the initiators and actions should take place to establish the impact of back-loading and transshipment operations on safety. For example, an ESD-1 in an LNG export terminal is not initiated via high pressure or high level in LNG storage tanks. Also, with an ESD-1 in an LNG import terminal, the LNG carrier pumps are stopped. But, for an ESD-1 in an LNG export terminal, LP pumps in the LNG storage tanks are stopped. These differences should be carefully studied and implemented in the SCS so that the terminal has operational flexibility for the unloading, back-loading and trans-shipment operation. Impact on new design requirements. Back-loading and trans-shipment operations will impact the LNG terminal hardware and software design. Changing from an LNG import terminal operation to a temporary LNG export terminal operation requires process 9,000 line-up changes (check valve, 3 Wobbe, MJ/Nm 8,900 GCV, MJ/N33 bypasses, etc.), as well as changMass ﬂow, kg/hr 8,800 ing the functionality of the SCS for different operations. Such 8,700 actions introduce more risk 8,600 (with additional operational 8,500 complexity) to the LNG terminal operation and this should 8,400 be considered during design. 8,300 The SCS should be designed 8,200 so that operational mistakes are 8,100 avoided. Carrier back-loading 0.25 0.50 0.75 1.00 and trans-shipment operational N2 concentration in LNG, % modes should be engineered and BOG quality of N2 in LNG during zero send-out operation. designed similar to the conventional terminal operating modes. Mass ﬂow, kg/hr

with a duplicate vapor return and unloading system. Thus, for future LNG terminals, the simultaneous unloading mode becomes the case governing the vaporhandling system design.

LNG DEVELOPMENTS The engineering and design TABLE 6. Advantages and disadvantages of HP should involve surge analysis compression, BOG reliquefaction and power generation studies, HAZIDs, HAZOPs and HP BOG Power SIL classification. Aspect compression reliquefaction generation Zero send-out operation.

Capital expenditure

+/â&#x20AC;&#x201C;

â&#x20AC;&#x201C;

Operational expenditure

â&#x20AC;&#x201C;

+/â&#x20AC;&#x201C; + â&#x20AC;&#x201C; +/â&#x20AC;&#x201C; â&#x20AC;&#x201C;

Solutions for zero send-out operation. There are numerous technical solu-

tions for avoiding continuous emissions to the atmosphere during zero send-out mode. LP or HP BOG compression, BOG reliquefaction and power generation will be discussed. Terminals generally install only one technical solution. Hybrid solutions increase the capital and operational expenditure along with operational and maintenance complexity. BOG compression. The lowest cost solution is BOG compression via the LNG terminalâ&#x20AC;&#x2122;s BOG compressors to NG users at LP. If there are no LP users available, then

ion s

Sinc e

1942

In this operation, LNG is not â&#x20AC;&#x201C; + vaporized and, thus, not sent as Impact on gas quality +/â&#x20AC;&#x201C; +/â&#x20AC;&#x201C; NG to the NG pipeline system. Impact on During zero send-out mode, cryo- environmental permit +/â&#x20AC;&#x201C; + genic conditions need to be main- Operational flexibility tained in the terminal unloading Plot space +/â&#x20AC;&#x201C; + and recirculation system by recirculating LNG from the LP pump discharge to the BOG recondenser. LNG cold recirculation, runs at a minimum is then sent back to the storage tanks by a flowrate of 120 m 3 /hr with 55% effizero send-out recirculation line, jetty and ciency, and a differential head of 300 m, unloading lines. During this operation, then another 580 kg/hr is generated. Table mechanical energy input by LP pumps, as 5 summarizes total BOG generated during well as heat in-leak into the process lines zero send-out for a terminal with the previand LNG storage tanks is released as vapor ously mentioned tank sizes, process lines from the LNG storage tanks. and equipment. Eventually, the generated BOG would If the LNG terminal has a maximum be routed to the vent or flare by the LNG send-out capacity of 6 million tpy (MMtpy), storage-tank-pressure controller in zero then the generated BOG represents 1% of this send-out mode. Since venting or flaring on maximum. Another issue is that the generated a continuous basis is often not permitted BOG will significantly differ in calorific valfrom an environmental point of view, it also ues [Wobbe & Gross Caloric Valve (GCV)] represents a product loss. Technical solutions should be implemented to process the generated BOG during zero send-out mode. LNG storage tanks are traditionally designed for a maximum heat in-leak of 0.05%/day based on pure methane. An LNG terminal with two 160,000-m3 storage l tanks generates 2,820 kg/hr from its tanks. So ical m e h C e f Sa If the total heat in-leak of the process piping system, which is kept cold, is 500 kW, another 3,520 kg/hr is generated. Assuming that the LP pump is used for

as compared to LNG in the LNG terminal. The calorific value of the BOG is largely a function of nitrogen (N2) content in the LNG. N2 is more volatile than methane. The BOG generated is therefore much richer in N2 than bulk LNG in the LNG storage tank. This can result in BOG below NG grid specifications. Fig. 4 illustrates the BOG quality produced during zero sendout operation as a function of N2 content in the LNG.

CONNECTIONS FOR LNG

An LNG receiving and regasification terminal connects an intermittent process of a carrier unloading with a continuous process of LNG vaporization and gas transmission into a natural gas pipeline system. An LNG terminal receives LNG by carrier and stores it in a cryogenic liquid state. The storage temperature is approximately â&#x20AC;&#x201C;160Â°C and pressure is slightly above atmospheric. LNG from LNG storage tanks is pressurized by low-pressure in-tank LNG pumps, combined with recondensed boil-off gas. It is further pressurized by high-pressure LNG send-out pumps to pipeline pressure and sent to vaporizers for vaporization. Then it is finally sent as natural gas to end users.

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LNG DEVELOPMENTS the BOG should be compressed to NG pipeline pressure, resulting in an additional investment in HP compression. Due to the much higher compression ratio compared to the compression by the LNG terminal BOG compressors which only compress to recondenser pressure, the HP BOG compression system will require inter- and after-cooling with air, LNG or seawater. When compressing BOG into the NG pipeline system, LNG shippers are effectively still sending out. The feasibility of a BOG compression solution depends on the willingness of LNG shippers to deliver modest BOG quantities during zero send-out mode. Operational costs of BOG compression into the NG grid depends on the grid’s operating pressure and can vary between 0.15–0.25 kWhr/kg of BOG when the pipeline operates between approximately 60 barg to 80 barg. The quality of the BOG during zero send-out mode may pose a problem in terms of calorific value if the LNG is nitrogen-rich. To comply with the NG grid specifications, the calorific value of the BOG may need to be increased. This is the reciprocal problem that LNG terminals face when the LNG quality that needs to be sent

out is above the NG grid specification.1,2 In some cases, the NG grid operator may be able to accept below-specification BOG if it can be blended with richer NGs. If this is not possible, the terminal will have to either increase the BOG flow by vaporizing additional LNG and/or introduce liquefied petroleum gas (LPG) inline blending. The first requires installing small LNG vaporizers; the latter requires an LPG blending station with permanent LPG storage or allowance for an LPG truck connection. Small-scale reliquefaction. BOG can be reliquefied by several commercially available processes. Many are derived from the operation of small-scale BOG reliquefaction units on newer-generation carriers, including Q-Max and Q-Flex.3 These processes are closed-loop systems relying on a three-stage N 2 compression and a turbo-grid-expander cycle. The BOG reliquefaction solution will allow the terminal to process BOG without any LNG inventory loss, so the shippers do not have to deliver any NG quantity during the zero send-out mode. However, BOG reliquefaction, especially with sparing of the rotating equipment

Select 179 at www.HydrocarbonProcessing.com/RS 110

within the unit, is expensive in capital and operational terms. The higher the N2 content of the BOG, the more difficult it is to reliquify. Depending on the N2 content in the LNG, the BOG reliquefaction process can cost up to 1.35 kWhr/kg of BOG if the N2 content of the LNG increases to 1–1.2 mol%. If purging N2-rich NG from the BOG reliquefaction unit to outside the reliquefaction loop is allowed, the cost can decrease to 0.8 kWhr/kg–0.9 kWhr/kg. BOG reliquefaction will completely decouple the terminal from the NG grid. The small-scale reliquefaction solution completely removes the necessity to replenish LNG into the terminal to compensate for BOG losses, since all the BOG is reliquefied. Power generation. Power generation using gas engines, gas turbines or combined cycle is another solution to process BOG in zero send-out mode. However, it is capitalcost-intensive. Importing electricity from the public grid has proven to be economically more attractive than power generation by the LNG terminal itself in many cases. Due to the lack of economy-of-scale, power generation is unlikely to be justifiable as a solution for the zero send-out mode. Advantages and disadvantages. Assuming LP compression is not possible, HP BOG compression into the NG system is the most economical option concerning capital and operational costs. BOG reliquefaction, especially with sparing of rotating equipment is two to three times more expensive with regard to capital costs compared to HP compression. Its operational costs are four to five times higher than HP BOG generation. However, BOG reliquefaction eliminates the requirement for terminal shippers to sell their BOG during zero send-out operation, thus providing the highest operational flexibility for the terminal. Also, it does not suffer from NG below grid specification issues. Power generation is not economically attractive because of its high capital cost and operational returns. Table 6 summarizes the advantages and disadvantages of HP compression, BOG reliquefaction and power generation. Technical minimum send-out. The minimum send-out rate for conventional LNG terminals without a technical solution for zero send-out operation is determined by the LNG volume required to recondense the generated BOG in the BOG recondenser. Typical minimum send-out rates can be as high as 15% of maximum send-out for conventional LNG terminals in holding mode. If a technical solution for zero send-out mode

LNG DEVELOPMENTS is installed, then the minimum LNG send-out rate is effectively reduced to 0% or close to 0%. However, if LNG shippers that have invested in a zero send-out solution are allowed to nominate flowrates well below the minimum send-out, then the terminal faces technical limitations. These limitations include the minimum flowrate of LP and HP pumps, the BOG recondenser control valve inlet system, the vaporizer LNG inlet control valves and the turndown of metering runs. To lower the minimum send-out through the LNG terminal below the minimal send-out for conventional terminals, these limitations need to be resolved to enable the LNG terminal to ramp-up from a zero send-out mode to its maximum send-out flow in a virtual continuous manner. Recirculation of an LP pump to the LNG storage tank is undesirable but can be sustained for prolonged periods, since the technical solution for zero send-out can handle the BOG generated by this recycle operation. However, the HP pump cannot run on recycle for very long since it generates a significant BOG volume due to its high mechanical energy input. This BOG volume cannot be handled by the technical solution for zero send-out. If the HP pump recycles to the BOG recondenser, it will quickly bring the LNG to its saturation pressure. To lower the minimum flow recycle and thus the minimum send-out flow of the LNG terminal, an investment in either smaller LP and HP pumps or variable-speed-drive motors could be considered. For the BOG recondenser control valves and vaporizer inlet systems, parallel sets of control valves with varying sizes could be installed. These control valves should handle the increased turn-

down to virtually zero send-out of the terminal. The metering runs should be bypassed while a smaller metering run is installed in parallel for the increased turndown requirement. Conclusion. The additional requirements for operational flex-

ibility in multi-shipper terminals have generated new governing cases for design. The future LNG terminal design should provide the desired operational flexibility—in short, it should be able to do it all. HP ACKNOWLEDGMENT The author thanks his colleagues and Michiel Baerends from Fluor B.V. for reviewing the article before publication. 1 2 3

LITERATURE CITED Mak, J., D. Nielsen, D. Schulte and C. Graham, “LNG Flexibility,” Hydrocarbon Engineering, October 2003. Cho, J. H., J. J. Vazquez-Esparragoza, H. Kotzot, F. de la Vega and C. D. Durr, “Practical Processes,” LNG Industry, 2007. Begazo, C. D. T., E. C. Carvalho and J. B. SimõesMoreira, “Small-scale LNG plant technologies,” Hydrocarbon World, pp. 28–33, 2007.

Sander P. B. Lemmers has over 12 years’ experience in both technical and business facets of the global engineering, procurement and construction (EPC) industry. Mr. Lemmers’ technical competencies include design and engineering of LNG storage and loading facilities, LNG receiving and regasification terminals, floating LNG facilities, offshore oil and gas production and gas compression platforms, ethylene cracking complexes, gas purification and NGL recovery processes. His business competencies include knowledge of management information systems, management accounting, sales coordination, strategic business planning and business risk management. Mr. Lemmers is currently involved in the EPC phase of The Netherlands’ first LNG terminal.

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Showcase

u p s t re a m / m i d s t re a m / d o w n s t re a m

A Supplement to

The following companies are display advertisers in the Fall 2009 edition of the Upstream/Downstream Software Reference Guide. You can access the entire guide online at www.gulfpub.com/gpc/. This edition will also be available at many key industry meetings such as the World Oil & Hydrocarbon Processing Industry Forecast Meeting, Turbo Symposium, NPRA Q&A, SPE Annual, SEG, LAGCOE, IADC, ERTC Annual, Chem Show, API Fall Meeting, Daratech, ARC Forum, NAPE, Pump Users Symposium. CD-adapco is the leading global provider of fullspectrum engineering simulation (CAE) solutions for fluid flow, heat transfer and stress, including Computational Fluid Dynamics (CFD/CAE) flow, thermal, and stress software, CAD-embedded CFD options, and CAE consulting services and training. Its principal offices are in New York, London and Yokohama with subsidiary offices across the world. Select 403 at www.HydrocarbonProcessing.com/RS

Chemstations is a leading global supplier of process simulation software for the following process industries: oil & gas, petrochemicals, chemicals and fine chemicals, including pharmaceuticals. We currently offer several individually licensed, and tightly integrated, technologies to address the needs of the chemical engineer, whether doing new process design or working in the plant. Select 404 at www.HydrocarbonProcessing.com/RS

Codeware is the leading provider of software for the design and analysis of ASME Section VIII pressure vessels and heat exchangers. Since 1985, Codeware’s Engineers have focused exclusively on meeting the engineering software needs of designers and users of vessels and exchangers. Over 1,000 companies currently rely on Codeware products. Select 405 at www.HydrocarbonProcessing.com/RS

The Equity Engineering Group, Inc. is a recognized leader on aging infrastructure fixed equipment service and support for the oil and gas industry. Equity helps plants manage risk and improve profitability with cutting-edge software and consulting strategies that maximize equipment operational availability, control inspection costs and avoid costly shutdowns. Select 406 at www.HydrocarbonProcessing.com/RS

geoLOGIC systems ltd. provides well data and integrated software solutions to the energy and production industry. The company is an innovator in supplying data in more accessible and usable forms so clients can make better decisions - from the well head to senior levels of accounting and administration. Select 408 at www.HydrocarbonProcessing.com/RS

Gulf Publishing Company’s Software Division publishes and distributes more than 40 desktop applications designed specifically for the needs of the engineering community involved in the petroleum industry. Haverly Systems Inc. is an independent software company specializing in developing optimization-related products and services for over four decades. Their systems are used in over 50 countries by international and independent oil companies as well as petrochemical companies. The effectiveness of their work has long been recognized in the continued patronage and goodwill of our clients. Select 410 at www.HydrocarbonProcessing.com/RS

Heat Transfer Research Inc. (HTRI) is an international consortium founded in 1962 that conducts industrially relevant research and provides software tools for design, rating and simulation of process heat transfer equipment. HTRI also produces

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KBC Advanced Technologies is a leading independent consulting and technology services group, delivering improvements in business performance and asset value to owners and operators in the oil refining, petrochemical and other processing industries worldwide. KBC’s specialized software improves profitability through industry-leading models and simulation technology. Select 412 at www.HydrocarbonProcessing.com/RS

m:pro IT Consult is a project services and software products company which enables petroleum refining, petrochemical and other industries to achieve total integration of information sources and applications, from business systems, ERP and supply chain management through to plant information, production planning, scheduling and operations decision support. Select 414 at www.HydrocarbonProcessing.com/RS

M3 Technoloy is a leading provider of advanced asset scheduling and optimization solutions for oil refining, petrochemical, natural gas-LNG and terminal operating industries. M3’s SIMTO™ software captures eco-nomic opportunities and reduces the cost of managing complex facilities at the plant level, regional operating level and global enterprise level. Select 415 at www.HydrocarbonProcessing.com/RS

Merrick Systems provides integrated software solutions for oil and gas production operations. Since 1989, Merrick’s product suite has grown to include Best-of-Class applications for field data capture, production hydrocarbon accounting, plant allocations, regulatory reporting, production data management and production monitoring. Select 416 at www.HydrocarbonProcessing.com/RS

Soteica is a Process Engineering Software Company dedicated to the development, implementation, support and sustainability of its hydrocarbon and energy management applications, S-TMS and Visual MESA. For more than 20 years, Soteica has successfully deployed its applications in refineries and petrochemical plants throughout the Americas and Europe. Our customers have achieved millions of dollars in recurring benefits from the sustained use of our applications. Select 420 at www.HydrocarbonProcessing.com/RS

Spiral Software was set up in 1998 in response to an observed change in the needs of the evolving oil industry. The modern oil industry faces a growing challenge: while environmental specifications on products grow tighter each year, many of the remaining reservoirs offer relatively poor quality crude oil. In this context, understanding the detailed refining behaviour of crude oil is more critical than ever before. Spiral Software provides tools and services that enable our clients to make the best possible choices in trading and refining crude oil. Select 421 at www.HydrocarbonProcessing.com/RS

MANAGEMENT GUIDELINES

Effective standardization: Harnessing the power of your organization Applying these guidelines can effectively leverage economies-of-scale K. SMITH, KBC Advanced Technologies, Inc., Houston, Texas

Performance

hether you are in a strong economy or a weak economy—especially in a weak one—standardization across a multi-facility organization is good business practice. Standardization provides a mechanism for effectively leveraging the economies-of-scale associated with a large multifacility organization. It provides a basis for continuous improvement through a process of practice/standard evolution by allowing for better organizational learning. Small, single-facility organizations can also benefit from developing defined standards as they provide a basis for improving the efficiency and effectiveness of employees. At the same time, standards allow for better teamwork. The following explores the arguments for standardization and describes the framework for effective standards development.

Cognitive teams Cognitive individuals

Standardization defined. Standardization is the process of

developing, agreeing upon and implementing technical or program specifications, methods, processes and/or practices throughout an organization. When compared to the classic performance model (Fig. 1), standardization provides a mechanism for improving overall organizational performance by moving the entire organization toward a “cognitive team” operation mode. This helps an organization recognize the efficiencies and business value associated with alignment between related groups as well as providing a platform for improved communication opportunities. A classic performance in-depth analysis. A more

detailed look at this model, which defines the four classic levels of engagement for an organization, illustrates the need and value of standardization. Chaos is a common organizational state found within the process industry. It is characterized by a “not invented here” mentality—the basic premise is that every site’s situation is so unique that they warrant a different approach. While chaos allows for a significant level of individual freedom, it also drives the lowest level of performance, because it does not allow the sites to effectively learn from one another. Organizational discipline is a disciplined response, the first stage of standardization, and it is characterized by a blind adherence to policy. This operational state shows higher levels of performance based on the assumption that the standards reflect the most advanced knowledge and practices in the organization. However, this state is limited in performance by its lack of ability to effec-

Chaos

Organizational discipline Engagement level

FIG. 1

A classic performance model.

tively deal with unique or unexpected situations or requirements. Cognitive individuals are characterized by an “open-eyed” adherence to standards. This operational state is defined by individuals applying the standards in the most effective manner possible for their specific situation. Cognitive teams are characterized by a collaborative working environment based upon a common set of applied practices and standards. When implemented effectively, standardization institutionalizes certain organizational behaviors, allowing for more effective teamwork. This collaborative environment, when combined with a strong set of corporate standards, permits a more efficient evolution of an organization by creating an efficient and effective learning environment. Why standardization? The business practice of standardizing key work systems across an entire corporation is a common practice among industry-leading corporations. When executed correctly, this practice allows for true organizational learning, and it provides a basis in which effective practices are established and HYDROCARBON PROCESSING SEPTEMBER 2009

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MANAGEMENT GUIDELINES sustained over time. Those that argue against standardization feel that by holding everyone to the same set of guidelines and practices, the ability to optimize their approach to suit the situation is taken away. However, when implemented correctly as previously discussed, standards actually do the opposite. Standards provide a foundation by supporting common practices from a central group and a set of guidelines for efficiently and effectively tailoring practices, that are directly impacted by the idiosyncrasies of a particular site. Further, standardization minimizes the overall amount of effort required to achieve and sustain excellence at any one individual site by leveraging the entire corporation’s resources. It is important to note that it is incumbent upon the central group administering the standards not to place excessive controls on the system as they may unintentionally discourage local innovation. When done correctly, the controls should ensure a consistent and effective application of the standards to drive local innovation as part of the continuous improvement process. When standardizing across an entire corporation, the goals are to: • Leverage economies-of-scale provided by the corporation • Minimize liabilities by applying the same standards to all facilities • Optimize overall enterprise performance by applying bestknown practices across all sites • Drive continuous improvement by providing a platform for capturing and institutionalizing best practices. Effective standardization requirements. The first requirement of effective standardization is establishing the governing policies. These policies set the boundaries for desired organizational behaviors, while the standards themselves dictate or provide guidance on how to meet those policies. In simpler terms, policies provide guidance and direction, and standards define the compulsory practices and/or targets associated with those policies. Policies. Policy documents guide the behaviors of groups or individuals to achieve a desired outcome. When written properly, policy documents provide the framework for developing the work processes, management systems, supporting documentation and procedures associated with adhering to specific policies. Whether for an individual site or across an entire corporation, policies determine philosophical direction, while standards dictate the work processes, management systems, supporting documentation and procedures that individuals must adhere to for compliance with the policy. Practice standards. If standards documents are constructed cor-

rectly, they balance the value gained by standardization with the need for unique site approaches by defining three categories of practices: • Minimum safe operations standards are those practices that must be adhered to for safe operations. Once set, every site must follow these standards or face potential liabilities. • Business standards are the practices that the corporation encourages employees to follow to achieve desired business performance. These standards are largely mandatory. However, with corporate approval, a site or segment of the organization may choose, by exception, not to follow some or all of these standards due to operational issues or concerns. • Guidelines represent recommendations and/or suggestions for effective practices. Guidelines are typically used in practice areas that are largely governed or impacted by local site considerations. 114

I SEPTEMBER 2009 HYDROCARBON PROCESSING

Once an effective set of standards has been developed, the only way to gain full value from the effort is to implement the standards across the entire organization. Specifically, this means that each site must be held accountable for adherence to both the minimum and business standards as written. If exceptions to this adherence are required, they should be approved based on agreement between senior site and corporate management. These exceptions must be heavily scrutinized and subjected to a management-of-change process to ensure that the deviation from the standard does not pose an undue business or safety risk. In practical terms, sites have the following responsibilities with regard to corporate standards: • Adhere to both minimum and business standards. Deviation from these standards will only be allowed if required by a unique situation, and any deviation must have prior approval from a senior site manager and the corporate manager responsible for the standard. • Follow corporate guidelines as appropriate to ensure optimal performance against the standard objectives. • Provide input into creating corporate standards. • Provide feedback to the governing body of the standards document to ensure that the standards effectively support optimal operations. Any lessons learned are shared with the rest of the organization and incorporated into future updates to the standards document. Organizational standards provide the framework from which exceptional organizational performance can be achieved. Standardization is not as simple as documenting and rolling out standards. The process utilized to develop and implement those standards is crucial to success. When approached incorrectly, the implementation of organizational standards will be met with strong resistance and sometimes outright defiance. Employees may see the standards as a way of eliminating their ability to think and apply their expertise. This resistance often comes from a feeling by employees that they are being told that their performance to date has not been adequate and that someone else is going to tell them how to do their job better. However, when approached correctly, employees will more readily accept standards knowing that they were part of the development process, making implementation significantly easier and much more effective. So, “Why standardize?” The answer is simply that it makes good business sense. Then, “How can we go about standardization?” This is a much more difficult question; the answer is to ensure that a deliberate process is followed for the design, development, implementation and evaluation of standards that engages affected employees at each process stage. When standards are applied effectively, they can transform an organization into an industry-leading business entity. HP

Kevin Smith is an executive vice president at KBC Advanced Technologies, Inc. He specializes in human capital solutions for the process industries with an emphasis on the performance of operations and maintenance personnel and their direct supervision. Mr Smith also works with plant management teams to align their organizations with company strategy to improve overall results. He earned a BS degree in chemical engineering from the University of Tennessee-Knoxville.

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ENGINEERING CASE HISTORIES

Case 52: Problems with a blocked-in centrifugal pump The potential for overheating is one of many concerns T. SOFRONAS, Consulting Engineer, Houston, Texas

ver the years I’ve analyzed several centrifugal pump failures that were the result of a blocked-in discharge. The cause was usually a procedural or initial design error and was corrected after the damage was done. Cracked mechanical seals and vibration occurred in some instances and a total seizing of the pump in others. Most pump books1 recommend not to run pumps blocked in. When a centrifugal pump is in a no-flow condition, it is still developing horsepower to the trapped liquid. Roughly the noflow horsepower is 40% to 60% of full flow. This power has to go somewhere and much of it goes into heating the confined liquid in the casing. An approximation of the liquid temperature rise in the casing of a blocked-in centrifugal pump can be calculated from the following equation: T = 81HPNF tmin / D 3 C , °F

where: ΔT HPNF tmin D ␳ C

= = = = = =

Liquid temperature rise in pump casing, °F No flow or blocked-in horsepower Time pump operates at blocked-in condition, minutes Impeller diameter, ft Liquid density, lb/ft3 Specific heat of liquid, Btu/lb-°F

This is just a rearrangement of the specific heat equation.2 Instead of trying to determine the weight of liquid being heated, the pump casing is considered to be spherical. Since the piping contains liquid too and that by using a sphere we only need to consider the impeller size, this approximation seems adequate for educational purposes. Consider the example of a 100 hp-centrifugal water pump with a one-foot-diameter impeller, using a 50% average blocked-in horsepower. It is blocked-in for two minutes to switch remote pumps.

T = 81 50 2 / 13 62.4 1 = 130°F The water trapped in the casing would rise 130° F which may or may not cause problems depending on the pump. What is important is that there are five variables in this simple equation. Just saying a pump can be run for some time with no flow would be irresponsible. As can be seen by the equation, a pump with a low no-flow horsepower and a large casing probably won’t seize, but a high-energy pump with a smaller volume might. Hydrocarbons would have a larger temperature rise than water since they

■ ... if a pump must be operated blocked

in for any length of time the safest approach is to discuss this with the pump manufacturer. It has experience in determining how long its pump can be operated in this condition or if a by-pass arrangement is required. have smaller ␳ and C values. Vaporization in the casing and rundry conditions would be a concern. Eventually the heat is dissipated through the casing, piping and shafting to the atmosphere and the temperature becomes steady state and doesn’t keep increasing, which isn’t considered here. This model only considers a blocked-in discharge for a short time and is based on the casing being filled with a liquid. Remember that this article only applies to a radial-flow centrifugal pump, not a mixed-flow, axial-flow or other type pump since they can have completely different blocked-in characteristics. Starting up with a slightly cracked discharge valve is standard practice on many low- and medium-specific-speed pumps.3 However, if a pump must be operated blocked in for any length of time the safest approach is to discuss this with the pump manufacturer. It has experience in determining how long its pump can be operated in this condition or if a by-pass arrangement is required. HP 1 2

LITERATURE CITED Karassik, I. J., Centrifugal Pump Clinic, p. 334, ISBN: 0-8247-1016-9, Marcel Dekker, Inc. Sofronas, A., Analytical Troubleshooting of Process Machinery and Pressure Vessels: Including Real-World Case Studies, p. 153, ISBN: 0-471-73211-7, John Wiley & Sons. Bloch, H. P. and A. R. Budris, Pump User’s Handbook Life Extension, p. 375, ISBN 0-88173-452-7, Fairmount Press, Inc.

Dr. Tony Sofronas, P.E., was worldwide lead mechanical engineer for ExxonMobil before his retirement. The case studies are from companies the writer has consulted for. Information on his books, seminars and consulting are available at the Website http://www.mechanicalengineeringhelp.com. HYDROCARBON PROCESSING SEPTEMBER 2009

I 117

HPI MARKETPLACE

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SURPLUS GAS PROCESSING/REFINING EQUIPMENT NGL/LPG PLANTS: 10 â&#x20AC;&#x201C; 600 MMCFD AMINE PLANTS: 60 â&#x20AC;&#x201C; 5,000 GPM SULFUR PLANTS: 10 â&#x20AC;&#x201C; 1,200 TPD FRACTIONATION: 1,000 â&#x20AC;&#x201C; 15,000 BPD HELIUM RECOVERY: 75 & 80 MMCFD NITROGEN REJECTION: 25 â&#x20AC;&#x201C; 80 MMCFD ALSO OTHER REFINING UNITS We offer engineered surplus equipment solutions.

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Mesh Mist Eliminators handle most scrubbing, distillation, and absorption and glycol applications. AMISTCO offers a wide range of mesh to separate liquids from vapor streams at efficiencies exceeding 99.9% of one micron. 0(6+ 0,67 (/,0,1$7256 Double Pocket Vane Type Mist Eliminators for more efficient KLJK SUHVVXUH VHSDUDWLRQV RI 8 microns) or space tight applications such as offshore platforms and those found in oil and gas exploration. A wide range of materials and blade spacing are available as well as a full line of standard Vane (chevron) Type Mist Eliminators. '28%/( 32&.(7 9$1(

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CA Co PE-O mp PE lian N t! HTRI Xchanger SuiteÂŽ â&#x20AC;&#x201C; an integrated, easy-to-use suite of tools that delivers accurate design calculations for â&#x20AC;˘ shell-and-tube heat exchangers â&#x20AC;˘ jacketed-pipe heat exchangers â&#x20AC;˘ hairpin heat exchangers â&#x20AC;˘ plate-and-frame heat exchangers â&#x20AC;˘ spiral plate heat exchangers

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2 Greenway Plaza, Suite 1020 Houston, Texas, 77046 USA Houston, Texas 77252-2608 USA Phone: +1 (713) 529-4301, Fax: +1 (713) 520-4433 www.HydrocarbonProcessing.com Bill Wageneck, Publisher

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LA, OK, TX Josh Mayer 5930 Royal Lane, Suite 201, Dallas, TX 75230 Phone: +1 (972) 816-6745, Fax: +1 (972) 767-4442 E-mail: Josh.Mayer@GulfPub.com

CT, MA, ME, NH, NJ, NY, PA, RI, VT, EASTERN CANADA Merrie Lynch 20 Park Plaza, Suite 517, Boston, MA 02116 Phone: +1 (617) 357-8190, Fax: +1 (617) 357-8194 E-mail: Merrie.Lynch@GulfPub.com

AL, AR, DC, DE, FL, GA, IN, KY, OH, MD, MO, MI, MS, NC, SC, TN, TX, VA, WV Lee Nichols 2 Greenway Plaza, Suite 1020, Houston, Texas, 77046 Phone: +1 (713) 525-4626, Fax: +1 (713) 525-4631 E-mail: Lee.Nichols@GulfPub.com

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FRANCE, SPAIN, PORTUGAL, SOUTHERN BELGIUM, LUXEMBOURG, SWITZERLAND, GERMANY, AUSTRIA, TURKEY Catherine Watkins Ohana, 30 rue Paul Vaillant Couturier 78114 Magny-les-Hameaux, France Tél.: +33 (0)1 30 47 92 51, Fax: +33 (0)1 30 47 92 40 E-mail: Watkins@GulfPub.com

AUSTRALIA – Perth Brian Arnold Phone: +61 (8) 9332-9839, Fax: +61 (8) 9313-6442 E-mail: Australia@GulfPub.com

ITALY, EASTERN EUROPE Fabio Potestá Mediapoint & Communications SRL Corte Lambruschini - Corso Buenos Aires, 8 5° Piano - Interno 7 16129 Genova - Italy Phone: +39 (010) 570-4948, Fax: +39 (010) 553-0088 E-mail: Fabio.Potesta@GulfPub.com RUSSIA/FSU Lilia Fedotova Anik International & Co. Ltd. 10/2 Build. 1,B. Kharitonyevskii Lane 103062 Moscow, Russia Phone: +7 (495) 628-10-333 E-mail: Lilia.Fedotova@GulfPub.com UNITED KINGDOM/SCANDINAVIA, NORTHERN BELGIUM, THE NETHERLANDS Peter Gilmore 57 Keyes House Dolphin Square London SW1V 3NA United Kingdom Phone: +44 (0) 20 7834 5559, Fax: +44 (0) 20 7834 0600 E-mail: Peter.Gilmore@GulfPub.com

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CLASSIFIED ADVERTISING AND REPRINTS Classified e-mail: Lee.Nichols@GulfPub.com Reprints e-mail: EditorialReprints@GulfPub.com

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FREE Product and Service Information — SEPTEMBER 2009 HOW TO USE THE INDEX: The FIRST NUMBER after the company name is the page on which an This information must be proadvertisement appears. The SECOND NUMBER, appearing in parentheses, after the company name, vided to process your request: is the READER SERVICE NUMBER. There are several ways readers can obtain information: PRIMARY DIVISION OF INDUSTRY 1. The quickest way to request information from an advertiser or about an editorial item is to go to www. HydrocarbonProcessing.com/RS. If you follow the instructions on the screen your request will be forwarded for immediate action. 2. Go online to the advertiser's Website listed below. 3. Circle the Reader Service Number below and fax this page to +1 (416) 620-9790. Include your name, company, complete address, phone number, fax number and e-mail address, and check the box on the right for your division of industry and job title. Name ________________________________________________________

Company ________________________________________________________

Address ______________________________________________________

City/State/Zip ____________________________________________________

Country ______________________________________________________

Phone No. _______________________________________________________

FAX No. ______________________________________________________

e-mail ___________________________________________________________

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

(check one only): A B C F G H J P

䊐-Refining Company 䊐-Petrochemical Co. 䊐-Gas Processing Co. 䊐-Equipment Manufacturer 䊐-Supply Company 䊐-Service Company 䊐-Chemical Co. 䊐-Engrg./Construction Co.

JOB FUNCTION (check one only): B E F G I J

䊐-Company Official, Manager 䊐-Engineer or Consultant 䊐-Supt. or Asst. 䊐-Foreman or Asst. 䊐-Chemist 䊐-Purchasing Agt.

ADVERTISERS in this issue of HYDROCARBON PROCESSING Company Website

Page

RS#

Alstom Power, Inc. . . . . . . . . . . . . . . . . . 78

(168)

www.info.hotims.com/26022-168

APEX Engineering Products Corp . . . . . 109

(178) (95) (53) (83)

www.info.hotims.com/26022-83

Belco Technologies Corp . . . . . . . . . . . . 39

(64)

www.info.hotims.com/26022-64

Bently Pressurized Bearing Co . . . . . . . 107

(177) (77) (179) (55) (84)

(165) (112) (152) (73)

LA Turbine . . . . . . . . . . . . . . . . . . . . . . . . 4

(167)

Linde Process Plants . . . . . . . . . . . . . . . 22

(93)

Lurgi GmbH . . . . . . . . . . . . . . . . . . . . . 30

(59)

M3 Technology . . . . . . . . . . . . . . . . . . . 38

(58)

MBI Leasing LLC . . . . . . . . . . . . . . . . . . 20

www.info.hotims.com/26022-174

(67)

Sabin Metals Corporation . . . . . . . . . . . 61

(160)

Selas Fluid Processing Corp . . . . . . . . . . 56

Mustang Engineering . . . . . . . . . . . . . . 73

(174)

NATCO . . . . . . . . . . . . . . . . . . . . . . . . . 50

(157)

www.info.hotims.com/26022-157

(56)

www.info.hotims.com/26022-56

(78)

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(105)

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Soteica LLC . . . . . . . . . . . . . . . . . . . . . 106

(82) (89) (96) (97) (151) (79) (92) (155)

www.info.hotims.com/26022-162

Spectro Analytical Instruments . . . . . . . . 54

(86) (75)

www.info.hotims.com/26022-75

(68)

(159)

www.info.hotims.com/26022-159

Spraying Systems Co . . . . . . . . . . . . . . . 10

(62)

www.info.hotims.com/26022-62

Süd-Chemie . . . . . . . . . . . . . . . . . . . . . 25

(70)

www.info.hotims.com/26022-70

Sulzer Chemtech Ltd . . . . . . . . . . . . . . . 41

(156)

www.info.hotims.com/26022-156

Sulzer Chemtech, USA Inc.. . . . . . . . . . . 28

(153)

www.info.hotims.com/26022-153

Swagelok Co. . . . . . . . . . . . . . . . . . . . . 32

(63)

www.info.hotims.com/26022-63

Swagelok Co. . . . . . . . . . . . . . . . . . . . 6-7

(65)

www.info.hotims.com/26022-65

T.D. Williamson . . . . . . . . . . . . . . . . . . 123

(66)

www.info.hotims.com/26022-66

(90)

www.info.hotims.com/26022-90

Thermo Fisher Scientific . . . . . . . . . . . . . 83 (99)

(176)

www.info.hotims.com/26022-176

Thermo Fisher Scientific . . . . . . . . . . . . . 22 (100)

www.info.hotims.com/26022-86

www.info.hotims.com/26022-68

(161)

www.info.hotims.com/26022-161

(80)

www.info.hotims.com/26022-99

(180)

(76)

SNC-Lavalin Engineers & Construction Inc.64 (162)

www.info.hotims.com/26022-100

Merichem . . . . . . . . . . . . . . . . . . . . . . . 69

(164)

(98)

www.info.hotims.com/26022-155

www.info.hotims.com/26022-180

GPC Events - World Oil Awards . . . . . 101

Rentech Boiler System . . . . . . . . . . . . . . . 2

www.info.hotims.com/26022-92

www.info.hotims.com/26022-171

GPC Events - WGLC. . . . . . . . . . . . . . 111

(81)

www.info.hotims.com/26022-79

(171)

(163)

www.info.hotims.com/26022-164

Prosim . . . . . . . . . . . . . . . . . . . . . . . . . 49

www.info.hotims.com/26022-151

MBI Global . . . . . . . . . . . . . . . . . . . . . . 20

(154)

www.info.hotims.com/26022-163

(158)

www.info.hotims.com/26022-97

www.info.hotims.com/26022-58

Gulf Publishing Company Boxscore Data Base . . . . . . . . . . . . . . 103 Circulation . . . . . . . . . . . . . . . . . . . . . 90

KTI Corporation . . . . . . . . . . . . . . . . . . . 45

Paratherm Corporation . . . . . . . . . . . . . 66

Prosernat . . . . . . . . . . . . . . . . . . . . . . . 62

www.info.hotims.com/26022-96

www.info.hotims.com/26022-59

Global Technology Forum. . . . . . . . . . . 115

KTI Corporation . . . . . . . . . . . . . . . . . . . 42

Paharpur Cooling Towers, Ltd. . . . . . . . . 34

(169)

www.info.hotims.com/26022-89

www.info.hotims.com/26022-93

Gas Technology Products LLC. . . . . . . . . 65

KBR . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

(102)

www.info.hotims.com/26022-76

www.info.hotims.com/26022-82

www.info.hotims.com/26022-167

Flexitallic LP . . . . . . . . . . . . . . . . . . . . . . 5

Johnson Matthey Catalysts . . . . . . . . . . 37

NPRA . . . . . . . . . . . . . . . . . . . . . . . . . 116

Process Consulting Services . . . . . . . . . 12

www.info.hotims.com/26022-80

www.info.hotims.com/26022-73

FlexElement Texas Inc. . . . . . . . . . . . . . . 78

John M Campbell & Co . . . . . . . . . . . . . 58

KBC Advanced Technologies Inc . . . . . . . 16

www.info.hotims.com/26022-152

Feeney Wireless . . . . . . . . . . . . . . . . . . . 56

ITT Goulds . . . . . . . . . . . . . . . . . . . . . . 14

(60)

www.info.hotims.com/26022-112

Dyna-Therm . . . . . . . . . . . . . . . . . . . . . 24

ISA . . . . . . . . . . . . . . . . . . . . . . . . . . . 104

Johnson Screens Europe . . . . . . . . . . . . 35

www.info.hotims.com/26022-165

DuPont Vespel . . . . . . . . . . . . . . . . . . . . 18

INOVx . . . . . . . . . . . . . . . . . . . . . . . . . . 52

RS#

Petro-Canada Lubricants . . . . . . . . . . . . 67 (69)

www.info.hotims.com/26022-69

HPI Marketplace . . . . . . . . . . . . . 118-119 Idrojet . . . . . . . . . . . . . . . . . . . . . . . . . . 79

(71)

www.info.hotims.com/26022-60

DMG World Media . . . . . . . . . . . . . . . . 70

Software Reference . . . . . . . . . . . . . . 112 Haldor Topsøe A/S . . . . . . . . . . . . . . . . . 77

www.info.hotims.com/26022-98

www.info.hotims.com/26022-71

Criterion Catalyst & Technologies, L.P. . . 92

(170)

www.info.hotims.com/26022-160

www.info.hotims.com/26022-84

Costacurta SpA Vico . . . . . . . . . . . . . . . 97

HP Webcast. . . . . . . . . . . . . . . . . 86, 120

Page

www.info.hotims.com/26022-154

www.info.hotims.com/26022-67

www.info.hotims.com/26022-55

CB&I . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

(175)

www.info.hotims.com/26022-81

www.info.hotims.com/26022-179

Burckhardt Compression Ag . . . . . . . . . 32

GPC SVB . . . . . . . . . . . . . . . . . . . . . 102

Company Website

www.info.hotims.com/26022-102

www.info.hotims.com/26022-158

www.info.hotims.com/26022-77

Buchen-ICS GmbH. . . . . . . . . . . . . . . . 110

(173)

www.info.hotims.com/26022-169

www.info.hotims.com/26022-177

BME Global Limited. . . . . . . . . . . . . . . . 98

GPC SVB . . . . . . . . . . . . . . . . . . . . . . . 96

www.info.hotims.com/26022-170

www.info.hotims.com/26022-53

BASF Catalysts LLC . . . . . . . . . . . . . . . . . 8

RS#

www.info.hotims.com/26022-175

www.info.hotims.com/26022-95

Axens . . . . . . . . . . . . . . . . . . . . . . . . . 124

Page

www.info.hotims.com/26022-173

www.info.hotims.com/26022-178

Ashland Inc . . . . . . . . . . . . . . . . . . . . . . 59

Company Website

(115)

www.info.hotims.com/26022-115

Tray-Tec Inc. . . . . . . . . . . . . . . . . . . . . . 91

(172)

www.info.hotims.com/26022-172

Treadlite Group . . . . . . . . . . . . . . . . . . . 74

(166)

www.info.hotims.com/26022-166

UOP LLC . . . . . . . . . . . . . . . . . . . . . . . . 63 Veolia Environment . . . . . . . . . . . . . . . . 29

(85)

www.info.hotims.com/26022-85

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121

HPIN CONTROL Y. ZAK FRIEDMAN, CONTRIBUTING EDITOR Zak@petrocontrol.com

Temperature points on main fractionators Main fractionators are distillation columns that handle wide boiling curve feeds, cutting it into several products. Almost every major refinery unit has such a column, all with similar design features, though some are easier to operate than others, and “easier to operate” translates to more optimal operation and fewer incidents. From my advanced process control (APC) and inferential control perspectives, units that are easier to operate naturally lend themselves to better inferential modeling and better APC. This editorial attempts to highlight the differences, and it concludes that a small investment in instrumentation can substantially improve main fractionator performance. To fit the space we cover only one typical style of main fractionator design (Fig. 1). Hot partially vaporized feed enters the flash zone. The vapor portion includes all distillate products plus some additional evaporated material called overflash. Below the flash zone is a steam stripping section for stripping absorbed distillates off the bottom residue product. Above the flash zone, vapor is condensed in stages by cooling circuits called pumparounds, and side streams are proportionally drawn, stripped in side strippers and become middle distillate products. In the style of Fig. 1 the draws are partial draws, meaning—excess internal reflux not drawn out flows down the column. For simplicity, Fig. 1 does not show stripping steam, but it shows all other control handles: top temperature controller, side product flow controllers and pumparound flows. What’s missing? What this control structure misses is the fact that the operator does not know the content of middle distillates in the feed. If too much side products are taken, they would go off specification. Worse yet, the section of column immediately above the flash zone can run dry, resulting in contamination of heavy diesel by entrainment. On the other hand, if side draws do not take all of the middle distillate material available there are economic penalties. At steady state operation that is merely an inconvenience, forcing the operator to rely heavily on lab tests, but upon disturbances, such as crude switches, coke drum switches, operational mode changes, etc., the operator is in the dark. Danger of contaminating the lowest side draw makes overflash perhaps the single most important control variable, only that most important variable is unmeasured. Of the attempts to measure overflash by orifice meters the rate of success stands at about 10%. Temperature indicators typically available on main fractionators are shown in Fig. 1 in purple: cooling circuits, draws and flash zone. But draw temperatures are bubble points, not so much related to the product 90% point, but rather to the initial boiling point. Farther, draws are saturated with light materials, which skew the interpretation of temperature readings. Pumparound heat duty calculations might be useful for engineers but they do not provide inference of product qualities. To use these available

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indicators in a productive way one needs to employ an inference package connecting all of this information together and digesting it into product quality inferences. That implies implementing APC, and even then, model repeatability improves if it does not have to rely on draw temperatures. Best temperature points. Temperature points that could help the operator handle fractionator disturbances should be located in the vapor space of trays immediately below the draws, and are shown in Fig. 1 in orange. These are dew point indicators with much cleaner interpretation. Dew points are rough inferences of the 90% points we are trying to control, and as opposed to bubble points are less influenced by light material flowing across the tray. Especially the one temperature point below heavy diesel is of much value. In addition to this temperature being a rudimentary inference of heavy diesel 90% point, the temperature difference between the flash zone and vapor below heavy diesel is rough inference of overflash, and being able to control overflash is mandatory for good operation during disturbance. I hope equipment designers read this and take notice. HP

The author is a principal consultant in advanced process control and online optimization with Petrocontrol. He specializes in the use of first-principles models for inferential process control and has developed a number of distillation and reactor models. Dr. Friedman’s experience spans over 30 years in the hydrocarbon industry, working with Exxon Research and Engineering, KBC Advanced Technology and since 1992 with Petrocontrol. He holds a BS degree from the Israel Institute of Technology (Technion) and a PhD degree from Purdue University.

HYDROCARBON PROCESSING SEPTEMBER 2009

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CONTENTS Advertising Index . . . . . . . . . . . . . . . . . . . . . . . . . . .38â&#x20AC;&#x201C;39

BUSINESS MANAGEMENT

P.O. Box 2608 Houston, Texas 77252-2608 Phone: +1 (713) 529-4301 Fax: +1 (713) 520-4433

Visit the Software Reference Website: www.gulfpub.com/gpc/

Planning, Scheduling and Blending . . . . . . . . . . . . . . . .18 Plant Lifecycle and Performance Monitoring . . . . . . . . .21 Predictive Maintenance and Repair . . . . . . . . . . . . . . . .22

Budgeting, Capital Allocation & Planning . . . . . . . . . . . .4 Process Engineering and Simulation . . . . . . . . . . . . . . . .23 Business Integration . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4 Production/Yield Accounting . . . . . . . . . . . . . . . . . . . . .25 Enterprise Operations Management . . . . . . . . . . . . . . . . .4 Land and Leasing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5 Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6 Plant Lifecycle and Performance Monitoring . . . . . . . . . .6

Refining, Petrochemical and Gas Processing . . . . . . . . . .26 SIS/Safety Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . .29 Training . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .29

MIDSTREAM

Production / Yield Accounting . . . . . . . . . . . . . . . . . . . . .7 Pipeline Engineering and Fluid Flow . . . . . . . . . . . . . . .31 Regulatory Compliance . . . . . . . . . . . . . . . . . . . . . . . . . .8 Risk Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8

DOWNSTREAM Asset Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9 Alarm Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9

UPSTREAM Asset Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . .31 Data Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . .31 Data Visualization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .32 Design, Construction and Engineering. . . . . . . . . . . . . .32 Drilling Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . .33

Design, Construction and Engineering . . . . . . . . . . . . .10 Dynamic Simulation and Optimization . . . . . . . . . . . . .12 Economic Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . .13

Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .34 Field Data Capture . . . . . . . . . . . . . . . . . . . . . . . . . . . . .34 Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .34

Energy Management . . . . . . . . . . . . . . . . . . . . . . . . . . .14 Process Engineering and Simulation . . . . . . . . . . . . . . . .35 Enterprise Portal Systems . . . . . . . . . . . . . . . . . . . . . . . .15 Production Engineering . . . . . . . . . . . . . . . . . . . . . . . . .36 Fluid Flow Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . .16 Production Optimization . . . . . . . . . . . . . . . . . . . . . . . .36 Online Monitoring & Optimization . . . . . . . . . . . . . . .16 Well Log Data Access and Management . . . . . . . . . . . . .37

F A L L 200 2009 9

SOFTWARE REFERENCE

Business Management BUDGETING, CAPITAL ALLOCATION AND PLANNING

U PSTREA M / D OWN STREA M SOFTWA RE REFERENCE

Company Bio m:pro IT Consult is a project services and software products company which enables petroleum refining, petrochemical and other industries to achieve total integration of information sources and applications, from business systems, ERP and supply chain management through to plant information, production planning, scheduling and operations decision support.

ENTERPRISE OPERATIONS MANAGEMENT

Products:

3esi #200, 1601 Westmount Road N.W. Calgary, Alberta T2N 3M2 Canada Phone: 403-270-3270 Fax: 403-270-3343 E-mail: info@3esi.com www.3esi.com

Company Bio: 3esi is a world-class supplier of innovative software solutions that help E&P companies increase capital efficiency, optimize process, integrate data and applications and perform look-backs throughout the entire Opportunity Life Cycle.

Products: esi.manage™ is an Operational Program Management tool that allows users to create Long Term Plans and Budgets easily and accurately within a single environment; eliminating large difficult to maintain spreadsheets. User’s can check the viability of their plan based on the aggregated project demand for rigs, key on-site personnel or any other scarce resources. User’s have the ability to rank and prioritize projects or an inventory of opportunities in seconds; knowing immediately if Exit Rate, F&D, Capex and Reserves Replacement targets are achievable. Key benefits include being able to import financial actuals and field estimates and blend them with forecasts to create a suite of variance reports that track progress against budget thus enabling improved communication between Finance and Operations departments. www.info.hotims.com/26886-401

BUSINESS INTEGRATION

m:pro IT Consult GmbH Kirchgasse 47 65183 Wiesbaden Germany Phone: +49 611 39843 0 Fax: +49 611 39843 12 E-mail: info@mpro-it.com www.mpro-it.com Matthias Wackenreuther, Enterprise Solutions 4

SOFTWARE REFERENCE

FALL 2009

m:pro delivers enterprise wide or point solutions - easy and fast to implement - which truly integrate the production and business applications required to manage the overall assets. m:pro enables, consult and assists business process improvements, especially for refining supply chain management (SCM). The m:pro Integration Platform (m:ip) provides the total integration of information sources and applications including ERP, planning, scheduling, functional databases, plant information systems, forecasting in a phased justified approach. The m:ip enables and improves the use of best-in-class software, plant and business applications = asset maximization. The m:pro object warehouse (m:owh) is our integration, data storage/management, and business intelligence back-end. The m:owh is based on standard and open relational database technology. The m:pro explorer (m:exp) is our feature rich, fully web-enabled common graphical user interface including build and administration tools. The m:exp can run as the portal or can seamlessly be embedded in popular web portal environments. m:pro provides standard applications/interfaces for: • Production planning, scheduling and blending • Performance monitoring and dashboards • Data and process quality • Information analysis, visualization, flowsheeting, trending and reporting Featured applications/interfaces are: • Analyzer Monitoring • Blend Monitoring and Reporting • Crude Composition Tracking • Crude Scheduling • GRTMPS Planning Interface • Heat Exchanger Monitoring • KPIs, Operating Envelops, Plan vs Actual • Lab Interface and Reporting • LP Data Collector • Oil Movement Logging • ORION Scheduling Interface • PIMS Planning Interface • Quality Tracking • Tank Calculation System www.info.hotims.com/26886-414

Oildex 1999 Broadway, Suite 1900 Denver, Colorado 80202 Phone: 303-863-8600 Toll Free: 888-922-1222 Fax: 303-863-0505 E-mail: info@oildex.com www.oildex.com Other Oildex Office Locations: 11777 Katy Freeway, Suite 350 Houston, Texas 77079 Phone: 281-741-6300 Fax: 281-741-6296

Company Bio: Oildex is the energy industry’s leading provider of ePayables, digital data, workflow, and spend analysis solutions. It provides the most comprehensive solution for managing revenues, expenses, and business intelligence. More than 5,000 companies depend on Oildex to help streamline their business processes with services ranging from electronic processing of invoices and delivery tickets to digital checkstub detail. Oildex connects the energy industry, serving operators, owners, suppliers, drillers, service providers, construction companies, and more.

Products: Oildex delivers the energy industry’s largest system for exchanging data, improving workflow and analyzing costs. With Oildex, companies working within the energy industry gain visibility into critical data, so they can quickly decide how and where to allocate resources - increasing productivity, reducing labor costs and saving time and money. The Oildex Service Suite Includes: Spendworks™ - is Oildex’s Award-winning ePayables solution for processing invoices, field tickets and purchase orders, simplifying the way companies purchase and pay for goods and services. TrendX™ - is Oildex’s business intelligence solution, providing insight into trends and opportunities in near real time. Checkstub Connect™ (CDEX) - is the industry’s largest revenue data exchange, providing companies and interest owners with the ability to receive and upload their revenue data electronically, eliminating manual entry and associated errors. Owner Relations Connect™ - is the industry’s most powerful owner-relations tool, providing owners and operators with web-accessible statements of revenue, production, gas balance,

Business Management

UPS TREAM / DOW NS T R E A M S OF T WA R E R E FE REN CE joint interest bills and more. JIB Connect™ - is one of the largest electronic joint interest bill exchanges in the United States, automating JIB processing and eliminating routine monthly data entry. Oildex Features and Benefits: • Simplifies data entry • Reduces up to 70% of process costs • Eliminates hand keying • Resolves partner and supplier issues three times faster • Captures 100% of data • Reduces errors • Provides access to information in near realtime • Ensures monthly coding consistency www.info.hotims.com/26886-417

LAND AND LEASING

geoLOGIC systems ltd. 900, 703 6 Avenue SW Calgary, AB Canada T2P 0T9 Phone: 403 262-1992 Fax: 403-262-1987 E-mail: sales@geologic.com www.geologic.com Andrea Hood, VP Business Development & Sales

Company Bio: geoLOGIC systems ltd. provides well data and integrated software solutions to the energy and production industry. The company is an innovator in supplying data in more accessible and usable forms so clients can make better decisions - from the well head to senior levels of accounting and administration.

Products: geoSCOUTTM is a fully integrated, Windowsbased exploratory system that combines presentation-quality mapping and cross-section tools with data handling and analysis soft-

ware. It integrates public and proprietary data on wells, well logs (Raster and LAS), land, pipelines and facilities, fields and pools, and seismic studies. It includes powerful, easyto-use tools for searching, viewing, mapping, reporting, graphing, analysis and managing information. The gDCTM (geoLOGIC Data Center) is an online exploration information system that gives users instant access, through their choice of software, to high quality data in the open Public Petroleum Data Model. Extremely fast and reliable, the gDC gives access to general well data, including geoLOGIC Tops, Original Operator data, DST and other well test data, directional well data, land data, and LAS and Raster log data. petroCUBETM is an innovative suite of products that provide unbiased, consistent statistical insights that can help you make more profitable decisions about petroleum plays. From reserve and production data through to full-cycle economics, petroCUBE gives you immediate access to a full spectrum of current geostatistical, technical and financial information and comprehensive analytical tools. petroCUBE instantly delivers the data engineers and geologists need to accurately assess risk and justify exploration and development proposals before wells are drilled.

If you want easy-to-use decision-making tools – there’s only one direction to go

industry-leading customer service

geoSCOUT™ uses a windows-based platform that makes it easy for searching, posting, mapping and analyzing the oil and gas data you need to make smarter decisions faster and to maximize the return on your oilfield investments. Thousands of landmen, engineers & geologists use geoSCOUT oil and gas mapping and analysis software every day, to make more efficient, informed decisions. Give us an hour for a demo – we know you’ll see the value. Call 403.262.1992 Email info@geoscout.com www.geoscout.com/demo

FROM

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www.info.hotims.com/26886-408

helping clients increase productivity

Select 408 at www.HydrocarbonProcessing.com/RS

Business Management OPERATIONS

U PSTREA M / D OWN STREA M SOFTWA RE REFERENCE

PLANT LIFECYCLE AND PERFORMANCE MONITORING m:pro IT Consult GmbH

KBC Advanced Technologies, Inc. 14701 St. Mary’s Lane, Suite 300 Houston, TX 77079 Phone: 281-293-8200 Fax: 281-293-8290 E-mail: salesinfo@kbcat.com www.kbcat.com

Other KBC Office Locations London: + 44 (0)1932 242424 Moscow: +7 (0)95 980 8449 Singapore:+ 65 6735 5488 Japan: +81 (0)45 290 6380

KBC Advanced Technologies, Inc. 14701 St. Mary’s Lane, Suite 300 Houston, TX 77079 Phone: 281-293-8200 Fax: 281-293-8290 E-mail: salesinfo@kbcat.com www.kbcat.com

Other KBC Office Locations London: + 44 (0)1932 242424 Moscow: +7 (0)95 980 8449 Singapore:+ 65 6735 5488 Japan: +81 (0)45 290 6380

Company Bio: KBC Advanced Technologies is a leading independent consulting and technology services group, delivering improvements in business performance and asset value to owners and operators in the oil refining, petrochemical, and other processing industries worldwide. Profimatics®, an operating division of KBC, provides specialized software to improve a refinery’s and/or a petrochemical facility’s profitability through industry leading models and simulation technology.

Products: KBC offers a wide range of software and associated services, from detailed reactor unit modeling to refinery-wide simulation. At the operations level, KBC Profimatics models are used in performance monitoring, troubleshooting and optimization, such as cyclelength optimization. Petro-SIM® and Petro-SIM Express are KBC’s full-featured, graphical process simulators, featuring Profimatics technology and industryproven process models. Petro-SIM and PetroSIM Express includes general-purpose unit operations, an extensive component library, a range of thermodynamics packages, and innovative methods to fully integrate the software with plant information systems, databases, Excel, and the LP. KBC offers unsurpassed model breath and depth that lets you truly model any part of the refinery. KBC’s industry-proven Profimatics SIM Suite reactor models include: FCC-SIM (Fluid Cat Cracking), HCRSIM (Hydrocracker), REF-SIM (Reformer), HTR-SIM (Hydrotreater Series), DC-SIM (Delayed Coker), ALK-SIM (Alkylation unit) and VIS-SIM (Visbreaker). New additions include reactor models for C6 Isomerization, Xylene Isomerization, and Aromatics Transalkylation. www.info.hotims.com/26886-412

Products: KBC offers a wide range of software and associated services, from detailed reactor unit modeling, troubleshooting and monitoring to refinery-wide simulation. Petro-SIM® and Petro-SIM Express are KBC’s full-featured, graphical process simulators featuring Profimatics technology and industry-proven process models. Petro-SIM includes general-purpose unit operations, an extensive component library, a range of thermodynamics packages, and innovative methods to fully integrate the software with plant information systems, databases, Excel, and the LP. KBC offers unsurpassed model breath and depth that lets you truly model any part of the refinery. KBC’s industry-proven Profimatics SIM Suite reactor models include: FCC-SIM (Fluid Cat Cracking), HCR-SIM (Hydrocracker), REFSIM (Reformer), HTR-SIM (Hydrotreater Series), DC-SIM (Delayed Coker), ALK-SIM (Alkylation unit) and VIS-SIM (Visbreaker). New additions include reactor models for C6 Isomerization, Xylene Isomerization, and Aromatics Transalkylation. www.info.hotims.com/26886-412

Kirchgasse 47 65183 Wiesbaden Germany Phone: +49 611 39843 0 Fax: +49 611 39843 12 E-mail: info@mpro-it.com www.mpro-it.com Matthias Wackenreuther, Enterprise Solutions

Products: m:pro delivers enterprise wide or point solutions easy and fast to implement - which truly integrate the production and business applications required to manage the overall assets. m:pro enables, consult and assists business process improvements, especially for refining supply chain management (SCM). The m:pro Integration Platform (m:ip) provides the total integration of information sources and applications including ERP, planning, scheduling, functional databases, plant information systems, forecasting in a phased justified approach. The m:ip enables and improves the use of best-in-class software, plant and business applications = asset maximization. The m:pro object warehouse (m:owh) is our integration, data storage/management, and business intelligence back-end. The m:owh is based on standard and open relational database technology. The m:pro explorer (m:exp) is our feature rich, fully web-enabled common graphical user interface including build and administration tools. The m:exp can run as the portal or can seamlessly be embedded in popular web portal environments. m:pro provides standard applications/interfaces for: • Production planning, scheduling and blending • Performance monitoring and dashboards • Data and process quality • Information analysis, visualization, flowsheeting, trending and reporting Featured applications/interfaces are: • Analyzer Monitoring • Blend Monitoring and Reporting • Crude Composition Tracking • Crude Scheduling • GRTMPS Planning Interface • Heat Exchanger Monitoring • KPIs, Operating Envelops, Plan vs Actual • Lab Interface and Reporting

Select 436 at www.HydrocarbonProcessing.com/RSv 6

SOFTWARE REFERENCE

FALL 2009

Business Management

UPS TREAM / DOW NS T R E A M S OF T WA R E R E FE REN CE U PSTREA M / D OWN STREA M SO FTWA RE REFERENCE • LP Data Collector • Oil Movement Logging • ORION Scheduling Interface • PIMS Planning Interface • Quality Tracking • Tank Calculation System www.info.hotims.com/26886-414

PRODUCTION/ YIELD ACCOUNTING

Merrick Systems, Inc. 4801 Woodway, Suite 200E Houston, TX 77056 Toll Free: 800-842-8389 Phone: 713-579-3400 Fax: 713-579-3499 E-mail: sales@MerrickSystems.com www.MerrickSystems.com Faisal Kidwai, V.P. Sales Faisal.Kidwai@MerrickSystems.com

Company Bio: Merrick Systems helps oil and gas companies to take control of their operations with the industry’s most robust software and hardware

solutions addressing production operations, engineering and asset tracking. Recognized for its industry expertise and innovative technologies, Merrick is committed to delivering best of breed solutions to improve production operations, helping companies extend oil and gas producing asset life, lower lifting costs, increase production and optimize operations. Merrick’s integrated applications include realtime surveillance and optimization; field operations management; field data capture; hydrocarbon production accounting; mobile computing for field and drilling operations; engineering workflow orchestration and ruggedized RFID for drilling and asset management.

Products: ProCount – ProCount is a comprehensive solution for hydrocarbon accounting that facilitates simple to complex allocation requirements operating onshore and offshore domestic US and international properties. The production accounting software integrates with Merrick’s field data capture system including electronic data from automation (SCADA, EFM) so the most recent day’s production information is available throughout the company. ProCount features include: • Simple drag and drop tool that allows users to create simple to complex multi-tiered connections for allocation networks. • Quick setup of daily and monthly allocations

using templates for multiple objects (meters, tanks, equipment and completions). • Allocate by volume, energy based – BTU and analysis, including component allocation of plant products and liquids/NGL. • User defined error checking and validation, custom formulas for allocation requirements and user configurable data fields and screens. • Handle requirements for mixed units of measurement (Imperial and Metric) within one data store. • Scalable to handle daily allocations for 20,000+ wells (with related equipment in a network) • Integrates with revenue/financial systems like Artesia, Excalibur, SAP as well as Aries for Petroleum Economics. • Regulatory filing of production for all key states and MMS either in electronic format or printed. • 100+ reports included for daily operations, daily and monthly accounting/allocations and management/partner reporting. Carte – Carte is a web-based dashboard that makes data from the production database viewable down to the well completion level. It allows oil and gas professionals across a company to view, graph and export daily and monthly oil and gas production trends. Carte provides users with a window into production data unlike any other product on the market. Managers use Carte for quick summarizations; engineers gain access to the production data details they

A KE R A H T A G A D V I Z E TA C C E A S P M M G S M E IC L RI A N N & X I M DA E D U 8 G I V E C E YC L I L T S S I E L S S M field operations A D management R 3 & and E T W CE ON R C TO IO L I M CT C C E T E I I I C O F field data capture O R A E A D F N E P R M A TA A E S S E R V O M C E U R AG P R E D R E T R T S T N S D A O M P R E AU L I Ahydrocarbon E N I T E Cproduction CE AN CE ESS IC I P I S Eaccounting N M H P M A IN ST O2 A C LS M O M AG E R C H E R S E R T N H A I Z E O T US ME C O C AN N XRFID P forEdrilling B Aruggedized D A TO E L E C E W DS N T I M and E E DO ESS M N E P O N G C E W T O TRE O management VA L -T I M I N O F R A G AT Iasset D N A N YC L E T E D N L R T T L A E NIT forRthe Digital N S E D EN RY E COil Field A W I Industrial D E V VA L I Eworkflow N R E P L A W O I N T L I F E E M E C O Lengineering E M TIS O A automation V R A T T N EN M E L L N AG R E A G E C O I O N X P E AT I N P N I N O U E I M W M A C T AT realS HtimeMsurveillance A R R and S AT optimization E E ALID NT R OP RUM CES L M E E G V ME T AC A O N S H I T A LU W N E A I N A S T U T O E R A S T V I R H V H I P AG E T R E I N TA A T ARC T E F O IS O C E A D P mobile computing L S S for field N and E R E B P E C T O P LY P N R DA O N A P E O I N drilling I P I M ERY D N N operations S O S W T H T O U I O O S A W D S C V I T C R R R L O H A CO E NT SS DU FIE ENT TE P Y P E LUA O F E N E E C R O VA S T P LY E R R G E M O C E E E M E D I TO R S H O F O W Y S E G N A P A F CO U P A S T N A O IVIT EC T O L X P R -T O F N U E T S A K O A S S T G P Y M R D I S M O R E N D L -T RE DS CO D U C R O S TO R R E E L O P L P EA S A O N E D Wsuite U RS O I I N E 4801 woodway 200E H L R E T R D T H E www.mer IZ J O N D Hricksystems.com E Ntx T77056O O L T I O Z E P E D I T E G U O F F S E R S E R A Dhouston A A M R R N OP E 713 579 P Memail: E N 3400 I D I M Iricksystems.com A H Asales@mer X G G T SC L W M D S E S A A N X T O N V A R E O R E L D O F I T Y S TA M A N V E S N N I T I M E E M R J E Y P Select 416 at www.HydrocarbonProcessing.com/RS H V A U A R N F 2009 S 7 SS

we understand

ALL

OFTWARE

EFERENCE

Business Management PRODUCTION/YIELD ACCOUNTING, CONT.

U PSTREA M / D OWN STREA M SOFTWA RE REFER REFERENCE ENC E

tiple diameter towers, COMPRESS can model virtually any geometry.

need to get their jobs done, and; analysts can use views to highlight production issues quickly before they become problematic. Carte features include: • View allocated production data to spot early trends and potential problem areas. • Drill down to the completion level to access the information needed for decision making. • Activate Excel from within Carte to generate user spreadsheets. • Annotate with ‘sticky notes’ on well production graphs • Print one or all production graphs with a single mouse click • Graph the forecasted economic model versus actual production on a daily basis PetroRegs – From production through filings with state and federal agencies, to gas allowable computations and well test calculations, these modules help ensure regulatory compliance. Regulatory features include: • Flexible filing options with hard copy reports, electronic filing and PDF format • Automatic handling of prior period adjustments (PPA) • Each module generates state-approved digital filings • Generate error reports for identifying potential problems before filing with the state www.info.hotims.com/26886-416

REGULATORY COMPLIANCE

The standard functionality of COMPRESS includes everything needed to perform ASME Section VIII, Division 1 pressure vessel calculations. This includes the U.S. Customary and Metric Editions of Section II, Part D as well as a selection of Building Codes and related Engineering Standards. To tailor COMPRESS to your needs, the following optional modules are available: • ASME Section VIII, Division 2 • Heat Exchangers (includes TEMA Standard, ASME UHX rules, tube field layout capability and bi-directional interface with HTRI’s Xchanger Suite) • Drafter (converts COMPRESS files into AutoCAD drawings) • Coster (creates Excel compatible vessel cost estimates) COMPRESS generates both detailed and abbreviated reports, the former suitable for use as a calculation audit trail. COMPRESS also generates ASME U forms and NBIC R forms. Once finalized, forms can be saved in PDF or EDT compliant format. EDT compliant files can be directly submitted to the National Board electronically. To simplify document management, a new “Project” feature allows users to organize, view and backup files of any type from within COMPRESS. Visit www.codeware.com to download your complimentary COMPRESS trial software today. www.info.hotims.com/26886-405

RISK MANAGEMENT Codeware, Inc. Codeware, Inc. 5224 Station Way Sarasota, FL 34233 United States Phone: (941) 927-2670 Fax: (941) 927-2459 E-mail: inquiries@codeware.com www.codeware.com

Company Bio: Since 1985, Codeware has focused exclusively on providing the most comprehensive software for the design and analysis of ASME vessels and exchangers. Codeware’s Austin, Texas based development team has the expertise needed to understand the complexities of the Code rules and the practical experience required to implement an effective solution.

Products: Let COMPRESS be your expert assistant. From individual components to complex mul8

SOFTWARE REFERENCE

FALL 2009

The Equity Engineering Group, Inc. 20600 Chagrin Blvd., Suite 1200 Shaker Heights, OH 44122 Phone: 216-283-9519 Fax: 216-283-6022 E-mail: gcalvarado@eng.com www.equityeng.com Greg Alvarado, VP Sales and Client Service

Company Bio: The Equity Engineering Group, Inc. is a recognized leader on aging infrastructure fixed equipment service and support for the oil and gas industry. Equity helps plants manage risk and improve profitability with cutting-edge software and consulting strategies that maximize equipment operational availability, control inspection costs and avoid costly shutdowns.

Products: API RBI Software is the industry standard for plant risk management, developed through the API consensus standards process and documented in API 581. It provides risk values and metrics for equipment, enabling plants to identify areas of potential failure and prioritize inspection dollars based on measured risk. Modules include fixed equipment, heat exchanger bundles, atmospheric storage tanks, and pressure relief systems. VCESage™ is a collection of modules providing an easy-to-use computerized design/analysis resource consistent with the new API 579-1/ ASME FFS-1 standard. The modules enable users to review and/or analyze existing and new equipment for structural integrity, code compliance, re-rating and remaining life evaluations. VCEDamage Mechanisms™ is a quick reference guide to identify the potential damage mechanisms that can cause equipment failure. It guides users through the damage mechanism identification process, helps in selecting the best inspection method for each damage type, and provides simplified Process Flow Diagrams showing where damage will likely occur. VCEIntelliJoint™ offers a total solution to bolted joint leakage with the latest advanced bolted joint technology, including assembly procedures and gasket test results. The program provides industry best practice gasket specifications and incorporates knowledge in areas required to effectively identify the root cause of a leakage problem. Training Equity Engineering offers software training for the API RBI and VCESage™ programs, as well as training in other engineering disciplines. The software courses, designed to help both the novice and experienced user make more effective use of the software, emphasize both hands-on training and in-class example problems. Public courses are held at E2G offices in Cleveland and Houston, or private courses can be held at your site. To find out more about E2G training courses, go to www.equityeng.com. www.info.hotims.com/26886-406

UPS TREAM / DOW NS T R E A M S OF T WA R E R E FE REN CE

ASSET MANAGEMENT

software courses, designed to help both the novice and experienced user make more effective use of the software, emphasize both hands-on training and in-class example problems. Public courses are held at E2G offices in Cleveland and Houston, or private courses can be held at your site. To find out more about E2G training courses, go to www.equityeng.com.

Downstream New additions include reactor models for C6 Isomerization, Xylene Isomerization, and Aromatics Transalkylation. www.info.hotims.com/26886-412

ALARM MANAGEMENT

www.info.hotims.com/26886-406

ProSys, Inc.

KBC Advanced Technologies, Inc. 14701 St. Mary’s Lane, Suite 300 Houston, TX 77079 Phone: 281-293-8200 Fax: 281-293-8290 E-mail: salesinfo@kbcat.com www.kbcat.com

Other KBC Office Locations London: + 44 (0)1932 242424 Moscow: +7 (0)95 980 8449 Singapore: + 65 6735 5488 Japan: +81 (0)45 290 6380

Products: KBC offers a wide range of software and associated services, from detailed reactor unit modeling, troubleshooting and monitoring to refinery-wide simulation. KBC offers the most comprehensive and detailed suite of models for the refining industry. Petro-SIM® and Petro-SIM Express are KBC’s full-featured, graphical process simulators, featuring Profimatics technology and industryproven process models. Petro-SIM includes general-purpose unit operations, an extensive component library, a range of thermodynamics packages, and innovative methods to fully integrate the software with plant information systems, databases, and Excel, and the LP.

11814 Coursey Boulevard, Suite 408 Baton Rouge, LA 70816 Phone: 225-291-9591 Fax: 225-291-9594 E-mail: sales@prosys.com www.agileops.com Katherina Persac, Sales & Marketing Director

Company Bio: ProSys, Inc. delivers high-quality, cost-effective, innovative process control systems consulting services and product solutions to the international refining and chemical industries. ProSys’ expertise and experience cover the full range of modern control system technology, including basic control, advanced control, dynamic configuration, human-machine interface, and alarm management.

Products: For far too long, plants and refineries have relied on process control applications and systems that operate in silos—each built for a specific function, but without the big-picture, goal-oriented view that profit-driven companies demand. It’s time for process control to work together. ProSys has the solution. AgileOps is the industry’s first truly unified process control execution environment. The single, Webbased, multi-user interface provides a same-look view and control of the whole operation and integrates with our display library. It improves ease of use, lowers training costs, and eliminates redundant data entry across multiple systems. It’s the only complete alarm management solution. You take unprecedented command of your plant and control system to meet real business needs. Earn more. Spend less. Do all the things you wish process control had helped you do all along. It’s dynamic plant management and control for the agile enterprise. www.info.hotims.com/26886-418

KBC offers unsurpassed model breath and depth that lets you truly model any part of the refinery. Our industry-proven Profimatics SIM Suite reactor models are all available with Petro-SIM. Reactor models include: FCC-SIM (Fluid Cat Cracking), HCR-SIM (Hydrocracker), REFSIM (Reformer), HTR-SIM (Hydrotreater Series), DC-SIM (Delayed Coker), ALK-SIM (Alkylation unit) and VIS-SIM (Visbreaker). F A L L 2009

SOFTWARE REFERENCE

Downstream DESIGN, CONSTRUCTION AND ENGINEERING

U PSTREA M / D OWN STREA M SOFTWA RE REFER ENC E • Expert Systems (‘es-solutions’) are application-specific bundles that talk the specific engineering language required. They can be viewed as ‘packaged consultancy’ since they are honed for solving particular application challenges.

ties), this program allows rigorous calculation of pure component and mixture physical properties and phase equilibria (VLE, LLE, VLLE). www.info.hotims.com/26886-404

www.info.hotims.com/26886-403

CD-adapco 60 Broadhollow Road Melville, NY 11747 Phone: 248-246-5803 Phone: 631-549-2300 Fax: 208-575-2685 E-mail: dennis.nagy@us.cd-adapco.com www.cd-adapco.com Dennis Nagy, VP Marketing & Business Development

Company Bio: CD-adapco is the leading global provider of full-spectrum engineering simulation (CAE) solutions for fluid flow, heat transfer and stress, including Computational Fluid Dynamics (CFD/CAE) flow, thermal, and stress software, CAD-embedded CFD options, and CAE consulting services and training. Its principal offices are in New York, London and Yokohama with subsidiary offices across the world.

Products: CD-adapco’s solutions (software and related consulting services, training, and mentoring) are widely used across many industries, including oil and gas, chemical process, marine, offshore structures, turbomachinery, automotive, aerospace, building systems, electronics, environmental, pharmaceuticals, power generation, rail, and specialized mechanical engineering applications. The technology-leading Computational Fluid Dynamics flow, thermal, and stress simulation (CFD/CAE) STAR codes have outstanding capabilities for handling complex fluid flow and heat transfer problems including transient flows, chemical reaction, free-surface flows, combustion, rotating systems, multiphase and multiphysics. There are four ways in which CD-adapco delivers its CFD technology in software: • STAR-CCM+ is a radically new fullspectrum CFD/CAE processing environment that features the latest object-oriented methods and ergonomically designed GUI for streamlined integration into any company’s engineering process. Solutions on polyhedral cells enable faster and more accurate solutions than any other of the world’s legacy CFD codes. • STAR-CD remains the world’s most advanced CFD code, comes with advanced pre-processing tools, and is now enhanced by the inclusion of any one of the environments from the STAR-CAD Series. • STAR-CAD Series is a range of products that deliver non-complex CFD in an easy to use CAD-embedded environment 10

SOFTWARE REFERENCE

FALL 2009

Codeware, Inc. Chemstations, Inc. 2901 Wilcrest, Suite 305 Houston, TX 77042 Toll Free: 800-243-6223 Phone: 713-978-7700 Fax: 713-978-7727 E-mail: sales@chemstations.net www.Chemstations.net Steve Brown, V.P. Sales/Marketing

Company Bio: With offices worldwide, Chemstations is a leading global supplier of process simulation software for the following process industries; Oil & Gas, Petrochemicals, Chemicals, and Fine Chemicals, including Pharmaceuticals. We currently offer several individually licensed, and tightly integrated, technologies to address the needs of the chemical engineer, whether doing new process design or working in the plant.

Products: CC-STEADY STATE Chemical Process Simulation Software - Includes database of chemical components, thermodynamic methods, and unit operations to allow steady state simulation of continuous chemical processes from lab scale to full scale. CC-DYNAMICS Dynamic Process Simulation Software - Takes your steady state simulations to the next level of fidelity to allow dynamic analysis of your flowsheet. The combination of two pieces of software, CC-ReACS and CCDCOLUMN make CC-DYNAMICS the dynamic simulator of choice. CC-BATCH Batch Distillation Simulation Software - As an add-on or stand alone program, CC-BATCH makes batch distillation simulation and design easy with intuitive, operation step based input. CC-THERM Heat Exchanger Design & Rating Software - As an add-on or stand alone program, CC-THERM makes use of multiple international standards for design and materials to make sizing your next heat exchanger faster and more accurate. CC-SAFETY NET Piping & safety relief Network Simulation Software - A subset of CCSTEADY STATE, this program allows rigorous analysis of any piping network. CC-FLASH Physical Propertieis & Phase Equilibria Calculation Software - A subset of the CHEMCAD Suite (all of the CHEMCAD Suite products include CC-FLASH capabili-

Codeware, Inc. 5224 Station Way Sarasota, FL 34233 United States Phone: (941) 927-2670 Fax: (941) 927-2459 E-mail: inquiries@codeware.com www.codeware.com

Products: Let COMPRESS be your expert assistant. From individual components to complex multiple diameter towers, COMPRESS can model virtually any geometry. The standard functionality of COMPRESS includes everything needed to perform ASME Section VIII, Division 1 pressure vessel calculations. This includes the U.S. Customary and Metric Editions of Section II, Part D as well as a selection of Building Codes and related Engineering Standards. To tailor COMPRESS to your needs, the following optional modules are available: • ASME Section VIII, Division 2 • Heat Exchangers (includes TEMA Standard, ASME UHX rules, tube field layout capability and bi-directional interface with HTRI’s Xchanger Suite) • Drafter (converts COMPRESS files into AutoCAD drawings) • Coster (creates Excel compatible vessel cost estimates) COMPRESS generates both detailed and abbreviated reports, the former suitable for use as a calculation audit trail. COMPRESS also generates ASME U forms and NBIC R forms. Once finalized, forms can be saved in PDF or EDT compliant format. EDT compliant files can be directly submitted to the National Board electronically. To simplify document management, a new “Project” feature allows users to organize, view and backup files of any type from within COMPRESS.

UPS TREAM / DOW NS T R E A M S OF T WA R E R E FE REN CE Visit www.codeware.com to download your complimentary COMPRESS trial software today. www.info.hotims.com/26886-405

Heat Transfer Research, Inc. Worldwide

150 Venture Drive College Station, TX 77845 USA Phone: 979-690-5050 Fax: 979-690-3250 E-mail: HTRI@HTRI.net www.HTRI.net Claudette D. Beyer, President and CEO Fernando J. Aguirre, VP, Sales and Business Development

Asia - Pacific World Business Garden Marive East 14F Nakase 2-6, Mihamaku Chiba 261-7114 Japan Phone: 81-43-297-0353 Fax: 81-43-297-0354 E-mail: HTRI.Asia@HTRI.net Hirohisa Uozu, Regional Manager

EMEA (Europe, Middle East, Africa) The Surrey Technology Centre 40 Occam Road Guildford, Surrey GU2 7YG U.K. Phone: 44-(0)1483-685100 Fax: 44-(0)1483-685101 HTRI.Europe@HTRI.net Hans U. Zettler, Regional Manager

Xfh—Simulates the behavior of fired heaters. Calculates the radiant section of cylindrical and box heaters and the convection section of fired heaters. It also designs process heater tubes and performs combustion calculations. Xhpe—Designs, rates, and simulates the performance of hairpin heat exchangers. Xist—Designs, rates, and simulates single- and two-phase shell-and-tube heat exchangers, including kettle and thermosiphon reboilers, falling film evaporators, and reflux condensers. Xjpe—Designs, rates, and simulates jacketedpipe (double-pipe) heat exchangers. Xphe—Designs, rates, and simulates plate-andframe heat exchangers. A fully incremental program, each plate channel is calculated individually using local physical properties and process conditions. Xspe—Rates and simulates single-phase spiral plate heat exchangers. Xtlo—Graphical standalone rigorous tube layout software; also integrated with Xist. Xvib—Performs flow-induced vibration analysis of a single tube in a heat exchanger bundle. It uses a rigorous structural analysis approach to calculate the tube natural frequencies for various modes and offers flexibility in the geometries it can handle. Xchanger Suite Educational—Customized version of Xchanger Suite with the capability to design, rate, and simulate shell-and-tube heat

Downstream exchangers, air-coolers, economizers, and plateand-frame heat exchangers. Available to educational institutions only. R-trend—Calculates and trends fouling resistances for shell-and-tube heat exchangers in single-phase service. Uses Microsoft Excel as working environment with optional link to Xist. www.info.hotims.com/26886-411

KRC Technologies, Inc. 4431 Donald Ave. San Diego, CA 92117 Toll Free: 888-467-2127 Phone: 858-490-0028 Fax: 858-777-5462 E-mail: support@engineering-software.com www.engineering-software.com Mike Stephenson, President

Company Bio: KRC Technologies provides engineering software solutions. The company sells hundreds of commercial engineering software applications from the company’s website. KRC Technologies also develops custom engineering solutions and has delivered software for the design and analysis of heat exchangers, on-line six sigma, factory automation and valve tray design software.

India C-1, First Floor, Tower-B, “Indraprasth Complex” Near Inox Multiplex, Race Course (North) Vadodara 390007, Gujarat, India Phone: +91 (982) 514-7775 HTRI.India@HTRI.net Rajan Desai, International Coordinator

Company Bio: HTRI operates an international consortium founded in 1962 that conducts industrially relevant research and provides software tools for design, rating, and simulation of process heat transfer equipment. HTRI also produces a wide range of technical publications and provides other services including contract research, software development, consulting, and training.

Select 404 at www.HydrocarbonProcessing.com/RS

Downstream

U PSTREA M / D OWN STREA M SOFTWA RE REFER ENC E

DYNAMIC SIMULATION AND OPTIMIZATION

DESIGN, CONSTRUCTION AND ENGINEERING, CONT.

as ‘packaged consultancy’ since they are honed for solving particular application challenges. www.info.hotims.com/26886-403

Products: KRC Technologies develops, sells and distributes software to engineers. Our mission is to provide software solutions to increase the productivity of engineers. For this reason, our products transcend most engineering disciplines. You can find software on our website to solve a multitude of engineering tasks. Some of these include: Design programs: • Shell and tube heat exchangers • Waste heat boilers • Cooling towers • Steam heaters • Heat recovery steam generators • Fluid mixers and atmospheric tanks • Mixer designs in vertical tanks • Vertical and horizontal storage tanks • Plate-fin heat exchangers • Compact heat exchangers • Heat transfer in process vessels and fermenters Physical properties: • Steam tables (IFC-97) • Gas compressibility calculators (AGA-8) • Psychrometrics • Combustion analysis • Thermodynamic and transport properties of over 600 common organic and inorganic compounds Economic evaluation: • Cogeneration • Flash tanks • Insulation Transport: • Piping pressure loss • Pipe Networks • Duct design • Flow calculation (nozzle, orifice, venturi) Structural: • Wind Load analysis • Snow load analysis • Single or multiple span beams • Rods • Self supported stacks • Guy wire supported stack • Analysis of horizontal vessels supported on two saddles KRC Technologies also creates custom software to various industries, including oil and gas. These have included: • Factory automation • On-line leak testing with six-sigma on-line analysis • Mist eliminator design • Valve tray design • Compact heat exchanger design Many products have demo versions that can be downloaded from the website, www.engineering-software.com. www.info.hotims.com/26886-413

SOFTWARE REFERENCE

FALL 2009

Company Bio:

Chemstations, Inc. 2901 Wilcrest, Suite 305 Houston, TX 77042 Toll Free: 800-243-6223 Phone: 713-978-7700 Fax: 713-978-7727 E-mail: sales@chemstations.net www.Chemstations.net Steve Brown, V.P. Sales/Marketing

Company Bio:

CD-adapco is the leading global provider of full-spectrum engineering simulation (CAE) solutions for fluid flow, heat transfer and stress, including Computational Fluid Dynamics (CFD/CAE) flow, thermal, and stress software, CAD-embedded CFD options, and CAE consulting services and training. Its principal offices are in New York, London and Yokohama with subsidiary offices across the world.

With offices worldwide, Chemstations is a leading global supplier of process simulation software for the following process industries; Oil & Gas, Petrochemicals, Chemicals, and Fine Chemicals, including Pharmaceuticals. We currently offer several individually licensed, and tightly integrated, technologies to address the needs of the chemical engineer, whether doing new process design or working in the plant.

Products:

CD-adapco’s solutions (software and related consulting services, training, and mentoring) are widely used across many industries, including oil and gas, chemical process, marine, offshore structures, turbomachinery, automotive, aerospace, building systems, electronics, environmental, pharmaceuticals, power generation, rail, and specialized mechanical engineering applications. The technology-leading Computational Fluid Dynamics flow, thermal, and stress simulation (CFD/CAE) STAR codes have outstanding capabilities for handling complex fluid flow and heat transfer problems including transient flows, chemical reaction, free-surface flows, combustion, rotating systems, multiphase and multiphysics. There are four ways in which CD-adapco delivers its CFD technology in software: • STAR-CCM+ is a radically new full-spectrum CFD/CAE processing environment that features the latest object-oriented methods and ergonomically designed GUI for streamlined integration into any company’s engineering process. Solutions on polyhedral cells enable faster and more accurate solutions than any other of the world’s legacy CFD codes. • STAR-CD remains the world’s most advanced CFD code, comes with advanced pre-processing tools, and is now enhanced by the inclusion of any one of the environments from the STAR-CAD Series. • STAR-CAD Series is a range of products that deliver non-complex CFD in an easy to use CAD-embedded environment • Expert Systems (‘es-solutions’) are application-specific bundles that talk the specific engineering language required. They can be viewed

CC-STEADY STATE Chemical Process Simulation Software - Includes database of chemical components, thermodynamic methods, and unit operations to allow steady state simulation of continuous chemical processes from lab scale to full scale. CC-DYNAMICS Dynamic Process Simulation Software - Takes your steady state simulations to the next level of fidelity to allow dynamic analysis of your flowsheet. The combination of two pieces of software, CC-ReACS and CCDCOLUMN make CC-DYNAMICS the dynamic simulator of choice. CC-BATCH Batch Distillation Simulation Software - As an add-on or stand alone program, CC-BATCH makes batch distillation simulation and design easy with intuitive, operation step based input. CC-THERM Heat Exchanger Design & Rating Software - As an add-on or stand alone program, CC-THERM makes use of multiple international standards for design and materials to make sizing your next heat exchanger faster and more accurate. CC-SAFETY NET Piping & safety relief Network Simulation Software - A subset of CCSTEADY STATE, this program allows rigorous analysis of any piping network. CC-FLASH Physical Properties & Phase Equilibria Calculation Software - A subset of the CHEMCAD Suite (all of the CHEMCAD Suite products include CC-FLASH capabilities), this program allows rigorous calculation of pure component and mixture physical properties and phase equilibria (VLE, LLE, VLLE) www.info.hotims.com/26886-404

UPS TREAM / DOW NS T R E A M S OF T WA R E R E FE REN CE

Downstream

ECONOMIC EVALUATION KBC Advanced Technologies, Inc. 14701 St. Mary’s Lane, Suite 300 Houston, TX 77079 Phone: 281-293-8200 Fax: 281-293-8290 E-mail: salesinfo@kbcat.com www.kbcat.com

Other KBC Office Locations London: + 44 (0)1932 242424 Moscow: +7 (0)95 980 8449 Singapore: + 65 6735 5488 Japan: +81 (0)45 290 6380

Products: KBC offers a wide range of software and associated services, from detailed reactor unit modeling, troubleshooting and monitoring to refinery-wide simulation and optimization. Petro-SIM® and Petro-SIM Express are KBC’s full-featured, graphical process simulators, featuring Profimatics technology and industryproven process models. Petro-SIM includes general-purpose unit operations, an extensive component library, a range of thermodynamics packages, and innovative methods to fully integrate the software with plant information systems, databases, and Excel, and the LP.. KBC offers unsurpassed model breath and depth that lets you truly model any part of the refinery. KBC’s industry-proven Profimatics SIM Suite reactor models include: FCC-SIM (Fluid Cat Cracking), HCR-SIM (Hydrocracker), REFSIM (Reformer), HTR-SIM (Hydrotreater Series), DC-SIM (Delayed Coker), ALK-SIM (Alkylation unit) and VIS-SIM (Visbreaker). New additions include reactor models for C6 Isomerization, Xylene Isomerization, and Aromatics Transalkylation. www.info.hotims.com/26886-412

Spiral Software Ltd KBC Advanced Technologies, Inc. 14701 St. Mary’s Lane, Suite 300 Houston, TX 77079 Phone: 281-293-8200 Fax: 281-293-8290 E-mail: salesinfo@kbcat.com www.kbcat.com Other KBC Office Locations London: + 44 (0)1932 242424 Moscow: +7 (0)95 980 8449 Singapore: + 65 6735 5488 Japan: +81 (0)45 290 6380

Products: KBC offers a wide range of software and associated services, from detailed reactor unit modeling and monitoring to refinery-wide simulation. Petro-SIM® and Petro-SIM Express are KBC’s full-featured, graphical process simulators, featuring Profimatics technology and industryproven process models. Petro-SIM includes general-purpose unit operations, an extensive component library, a range of thermodynamics packages, and innovative methods to fully integrate the software with plant information systems, databases, and Excel, and the LP. KBC offers unsurpassed model breath and depth that lets you truly model any part of the refinery. KBC’s industry-proven Profimatics SIM Suite reactor models include: FCC-SIM (Fluid Cat Cracking), HCR-SIM (Hydrocracker), REFSIM (Reformer), HTR-SIM (Hydrotreater Series), DC-SIM (Delayed Coker), ALK-SIM (Alkylation unit) and VIS-SIM (Visbreaker). New additions include reactor models for C6 Isomerization, Xylene Isomerization, and Aromatics Transalkylation. www.info.hotims.com/26886-412

St. Andrew’s House St. Andrew’s Road Cambridge, CB4 1DL United Kingdom Phone: +44 (0)1223 445 000 Fax: +44 (0)1223 445 001 E-mail: sales@spiralsoft.com www.spiralsoft.com Spiral also has consultants based in Oklahoma City, OK, and Weston, CT, USA.

Company Bio: Spiral Software was set up in 1998 in response to an observed change in the needs of the evolving oil industry. The modern oil industry faces a growing challenge: while environmental specifications on products grow tighter each year, many of the remaining reservoirs offer relatively poor quality crude oil. In this context, understanding the detailed refining behaviour of crude oil is more critical than ever before. Spiral Software provides tools and services that enable our clients to make the best possible choices in trading and refining crude oil.

Products: Spiral Software’s crude oil assay management tools are designed from the ground up for today’s challenges, allowing companies to benefit from the most recent developments in laboratory measurement, mathematical modelling and information technology. They play a businesscritical role in over 60 companies across over 200 sites around the world, including global implementations by three oil majors. CrudeSuite internet CrudeSuite internet (CSi) provides secure, web-based access to crude oil data and decision support tools. Focussing on the needs of integrated oil companies and energy traders, CSi enables users to maximise profits in trading and refining through a better understanding of crude oil quality and refining performance. Industry-leading software innovations provide unprecedented performance in netback calculations, crude margin estimation and crude and product blending, allowing users to explore opportunities in real time. In only a few seconds, users can explore margin estimates across broad crude slates or generate and assess thousands of blending possibilities. Accessible through standard web browsers, CSi provides a unified source of crude oil knowledge within a company, bringing together data from all available sources and making it globally accessible. Users throughout an organisation can make decisions on the same basis, with immediate access to the most current information in any format they require.

F A L L 2009

SOFTWARE REFERENCE

Downstream ECONOMIC EVALUATION, CONT. CSi is a fully modular application and functionality can be tailored to the specific requirements of each client company. In addition, the user interface is highly customisable, allowing each user to optimise the tool presentation around the needs of their particular role. • The Advanced Blending module uses cutting edge blending technology to explore a wide blending space, identifying blends which meet user-definable property criteria. Powerful graphical tools help users to visualise viable blending ranges and select optimal combinations which can immediately be generated as full database assays or directly to report formats suitable for planning and scheduling. • The Crude Valuation module provides powerful netback modelling with user control over refinery unit topology, operating parameters and product specifications. With a run time of less than 0.1s per crude, the netback tool allows wider ranges of potential feedstocks to be tested interactively, with users able to modify refining parameters and immediately explore their netback impact.

Crude Oil Assay Libraries

U PSTREA M / D OWN STREA M SOFTWA RE REFERENCE

Spiral CrudeManager and CrudeSuite Assay Management Tools For more information, please refer to the Spiral Software listing in the Planning, Scheduling and Blending section of the Downstream Software Reference Guide. www.info.hotims.com/26886-421

Asia - Pacific World Business Garden Marive East 14F Nakase 2-6, Mihamaku Chiba 261-7114 Japan Phone: 81-43-297-0353 Fax: 81-43-297-0354 E-mail: HTRI.Asia@HTRI.net Hirohisa Uozu, Regional Mgr.

ENERGY MANAGEMENT

EMEA (Europe, Middle East, Africa)

Heat Transfer Research, Inc.

India

Worldwide 150 Venture Drive College Station, TX 77845 USA Phone: 979-690-5050 Fax: 979-690-3250 E-mail: HTRI@HTRI.net www.HTRI.net Claudette D. Beyer, President and CEO Fernando J. Aguirre, VP, Sales and Business Development

Industry-leading assay libraries from Chevron and Shell are available in a variety of packages including regional and basket format.

^ƉŝƌĂů ^ŽŌǁĂƌĞ

The Surrey Technology Centre 40 Occam Road Guildford, Surrey GU2 7YG U.K. Phone: 44-(0)1483-685100 Fax: 44-(0)1483-685101 HTRI.Europe@HTRI.net Hans U. Zettler, Regional Manager C-1, First Floor, Tower-B, “Indraprasth Complex” Near Inox Multiplex, Race Course (North) Vadodara 390007, Gujarat, India Phone: +91 (982) 514-7775 HTRI.India@HTRI.net Rajan Desai, International Coordinator

Products:

Unlock the True Value of Crude Oil

HTRI Xchanger Suite—Integrated graphical user environment for the design, rating, and simulation of heat transfer equipment.

^ƉŝƌĂů ^ŽŌǁĂƌĞ͛Ɛ ƐƵŝƚĞ ŽĨ ĚĞĐŝƐŝŽŶ ƐƵƉƉŽƌƚ ƚŽŽůƐ ǁŝůů ĞŶĂďůĞ ǇŽƵ ƚŽ ĨƵůůǇ ƵŶĚĞƌƐƚĂŶĚ͕ ŵĂŶĂŐĞ͕ ǀŝƐƵĂůŝƐĞ ĂŶĚ ĂƉƉůǇ ƵƉͲƚŽͲĚĂƚĞ ĂƐƐĂǇ ĚĂƚĂ͕ ůĞĂĚŝŶŐ ƚŽ ŵĂǆŝŵŝƐĞĚ ƉƌŽĮƚĂďŝůŝƚǇ͘

Xace—Designs, rates, and simulates the performance of air-cooled heat exchangers, heat recovery units, and air preheaters.

ƌƵĚĞDĂŶĂŐĞƌ Ͳ ĐƌƵĚĞ Žŝů ĂƐƐĂǇ ŵĂŶĂŐĞŵĞŶƚ ƌƵĚĞ^ƵŝƚĞ >ĂďŽƌĂƚŽƌǇ Ͳ ĚĞƚĂŝůĞĚ ĂƐƐĂǇ ǁŽƌŬƵƉ ƌƵĚĞ^ƵŝƚĞ ŝŶƚĞƌŶĞƚ Ͳ ĚĞĐŝƐŝŽŶ ƐƵƉƉŽƌƚ ƚŽŽůƐ ĨŽƌ ƚƌĂĚŝŶŐ ƐƐĂǇ >ŝďƌĂƌŝĞƐ Ͳ ĚĞƚĂŝůĞĚ ĂƐƐĂǇ ŝŶĨŽƌŵĂƟŽŶ ĂŶĚ ŵŽĚĞů

ǁǁǁ͘ƐƉŝƌĂůƐŽŌ͘ĐŽŵ 14

Select 421 at www.HydrocarbonProcessing.com/RS

Xspe—Rates and simulates single-phase spiral plate heat exchangers.

UPS TREAM / DOW NS T R E A M S OF T WA R E R E FE REN CE

Xtlo—Graphical standalone rigorous tube layout software; also integrated with Xist. Xvib—Performs flow-induced vibration analysis of a single tube in a heat exchanger bundle. It uses a rigorous structural analysis approach to calculate the tube natural frequencies for various modes and offers flexibility in the geometries it can handle. Xchanger Suite Educational—Customized version of Xchanger Suite with the capability to design, rate, and simulate shell-and-tube heat exchangers, air-coolers, economizers, and plateand-frame heat exchangers. Available to educational institutions only. R-trend—Calculates and trends fouling resistances for shell-and-tube heat exchangers in single-phase service. Uses Microsoft Excel as working environment with optional link to Xist. www.info.hotims.com/26886-411

KBC Linnhoff March Energy Services Targeting House Gadbrook Park Northwich, Cheshire CW9 7UZ UK Phone: +44 (0)1606 815100 Fax: +44 (0)1606 815151 E-mail: energy@kbcat.com www.kbcat.com/lm

Company Bio: KBC Advanced Technologies is a leading independent consulting and technology services group, delivering improvements in business performance and asset value to owners and operators in the oil refining, petrochemical, and other processing industries worldwide. Linnhoff March, an operating division of KBC, provides process and utility integration through a range of software and services to help reduce capital expenditures and energy/utility requirements.

Products: ProSteam® software helps optimize the design of site utility systems. The Excel® spreadsheet add-in provides drawing tools and easy access to steam and water properties together with an impressive library of utility system equipment models. ProSteam builds on the successful base of its predecessor, Steam97, which has been applied to hundreds of systems worldwide to determine the true cost/benefit of design, and operational changes by accurately determining their influence on purchased power and fuel. OptiSteam™ is an enhanced version of ProSteam developed specifically to deal with the complex task of automatic utility system optimization. Linnhoff March’s experienced

personnel will build a custom model to match the site’s configuration and operation. The system can be set up for manual data input, or to import and reconcile data from the DCS. The final model can be applied by the company’s site personnel or remotely operated by our energy and utility experts to automatically determine least-cost utility system operation as process demands and energy economics fluctuate.

Downstream drop model building tools. • Presents results via MS-Excel based reports, MS-Visio drawings and HTML web pages. • Has an excellent ROI (usually less than 6 months). • Is a proven and validated software with over 20 years of successful applications. • Current users include major refiners and petrochemical producers. www.info.hotims.com/26886-420

www.info.hotims.com/26886-412

ENTERPRISE PORTAL SYSTEMS

Soteica Ideas & Technology, LLC 16010 Barker’s Point Ln, Suite 580 Houston, TX, 77079 Phone: 281-829-3322 Fax: 281-966-1710 Email: infousa@soteica.com www.soteica.com Other Soteica Office Locations: Europe/Middle East: +34 (93) 375 3503 Latin America: +54 (11) 4555 5703

m:pro IT Consult GmbH

Company Bio:

Company Bio

Products: Soteica’s Energy Management System, Visual MESA: • Is an online computer program that acts as your sitewide Utilities/Energy Watchdog. • Allows operators and engineers to have detailed coverage in four distinct areas: 1. Monitoring the steam, electric, water and fuel systems by providing warnings of important changes. 2. Optimization of the production and use of steam, fuel and power to reduce costs. Recommends how to operate the utility system at minimum cost within equipment and emissions constraints. 3. ”What If?” Case Studies and Planning by predicting how the utilities systems will respond to proposed changes. 4. Auditing, Accounting and Data Validation: tracks the imbalances that are key sensor and model health monitoring variables. • Runs continuously connected to online data from any historian via OPC. • Is the calculation engine for Energy Key Performance Indicators initiatives. • Has a MS-Visio based GUI with drag and

Kirchgasse 47 65183 Wiesbaden Germany Phone: +49 611 39843 0 Fax: +49 611 39843 12 E-mail: info@mpro-it.com www.mpro-it.com Matthias Wackenreuther, Enterprise Solutions m:pro IT Consult is a project services and software products company which enables petroleum refining, petrochemical and other industries to achieve total integration of information sources and applications, from business systems, ERP and supply chain management through to plant information, production planning, scheduling and operations decision support.

Products: m:pro delivers enterprise wide or point solutions - easy and fast to implement - which truly integrate the production and business applications required to manage the overall assets. m:pro enables, consult and assists business process improvements, especially for refining supply chain management (SCM). The m:pro Integration Platform (m:ip) provides the total integration of information sources and applications including ERP, planning, scheduling, functional databases, plant information systems, forecasting in a phased justified approach. The m:ip enables and improves the use of best-in-class software, plant and business applications = asset maximization. The m:pro object warehouse (m:owh) is our integration, data storage/management, and business intelligence back-end. The m:owh is based on standard and open relational database technology. The m:pro explorer (m:exp) is our feature rich, fully web-enabled common graphical user interface including build and administration tools. The m:exp can run as the portal or can

F A L L 2009

SOFTWARE REFERENCE

Downstream ENTERPRISE PORTAL SYSTEMS, CONT.

U PSTREA M / D OWN STREA M SOFTWA RE REFERENCE

FLUID FLOW ANALYSIS

seamlessly be embedded in popular web portal environments. m:pro provides standard applications/interfaces for: • Production planning, scheduling and blending • Performance monitoring and dashboards • Data and process quality • Information analysis, visualization, flowsheeting, trending and reporting Featured applications/interfaces are: • Analyzer Monitoring • Blend Monitoring and Reporting • Crude Composition Tracking • Crude Scheduling • GRTMPS Planning Interface • Heat Exchanger Monitoring • KPIs, Operating Envelops, Plan vs Actual • Lab Interface and Reporting • LP Data Collector • Oil Movement Logging • ORION Scheduling Interface • PIMS Planning Interface • Quality Tracking • Tank Calculation System www.info.hotims.com/26886-414

Company Bio: CD-adapco is the leading global provider of full-spectrum engineering simulation (CAE) solutions for fluid flow, heat transfer and stress, including Computational Fluid Dynamics (CFD) software, CAD-embedded CFD options, and CAE consulting services and training. Its principal offices are in New York, London and Yokohama with subsidiary offices across the world.

Products: CD-adapco’s solutions (software and related consulting services, training, and mentoring) are widely used across many industries, includ-

ing oil and gas, chemical process, marine, offshore structures, turbomachinery, automotive, aerospace, building systems, electronics, environmental, pharmaceuticals, power generation, rail, and specialized mechanical engineering applications. The technology-leading Computational Fluid Dynamics flow, thermal, and stress simulation (CFD/CAE) STAR codes have outstanding capabilities for handling complex fluid flow and heat transfer problems including transient flows, chemical reaction, free-surface flows, combustion, rotating systems, multiphase and multiphysics. There are four ways in which CD-adapco delivers its CFD technology in software: • STAR-CCM+ is a radically new full-spectrum CFD/CAE processing environment that features the latest object-oriented methods and ergonomically designed GUI for streamlined integration into any company’s engineering process. Solutions on polyhedral cells enable faster and more accurate solutions than any other of the world’s legacy CFD codes. • STAR-CD remains the world’s most advanced CFD code, comes with advanced preprocessing tools, and is now enhanced by the inclusion of any one of the environments from the STAR-CAD Series. • STAR-CAD Series is a range of products that deliver non-complex CFD in an easy to use CAD-embedded environment • Expert Systems (‘es-solutions’) are application-specific bundles that talk the specific engineering language required. They can be viewed as ‘packaged consultancy’ since they are honed for solving particular application challenges. www.info.hotims.com/26886-403

ONLINE MONITORING AND OPTIMIZATION

UPS TREAM / DOW NS T R E A M S OF T WA R E R E FE REN CE chemical engineer, whether doing new process design or working in the plant.

Products: Gas Flex®, first developed as a DOS program in 1990, does gas compressor performance calculations using BWR (Benedict, Webb & Rubin) equations of state. In it’s present form, Gas Flex® “Live Analysis” will automatically process compressor data. Gas Flex® will read raw data, process it and store results for trending purposes while you watch the results displayed on the OEM performance curve. The trending, including transients like hard startups aid troubleshooting efforts. www.info.hotims.com/26886-422

KBC Linnhoff March Energy Services Targeting House Gadbrook Park Northwich, Cheshire CW9 7UZ UK Phone: +44 (0)1606 815100 Fax: +44 (0)1606 815151 E-mail: energy@kbcat.com www.kbcat.com/lm

Company Bio: KBC Advanced Technologies is a leading independent consulting and technology services group, delivering improvements in business performance and asset value to owners and operators in the oil refining, petrochemical, and other processing industries worldwide. Linnhoff March, an operating division of KBC, provides process and utility integration through a range of software and services to help reduce capital expenditures and energy/ utility requirements.

Products:

Flexware, Inc. PO Box 110 Grapeville, PA 15634-0110 Phone: 724-527-3911 Fax: 724-527-5701 E-mail: sales@flexwareinc.com www.flexwareinc.com

Company Bio: Flexware® is focused on servicing companies interested in monitoring and improving turbomachinery performance for energy conservation and capacity improvements. Central to this is software development to assist the rotating equipment engineer in assessing the operating equipment along with training programs and supporting consulting services.

ProSteam® software helps optimize the design of site utility systems. The Excel® spreadsheet add-in provides drawing tools and easy access to steam and water properties together with an impressive library of utility system equipment models. ProSteam builds on the successful base of its predecessor, Steam97, which has been applied to hundreds of systems worldwide to determine the true cost/ benefit of design, and operational changes by accurately determining their influence on purchased power and fuel. OptiSteam™ is an enhanced version of ProSteam developed specifically to deal with the complex task of automatic utility system optimization. Linnhoff March’s experienced personnel will build a custom model to match the site’s configuration and operation. The system can be set up for manual data input, or to import and reconcile data from the DCS. The final model can be applied by the company’s site personnel or remotely operated by our energy and utility experts to automatically determine least-cost utility system

Downstream operation as process demands and energy economics fluctuate. www.info.hotims.com/26886-412

Company Bio: Soteica is a Process Engineering Software Company dedicated to the development, implementation, support and sustainability of its hydrocarbon and energy management applications, S-TMS and Visual MESA. For more than 20 years, Soteica has successfully deployed its applications in refineries and petrochemical plants throughout the Americas and Europe. Our customers have achieved millions of dollars in recurring benefits from the sustained use of our applications.

Downstream

U PSTREA M / D OWN STREA M SOFTWA RE REFER ENC E

ONLINE MONITORING AND OPTIMIZATION, CONT.

pared, and analyzed using advanced graphical and computational techniques. LP optimization technology is used to calculate netback value for selected crude or blends of crude. Crude netback values may readily be determined for a user customized set of refinery configurations.

• Has an excellent ROI (usually less than 6 months). • Is a proven and validated software with over 20 years of successful applications. • Current users include major refiners and petrochemical producers. www.info.hotims.com/26886-420

PLANNING, SCHEDULING AND BLENDING

Haverly Systems, Inc. 12 Hinchman Avenue Denville, NJ 07834 Phone: 973-627-1424 Fax: 973-625-2296 E-mail: newjersey@haverly.com www.haverly.com

Other Haverly Office Locations Ventura, CA: Houston, TX: St. Albans, U.K.: Singapore:

805-653-5355 713-776-3161 +44 1727 826321 +65 9630 6364

Company Bio:

AMI Consultants, Inc. 4102 Tremont Ct. Sugar Land, TX 77479 Phone: 281-565-4745 Fax: 281-565-1196 Email: Info@AmiConsultants.com www.AmiConsultants.com

Company Bio: AMI Consultant develops and markets software for Petroleum refinery planning and economics. Since the introduction of the PetroPlanSM software in 1996, AMI’s customer base has grown with installations now at over 50 sites worldwide. Licensees include operating and E&C companies as well as educational institutions.

Products: PetroPlanSM is a software to simulate the whole refinery using a truly user-friendly graphic interface. Applications include: evaluation of revamp/expansion options, planning of grassroots facilities, evaluation of alternative feedstocks, changed product specifications and optimization of plant operations. In the simulation each refinery unit is represented by a block (e.g. FCC). For each block, the prediction of product yields and properties is based on feed characteristics and user specified parameters (e.g. conversion). The equations for predicting a block’s performance are visible to the user and are editable. Crude oil cutting and specification product blending are integrated into the main simulation. www.info.hotims.com/26886-402

Haverly Systems Inc. is an independent software company that has specialized in the development and use of optimization-related products and services for over four decades. Their systems are used in more than 50 countries worldwide by international and independent oil companies, chemical companies, and many other industrial and government entities. The effectivenss of their products has long been recognized in the continued patronage and goodwill of their clients. The ownership has been unchanged since the company’s founding, and most senior management and technical staff has been with the company for more than 15 years. This continuity in ownership, management, and business specializaiton is reflected in the corporate stability, continued profitability, and very personal pride found in satisfying each client’s need for technically excellent products and services.

Products: H/CAMS: a software system for the management, development, analysis, and application of crude assay data. H/CAMS determines and relates the effects associated with mixing and distilling crude oils, as well as other virgin hydrocarbons. Hundreds of varying whole crude, distillate, and residue properties are accepted, reported, correlated, or otherwise calculated. Raw assay data is easily entered and results displayed through vivid graphs. These can be readily smoothed, augmented, and contraasted against other properties and known references to provide the very best representation of crude behavior to applications that depend on good assay data. Correlations and calculations-based sound engineering principles provide users additional intelligence in determining data quality and best data interpretation. H/ CAMS features several useful utilities that allow easy updating of existing assays with refinery laboratory or current operating data and assure accurate representations. H/CAMS may be supplied with one or more high quality, industry developed crude assay libraries to supplement a user’s local library and extend the application of the system. H/COMET: the on-line version of H/CAMS which allows for the quick access and evaluation of crude oils from a large, on-line crude assay database. Crudes may be easily cut, blended, com-

SOFTWARE REFERENCE

FALL 2009

GRTMPS: Haverly’s premier economic optimization planning system. GRTMPS is used to model individual refinery and petrochemical plant operations, as well as entire business enterprises, of any size and complexity, and over any time horizon. It employs both advanced linear and non-linear modeling techniques. Its non-linear modeling abilities extend to cut-point optimization, reformulated gasoline modeling, rigorous process simulation interfacing, and investment opportunity studies. Haverly also offers an advance refinery modeling platform in GRTMPS structure and developed by the industry consulting firm: Turner, Mason & Company -- to assist in the development and execution of models. H/Sched: advanced operations scheduling tools. Each H/Sched system couples superior schedule simulation and generation technology with stateof-the-art graphics to provide tools with unsurpassed scheduling optimization abilities. Schedules are automatically generated and optimized, using Haverly’s own Progressional LP technology. After reviewing informative Gantt charts, flow diagrams, inventory profiles and detail windows - schedulers may directly modify these mediums to alter their schedules and obtain more desirable results. H/Gal-XE: an expert H/Sched application specifically designed for the optimization of gasoline blend scheduling. Allow for fast construction and execution of models constrained by operational parameters typically found in gasoline blending and distribution operations. www.info.hotims.com/26886-410

KBC Advanced Technologies, Inc. 14701 St. Mary’s Lane, Suite 300 Houston, TX 77079 Phone: 281-293-8200 Fax: 281-293-8290 E-mail: salesinfo@kbcat.com www.kbcat.com

Other KBC Office Locations London: + 44 (0)1932 242424 Moscow: +7 (0)95 980 8449 Singapore: + 65 6735 5488 Japan: +81 (0)45 290 6380

Downstream

UPS TREAM / DOW NS T R E A M S OF T WA R E R E FE REN CE operating division of KBC, provides specialized software to improve a refineryâ&#x20AC;&#x2122;s and/or a petrochemical facilityâ&#x20AC;&#x2122;s profitability through industry leading models and simulation technology.

Products: KBC offers a wide range of software and associated services, from detailed reactor unit modeling, troubleshooting and monitoring to refinery-wide simulation. KBCâ&#x20AC;&#x2122;s comprehensive kinetic models are the best basis for development of LP vectors, available within a new, streamlined process. Petro-SIMÂŽ and Petro-SIM Express are full-featured, graphical process simulators, featuring Profimatics technology and industry-proven process models. KBC offers unsurpassed model breath and depth that lets you truly model any part of the refinery. KBCâ&#x20AC;&#x2122;s industry-proven Profimatics SIM Suite reactor models include: FCC-SIM (Fluid Cat Cracking), HCR-SIM (Hydrocracker), REFSIM (Reformer), HTR-SIM (Hydrotreater Series), DC-SIM (Delayed Coker), ALK-SIM (Alkylation unit) and VIS-SIM (Visbreaker). New additions include reactor models for C6 Isomerization, Xylene Isomerization, and Aromatics Transalkylation. www.info.hotims.com/26886-412

m:pro IT Consult GmbH Kirchgasse 47 65183 Wiesbaden Germany Phone: +49 611 39843 0 Fax: +49 611 39843 12 E-mail: info@mpro-it.com www.mpro-it.com Matthias Wackenreuther, Enterprise Solutions

systems, forecasting in a phased justified approach. The m:ip enables and improves the use of best-in-class software, plant and business applications = asset maximization. The m:pro object warehouse (m:owh) is our integration, data storage/management, and business intelligence back-end. The m:owh is based on standard and open relational database technology. The m:pro explorer (m:exp) is our feature rich, fully web-enabled common graphical user interface including build and administration tools. The m:exp can run as the portal or can seamlessly be embedded in popular web portal environments. m:pro provides standard applications/interfaces for: â&#x20AC;˘ Production planning, scheduling and blending â&#x20AC;˘ Performance monitoring and dashboards â&#x20AC;˘ Data and process quality â&#x20AC;˘ Information analysis, visualization, flowsheeting, trending and reporting Featured applications/interfaces are: â&#x20AC;˘ Analyzer Monitoring â&#x20AC;˘ Blend Monitoring and Reporting â&#x20AC;˘ Crude Composition Tracking â&#x20AC;˘ Crude Scheduling â&#x20AC;˘ GRTMPS Planning Interface â&#x20AC;˘ Heat Exchanger Monitoring â&#x20AC;˘ KPIs, Operating Envelops, Plan vs Actual â&#x20AC;˘ Lab Interface and Reporting â&#x20AC;˘ LP Data Collector â&#x20AC;˘ Oil Movement Logging â&#x20AC;˘ ORION Scheduling Interface

â&#x20AC;˘ PIMS Planning Interface â&#x20AC;˘ Quality Tracking â&#x20AC;˘ Tank Calculation System www.info.hotims.com/26886-414

M3 Technology, Inc 10850 Richmond Ave., Suite 290 Houston, TX 77042 Phone: +1.713.784.8285 Fax: +1.832.553.1893 E-mail: m3.sales@m3tch.com www.m3tch.com

Company Bio M3 Technology is a leading provider of advanced asset scheduling and optimization solutions for oil refining, petrochemical, natural gas-LNG and terminal operating industries. M3â&#x20AC;&#x2122;s SIMTOâ&#x201E;˘ software captures eco-nomic opportunities and reduces the cost of managing complex facilities at the plant level, regional operating level and global enterprise level.

(AVERLY 3YSTEMS )NC

( #/-%4

Crude Oil Management Evaluation Tool

Revolutionary Web-Based Application With H/COMET you can: â&#x20AC;˘ Quickly access & evaluate crudes from a large assay database â&#x20AC;˘ Select crudes based on user-defined criteria â&#x20AC;˘ Compare crudes side-by-side for any desired qualities â&#x20AC;˘ Re-cut and blend crudes using HaverlyĘźs H/CAMS technology â&#x20AC;˘ Determine netback values of crudes or blends for a variety of refinery configurations.

Visit www.haverly.com to learn more or call us at (973) 627-1424 Select 410 at www.HydrocarbonProcessing.com/RS

Downstream PLANNING, SCHEDULING AND BLENDING, CONT.

specifications and regulatory requirements vary by product grades, seasons, and even local markets.

Products:

SIMTO™ Scheduling SIMTO™ Scheduling—SIMTO™ Scheduling software provides inte-grated scheduling and planning system for the operation of a facility. An operating plant, whether it is a refinery, a petrochemical com-plex, or a terminal, must satisfy its customers’ demands for high quality products and on-time deliveries, while maximizing profits for its stakeholders. The scheduler must respond quickly to changes from market to plant levels and to provide customers with accurate delivery time. The scheduling technology addresses major activities in a plant such as: • scheduling feedstock upload, storage, and tank transfer and scheduling the feeds to process units • scheduling process units, including production yield, quality and reaction processes • scheduling blending and shipments of final products SIMTO Scheduling has comprehensive modeling functions and flexible scheduling features to help a process facility adapt to changing market demands, increase utilization of its finite capacity, and reduce operating costs with controlled inventory. The program’s user-friendly interfaces and visualization technology shield users from the complexities of the production process and yet enhance the comprehension of the plant’s capacity and improve scheduling efficiency. The program’s structure and integration promote coordination and cooperation from the plant level to across the entire enterprise.

SIMTO™ Blending SIMTO™ M-Blend—SIMTO™ M-Blend, multi-period blend recipe optimization, is a solution for product blending, which is a common activity in the process industry and has strong economic and operational impacts. A plant, whether a refinery, petrochemical complex or a blending facility, needs to meet the market’s demands and maximize the plant’s profits, while utilizing its available materials and equipment to blend feedstock or products. Examples include: • A crude mix needs to make the right product slate and still conforms to the metalurgical limits and capacities of processing units. • Gasoline blending involves many blend stocks and additives, stringent quality specifications, and regulatory requirements. Blend stocks vary in quality and quantity from day to day because of variations in the crude mix and unit operation. Quality 20

SOFTWARE REFERENCE

U PSTREA M / D OWN STREA M SOFTWA RE REFER ENC E

FALL 2009

SIMTO M-Blend is comprehensive, yet flexible, user-friendly and able to work well with other systems. It optimizes a blending schedule for a wide range of materials such as crude oil, gasoline, diesel, asphalt, naphtha feedstock and petrochemical products. It automatically generates optimal blend recipes, while considering component rundown rates and qualities, logistic limitations, and shipment requirements. The optimized solution provides options to help a plant minimize cost and quality giveaway.

SIMTO™ Distribution SIMTO™ Distribution—SIMTO™ Distribution facilitates easy decision making for complex business problems involving supply chain planning and distribution. SIMTO Distribution optimizes several parameters of the materials and its movement across the network such as buying, storage, selling, and transportation, lot costs and others. Some of the common problems solved by SIMTO Distribution involve: Optimizing the Supply Chain network across multi-commodities sharing multiple modes of transportation, optimizing the specification and quality blending of materials for oil refining and petrochemical industries, and blend recipe optimization for the process industries. SIMTO Distribution quickly provides optimal solutions for: • The quantity of materials of a type that should be ordered at a location in a given period to meet a demand of a certain type. • The amount of material of a type that should be transported from one location to another. • The mode of transportation that should be selected for a type of material. • The amount of material that should be held for selling in future period based on the sales forecast. SIMTO Distribution empowers planners to provide the Right Product at the Right Place at the Right Time at the Right Price. SIMTO Distribution provides a visual aid for performing the case comparison and enables quick evaluation of What-If scenarios. www.info.hotims.com/26886-415

Products: Soteica’s Scheduling and Operations Manager, S-SOM, is an application for the programming and simulation of refinery and petrochemical plant operations as part of an integrated supply chain model. S-SOM provides detailed models for: • raw material reception • movements in the tank yard • pipeline operations • refinery and petrochemical unit operations • product shipment S-SOM’s objective is to assure the feasibility of the scheduled operations while improving the adherence to the production plan by supporting: • Reaching flow targets • Maintaining quality targets • Maintaining inventory policies • Reducing penalties due to demurrage • Reducing operational complexity (switches) • Reducing material degradation At the same time, it performs rigorous control of the following constraints: • Minimum and maximum tank capacities • Minimum and maximum pumping capacities • Possible alignments (static and dynamic connections topology) • Buffering and decantation policies • Sequencing and delay of material lots in pipelines • Landing and off-shore mooring availability S-SOM provides future visibility through detailed simulation models, presenting constantly updated projections of inventories and material properties. The simulation engine is equipped with an auto-

UPS TR E A M / D OW N S T R E A M SOFTWA RE REFEREN CE matic state event detection mechanism which enables the user to be alerted to critical situations.

they have proven scalability from single-site usage through to global implementations for oil majors.

www.info.hotims.com/26886-420

CrudeSuite Laboratory extends the functionality of CrudeManager to provide an AssayWorkup tool geared around the requirements of crude experts entering full assays, whether from in-house or third party laboratories. In addition, a secure data synchronisation mechanism, CrudeSync, allows users to share information and maintain a central master database of crude oil information.

Spiral Software Ltd St. Andrew’s House St. Andrew’s Road Cambridge, CB4 1DL United Kingdom Phone: +44 (0)1223 445 000 Fax: +44 (0)1223 445 001 E-mail: sales@spiralsoft.com www.spiralsoft.com Spiral also has consultants based in Oklahoma City, OK, and Weston, CT, USA.

Products: Our crude oil assay management tools are designed from the ground up for today’s challenges, allowing companies to benefit from the most recent developments in laboratory measurement, mathematical modelling and information technology. They play a businesscritical role in over 60 companies across over 200 sites around the world, including global implementations by three oil majors. CrudeManager CrudeManager is a powerful tool for managing and manipulating crude oil information. It allows users to search and view crude oil data, display a wide range of graphs and explore the underlying laboratory measurements. Advanced predictive tools allow complete assay data across all properties to be estimated from limited measurement information — whether predicting the properties of a new crude oil, or updating an existing assay to reflect new measurements. Incorporating a multi-tower commercial fractionation model, CrudeManager can provide input directly into a range of industry-standard simulation, optimisation and scheduling packages. CrudeSuite The CrudeSuite assay management tools are designed for use in medium to large size companies, with users across many sites wanting to share and exchange information. Offering granular security control over user access to data and services,

CrudeSuite internet CrudeSuite internet (CSi) provides secure, webbased access to crude oil data and decision support tools. Focussing on the needs of integrated oil companies and energy traders, CSi enables users to maximise profits in trading and refining through a better understanding of crude oil quality and refining performance. Industry-leading software innovations provide unprecedented performance in netback calculations, crude margin estimation and crude and product blending, allowing users to explore opportunities in real time. In only a few seconds, users can explore margin estimates across broad crude slates or generate and assess thousands of blending possibilities. For more information, please refer to the Spiral Software listing in the Economic Evaluation section of the Downstream Software Reference Guide. Crude Oil Assay Libraries Spiral markets a range of assay libraries for use in conjunction with the software tools. The Spiral HPI assay library is shipped as standard with all products. Industry-leading assay libraries from Chevron and Shell are available in a variety of packages including regional and basket format. www.info.hotims.com/26886-421

PLANT LIFECYCLE AND PERFORMANCE MONITORING

KBC Advanced Technologies, Inc. 14701 St. Mary’s Lane, Suite 300 Houston, TX 77079 Phone: 281-293-8200 Fax: 281-293-8290 E-mail: salesinfo@kbcat.com www.kbcat.com

Efficiency Improvements Energy Management

An online Energy Watchdog that assists you with the operation of your utilities systems (steam, fuel, electricity, etc.) to achieve minimum cost within equipment and emissions constraints. Generates energyͲrelated KPIs (Key Performance Indicators). Monitors imbalances allowing you to keep track of leaks, measurement issues and changes in the field. Can be used openͲloop or closedͲloop.

Hydrocarbon Management Hydrocarbon Management

A Production/Yield Accounting system that becomes the foundation for your loss control initiatives. It assists you with your daily sitewide mass balance on a tankͲbyͲtank and unit level. A discrete events simulator is also available to check the feasibility of your operations schedule including your docks, tank yards, process units and pipelines.

Other KBC Office Locations London: + 44 (0)1932 242424 Moscow: +7 (0)95 980 8449 Singapore: + 65 6735 5488 Japan: +81 (0)45 290 6380

Company Bio: KBC Advanced Technologies is a leading independent consulting and technology services group, delivering improvements in business per-

Effective Solutions for Plant Operations Management

USA: +1 (281) 829Ͳ3322 Europe: +34 (93) 375Ͳ3503 Latin America: +54 (11) 4555Ͳ5703

infousa@soteica.com ; www.soteica.com Select 420 at www.HydrocarbonProcessing.com/RS

Downstream PLANT LIFECYCLE AND PERFORMANCE MONITORING, CONT. formance and asset value to owners and operators in the oil refining, petrochemical, and other processing industries worldwide. Profimatics®, an operating division of KBC, provides specialized software to improve a refinery’s and/or a petrochemical facility’s profitability through industry leading models and simulation technology.

Products: KBC offers a wide range of software and associated services, from detailed reactor unit modeling, troubleshooting and monitoring to refinery-wide simulation.

U PSTREA M / D OWN STREA M SOFTWA RE REFER ENC E the Code rules and the practical experience required to implement an effective solution.

Petro-SIM® and Petro-SIM Express are KBC’s full-featured, graphical process simulators, featuring Profimatics technology and industryproven process models. Petro-SIM includes general-purpose unit operations, an extensive component library, a range of thermodynamics packages, and innovative methods to fully integrate the software with plant information systems, databases, and Excel, and the LP.

• ASME Section VIII, Division 2

KBC offers unsurpassed model breath and depth that lets you truly model any part of the refinery. KBC’s industry-proven Profimatics SIM Suite reactor models include: FCC-SIM (Fluid Cat Cracking), HCR-SIM (Hydrocracker), REFSIM (Reformer), HTR-SIM (Hydrotreater Series), DC-SIM (Delayed Coker), ALK-SIM (Alkylation unit) and VIS-SIM (Visbreaker). New additions include reactor models for C6 Isomerization, Xylene Isomerization, and Aromatics Transalkylation.

• Coster (creates Excel compatible vessel cost estimates)

www.info.hotims.com/26886-412

PREDICTIVE MAINTENANCE AND REPAIR

• Heat Exchangers (includes TEMA Standard, ASME UHX rules, tube field layout capability and bi-directional interface with HTRI’s Xchanger Suite) • Drafter (converts COMPRESS files into AutoCAD drawings)

COMPRESS generates both detailed and abbreviated reports, the former suitable for use as a calculation audit trail. COMPRESS also generates ASME U forms and NBIC R forms. Once finalized, forms can be saved in PDF or EDT compliant format. EDT compliant files can be directly submitted to the National Board electronically. To simplify document management, a new “Project” feature allows users to organize, view and backup files of any type from within COMPRESS. Visit www.codeware.com to download your complimentary COMPRESS trial software today. www.info.hotims.com/26886-405

ware and consulting strategies that maximize equipment operational availability, control inspection costs and avoid costly shutdowns.

Codeware, Inc. Codeware, Inc. 5224 Station Way Sarasota, FL 34233 United States Phone: (941) 927-2670 Fax: (941) 927-2459 E-mail: inquiries@codeware.com www.codeware.com

SOFTWARE REFERENCE

FALL 2009

Downstream

UPS TREAM / DOW NS T R E A M S OF T WA R E R E FE REN CE

PROCESS ENGINEERING AND SIMULATION

• Expert Systems (‘es-solutions’) are application-specific bundles that talk the specific engineering language required. They can be viewed as ‘packaged consultancy’ since they are honed for solving particular application challenges. www.info.hotims.com/26886-403

new process design or working in the plant.

COMPRESS ™ Simplify ASME VIII Code Calculations We have the expertise needed to understand the complexities of the Code rules and the practical experience required to implement an effective solution. Let COMPRESS be your expert assistant. x

Intuitive interface

Code rule reminders during input

ASME U and NBIC R form generation

New “Project” view

DOWNLOAD YOUR TRIAL SOFTWARE TODAY www.codeware.com

Select 405 at www.HydrocarbonProcessing.com/RS 23

Downstream PROCESS ENGINEERING AND SIMULATION, CONT. CC-FLASH Physical Propertieis & Phase Equilibria Calculation Software - A subset of the CHEMCAD Suite (all of the CHEMCAD Suite products include CC-FLASH capabilities), this program allows rigorous calculation of pure component and mixture physical properties and phase equilibria (VLE, LLE, VLLE). www.info.hotims.com/26886-404

Codeware, Inc. Codeware, Inc. 5224 Station Way Sarasota, FL 34233 United States Phone: (941) 927-2670 Fax: (941) 927-2459 E-mail: inquiries@codeware.com www.codeware.com

U PSTREA M / D OWN STREA M SOFTWA RE REFERENCE software for the design and analysis of ASME vessels and exchangers. Codeware’s Austin, Texas based development team has the expertise needed to understand the complexities of the Code rules and the practical experience required to implement an effective solution.

Visit www.codeware.com to download your complimentary COMPRESS trial software today. www.info.hotims.com/26886-405

To tailor COMPRESS to your needs, the following optional modules are available: • ASME Section VIII, Division 2

Heat Transfer Research, Inc.

• Heat Exchangers (includes TEMA Standard, ASME UHX rules, tube field layout capability and bi-directional interface with HTRI’s Xchanger Suite)

Worldwide

Company Bio:

• Drafter (converts COMPRESS files into AutoCAD drawings)

Since 1985, Codeware has focused exclusively on providing the most comprehensive

• Coster (creates Excel compatible vessel cost estimates) What do you expect from your Engineering Simulation Software? Productivity Accuracy Flexibility Expertise

t: Visit us a

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Select 403 at www.HydrocarbonProcessing.com/RS 24

Asia - Pacific Heat Transfer Research, Inc. World Business Garden Marive East 14F Nakase 2-6, Mihamaku Chiba 261-7114 Japan Phone: 81-43-297-0353 Fax: 81-43-297-0354 E-mail: HTRI.Asia@HTRI.net Hirohisa Uozu, Regional Mgr.

India C-1, First Floor, Tower-B “Indraprasth Complex” Near Inox Multiplex, Race Course (North) Vadodara 390007, Gujarat, India Phone: +91 (982) 514-7775 HTRI.India@HTRI.net Rajan Desai, International Coordinator

UPS TREAM / DOW NS T R E A M S OF T WA R E R E FE REN CE

PRODUCTION/YIELD ACCOUNTING

other services including contract research, software development, consulting, and training.

Products: HTRI Xchanger Suite—Integrated graphical user environment for the design, rating, and simulation of heat transfer equipment. Xace—Designs, rates, and simulates the performance of air-cooled heat exchangers, heat recovery units, and air preheaters. Xfh—Simulates the behavior of fired heaters. Calculates the radiant section of cylindrical and box heaters and the convection section of fired heaters. It also designs process heater tubes and performs combustion calculations. Xhpe—Designs, rates, and simulates the performance of hairpin heat exchangers. Xist—Designs, rates, and simulates single- and two-phase shell-and-tube heat exchangers, including kettle and thermosiphon reboilers, falling film evaporators, and reflux condensers. Xjpe—Designs, rates, and simulates jacketedpipe (double-pipe) heat exchangers. Xphe—Designs, rates, and simulates plate-andframe heat exchangers. A fully incremental program, each plate channel is calculated individually using local physical properties and process conditions. Xspe—Rates and simulates single-phase spiral plate heat exchangers. Xtlo—Graphical standalone rigorous tube layout software; also integrated with Xist. Xvib—Performs flow-induced vibration analysis of a single tube in a heat exchanger bundle. It uses a rigorous structural analysis approach to calculate the tube natural frequencies for various modes and offers flexibility in the geometries it can handle. Xchanger Suite Educational—Customized version of Xchanger Suite with the capability to design, rate, and simulate shell-and-tube heat exchangers, air-coolers, economizers, and plateand-frame heat exchangers. Available to educational institutions only. R-trend—Calculates and trends fouling resistances for shell-and-tube heat exchangers in single-phase service. Uses Microsoft Excel as working environment with optional link to Xist. www.info.hotims.com/26886-411

Downstream

KBC Advanced Technologies, Inc. 14701 St. Mary’s Lane, Suite 300 Houston, TX 77079 Phone: 281-293 8200 Fax: 281-293 8290 E-mail: salesinfo@kbcat.com www.kbcat.com

Other KBC Office Locations: London: Moscow: Singapore: Japan:

+ 44 (0)1932 242424 +7 (0)95 980 8449 + 65 6735 5488 +81 (0)45 290 6380

Products: KBC offers a wide range of software and associated services, from detailed reactor unit modeling and monitoring to refinery-wide simulation. Petro-SIM® and Petro-SIM Express are KBC’s full-featured, graphical process simulators, featuring Profimatics technology and industry-proven process models. Petro-SIM includes general-purpose unit operations, an extensive component library, a range of thermodynamics packages, and innovative methods to fully integrate the software with plant information systems, databases, and Excel, and the LP. KBC offers unsurpassed model breath and depth that lets you truly model any part of the refinery. KBC’s industry-proven Profimatics SIM Suite reactor models include: FCC-SIM (Fluid Cat Cracking), HCRSIM (Hydrocracker), REF-SIM (Reformer), HTR-SIM (Hydrotreater Series), DC-SIM (Delayed Coker), ALK-SIM (Alkylation unit) and VIS-SIM (Visbreaker). New additions include reactor models for C6 Isomerization, Xylene Isomerization, and Aromatics Transalkylation. www.info.hotims.com/26886-412

Products: Soteica’s Production/Yield Accounting package, S-TMS, is a web application that enables users to model inventories and material movements typical of the process industry by providing: • Advanced dynamic graphical environment for gross error and reconciliation analysis • Intelligent connectors for Import / Export information from / to other systems (Historians, ERP, Planning, etc.). • Screen forms for all data capture (both manual and from other systems). • Inventories, flows and movement quantities calculations • Tracking of material changes in tanks (Reclassifications / Regradings) • Crude tanks composition calculation • State of the art data reconciliation engine • Pipeline module. • Planned vs. Real Tracking • Report Editor and a complete off-the-shelf set of standard reports • MS-Excel integration S-TMS enables the user to: • Implement a Loss Reduction initiative at the site. • Acquire a better and detailed knowledge of plant and tank farm operations and movements • Improve data quality and operating procedures • Detect gross errors in early stages (data entry errors, instrument failure, missing movements) • Systematically analyze plant measurement errors and custody transfer points, which results in a more focused instrumentation maintenance program • Have better information for Planning and ERP www.info.hotims.com/26886-420 F A L L 2009

SOFTWARE REFERENCE

Downstream REFINING, PETROCHEMICAL AND GAS PROCESSING

CD-adapco

U PSTREA M / D OWN STREA M SOFTWA RE REFER ENC E neering language required. They can be viewed as ‘packaged consultancy’ since they are honed for solving particular application challenges. www.info.hotims.com/26886-403

60 Broadhollow Road Melville, NY 11747 Phone: 248-246-5803 Phone: 631-549-2300 Fax: 208-575-2685 E-mail: dennis.nagy@us.cd-adapco.com www.cd-adapco.com Dennis Nagy, VP Marketing & Business Development

The Equity Engineering Group, Inc.

Company Bio:

Products: CD-adapco’s solutions (software and related consulting services, training, and mentoring) are widely used across many industries, including oil and gas, chemical process, marine, offshore structures, turbomachinery, automotive, aerospace, building systems, electronics, environmental, pharmaceuticals, power generation, rail, and specialized mechanical engineering applications. The technology-leading Computational Fluid Dynamics flow, thermal, and stress simulation (CFD/CAE) STAR codes have outstanding capabilities for handling complex fluid flow and heat transfer problems including transient flows, chemical reaction, free-surface flows, combustion, rotating systems, multiphase and multiphysics. There are four ways in which CD-adapco delivers its CFD technology in software: • STAR-CCM+ is a radically new full-spectrum CFD/CAE processing environment that features the latest object-oriented methods and ergonomically designed GUI for streamlined integration into any company’s engineering process. Solutions on polyhedral cells enable faster and more accurate solutions than any other of the world’s legacy CFD codes. • STAR-CD remains the world’s most advanced CFD code, comes with advanced pre-processing tools, and is now enhanced by the inclusion of any one of the environments from the STAR-CAD Series. • STAR-CAD Series is a range of products that deliver non-complex CFD in an easy to use CAD-embedded environment • Expert Systems (‘es-solutions’) are application-specific bundles that talk the specific engi26

SOFTWARE REFERENCE

FALL 2009

20600 Chagrin Blvd., Suite 1200 Shaker Heights, OH 44122 Phone: 216-283-9519 Fax: 216-283-6022 E-mail: gcalvarado@eng.com www.equityeng.com Greg Alvarado, VP Sales and Client Service

as training in other engineering disciplines. The software courses, designed to help both the novice and experienced user make more effective use of the software, emphasize both hands-on training and in-class example problems. Public courses are held at E2G offices in Cleveland and Houston, or private courses can be held at your site. To find out more about E2G training courses, go to www.equityeng.com. www.info.hotims.com/26886-406

Heat Transfer Research, Inc. Worldwide 150 Venture Drive College Station, TX 77845 USA Phone: 979-690-5050 Fax: 979-690-3250 E-mail: HTRI@HTRI.net www.HTRI.net Claudette D. Beyer, President and CEO Fernando J. Aguirre, VP, Sales and Business Development

UPS TREAM / DOW NS T R E A M S OF T WA R E R E FE REN CE

Products:

Fax: +44 (0)1606 815151 E-mail: energy@kbcat.com www.kbcat.com/lm

HTRI Xchanger Suite—Integrated graphical user environment for the design, rating, and simulation of heat transfer equipment. Xace—Designs, rates, and simulates the performance of air-cooled heat exchangers, heat recovery units, and air preheaters. Xfh—Simulates the behavior of fired heaters. Calculates the radiant section of cylindrical and box heaters and the convection section of fired heaters. It also designs process heater tubes and performs combustion calculations.

Downstream Company Bio:

KBC Linnhoff March Energy Services Targeting House Gadbrook Park Northwich, Cheshire CW9 7UZ UK Phone: +44 (0)1606 815100

KBC Advanced Technologies is a leading independent consulting and technology services group, delivering improvements in business performance and asset value to owners and operators in the oil refining, petrochemical, and other processing industries worldwide. Linnhoff March, an operating division of KBC, provides process and utility integration through a range

Xhpe—Designs, rates, and simulates the performance of hairpin heat exchangers. Xist—Designs, rates, and simulates single- and two-phase shell-and-tube heat exchangers, including kettle and thermosiphon reboilers, falling film evaporators, and reflux condensers. Xjpe—Designs, rates, and simulates jacketedpipe (double-pipe) heat exchangers. Xphe—Designs, rates, and simulates plate-andframe heat exchangers. A fully incremental program, each plate channel is calculated individually using local physical properties and process conditions. Xspe—Rates and simulates single-phase spiral plate heat exchangers. Xtlo—Graphical standalone rigorous tube layout software; also integrated with Xist. Xvib—Performs flow-induced vibration analysis of a single tube in a heat exchanger bundle. It uses a rigorous structural analysis approach to calculate the tube natural frequencies for various modes and offers flexibility in the geometries it can handle. Xchanger Suite Educational—Customized version of Xchanger Suite with the capability to design, rate, and simulate shell-and-tube heat exchangers, air-coolers, economizers, and plateand-frame heat exchangers. Available to educational institutions only. R-trend—Calculates and trends fouling resistances for shell-and-tube heat exchangers in single-phase service. Uses Microsoft Excel as working environment with optional link to Xist. www.info.hotims.com/26886-411

Select 406 at www.HydrocarbonProcessing.com/RS 27

Downstream REFINING, PETROCHEMICAL AND GAS PROCESSING, CONT. of software and services to help reduce capital expenditures and energy/utility requirements.

Products: SuperTarget® is the definitive tool for energy Pinch Analysis. With SuperTarget, you can reduce process energy requirements, reduce capital investment, obtain maximum benefit from planned capital improvements and improve process throughput by eliminating energy bottlenecks. Applied in a new design or retrofit situations, it will help identify cost-effective targets for energy integration, design practical heat exchanger networks, and optimally match utility supply to process demand. The software has been proven for more than a decade—improving the profitability of thousands of processes by identifying optimal opportunities for process and utility integration. ProSteam® software helps optimize the design of site utility systems. The Excel® spreadsheet add-in provides drawing tools and easy access to steam and water properties together with an impressive library of utility system equipment models. ProSteam builds on the successful base of its predecessor, Steam97, which has been applied to hundreds of systems worldwide to determine the true cost/benefit of design, and

U PSTREA M / D OWN STREA M SOFTWA RE REFERENCE operational changes by accurately determining their influence on purchased power and fuel. WaterTarget is a software suite enabling the efficient use and re-use of water to minimize the cost of consuming, treating and discharging water and to minimize capital expenditure on treatment facilities. The suite comprises two components—WaterTracker for generating reconciled water balances with minimal flow and contaminant measurements and WaterPinch for the design of optimal water networks and wastewater treatment strategies. www.info.hotims.com/26886-412

KBC Advanced Technologies, Inc. 14701 St. Mary’s Lane, Suite 300 Houston, TX 77079 Phone: 281-293-8200 Fax: 281-293-8290 E-mail: salesinfo@kbcat.com www.kbcat.com Other KBC Office Locations London: + 44 (0)1932 242424 Moscow: +7 (0)95 980 8449 Singapore: + 65 6735 5488 Japan: +81 (0)45 290 6380

Products: KBC offers a wide range of software and associated services, from detailed reactor unit modeling and monitoring to refinery-wide simulation. Petro-SIM® and Petro-SIM Express are KBC’s full-featured, graphical process simulators, featuring Profimatics technology and industryproven process models. Petro-SIM includes general-purpose unit operations, an extensive component library, a range of thermodynamics packages, and innovative methods to fully integrate the software with plant information systems, databases, and Excel, and the LP. KBC offers unsurpassed model breath and depth that lets you truly model any part of the refinery. KBC’s industry-proven Profimatics SIM Suite reactor models include: FCC-SIM (Fluid Cat Cracking), HCR-SIM (Hydrocracker), REF-SIM (Reformer), HTR-SIM (Hydrotreater Series), DC-SIM (Delayed Coker), ALK-SIM (Alkylation unit) and VIS-SIM (Visbreaker). New additions include reactor models for C6 Isomerization, Xylene Isomerization, and Aromatics Transalkylation. www.info.hotims.com/26886-412

M3 Technology, Inc 10850 Richmond Ave., Suite 290 Houston, TX 77042 Phone: +1.713.784.8285 Fax: +1.832.553.1893 E-mail: m3.sales@m3tch.com www.m3tch.com

Company Bio M3 Technology is a leading provider of advanced asset scheduling and optimization solutions for oil refining, petrochemical, natural gas-LNG and terminal operating industries. M3’s SIMTO™ software captures economic opportunities and reduces the cost of managing complex facilities at the plant level, regional operating level and global enterprise level.

Select 415 at www.HydrocarbonProcessing.com/RS 28

UPS TREAM / DOW NS T R E A M S OF T WA R E R E FE REN CE

Products:

SIMTO™ Refining

SIMTO™ Refinery Solution is an integrated solution for refinery planning and scheduling management. The solution covers refinery activities from feedstock to products, from receiving to shipping, from corporate to plant planning, and from internal to external scheduling: • Summarizing multi-site schedule data across the supply chain to communicate among enterprise applications and to share with traders, managers, and enterprise personnel. • Planning activities across the enterprise on a single user-interface to integrate data from multiple sources, improve data compre-hension, and increase outcome visibility. • Optimizing product movements in the supply chain to minimize costs. • Scheduling feedstock receipts, processing unit operations, and product shipments to improve utilization of assets. • Optimizing blends of feedstock and products for multiple periods to comply with equipment limitations, improve yields, meet quality specifications, and deliver products on schedule. • Scheduling receiving and shipping docks or terminals with considerations for constraints in weather, traffic, vessels, berths, and inventories. • Integrating planning and scheduling activities in an enterprise solution to facilitate communication and enhance coordination and cooperation. www.info.hotims.com/26886-415

SIS / SAFETY SYSTEMS

exida 64 North Main Street Sellersville, PA 18960 Phone: 215-453-1720 Fax: 215-257-1657 E-mail: Info@exida.com www.exida.com Iwan van Beurden, Senior Safety Engineer, Iwan.vanbeurden@exida.com

Company Bio: exida is an engineering consulting firm specializing in safety critical and high availability automation systems. Core competencies in design, analysis, implementation, operation, and maintenance of critical automation systems has allowed exida to develop an extensive suite of software tools that assist in the implementation of the Safety Lifecycle.

Downstream

Products:

exSILentiaT Safety Lifecycle Tool: exSILentiaT Integrates SILect (Safety Integrity Level selection), SIF SRS (Safety Requirements Specification), and SILver (Safety Integrity level verification), covering three important activities for functional safety standard compliance. exSILentia lets the user define a project consisting of one or more Safety Instrumented Functions. It also manages your project documentation with an easy report generation In RTF (for use with a word processor program like Microsoft Word). Sharing data for multi-person projects or for independent review has become easier than ever with the built-in exSILentia import /export functionality.

API RBI Software is the industry standard for plant risk management, developed through the API consensus standards process and documented in API 581. It provides risk values and metrics for equipment, enabling plants to identify areas of potential failure and prioritize inspection dollars based on measured risk. Modules include fixed equipment, heat exchanger bundles, atmospheric storage tanks, and pressure relief systems.

exSILentia provides fully customizable SIL selection options like risk graph, hazard matrix, and frequency based targets. In addition, a complete SIF SRS template ensures completeness in requirements definition. exSILentia contains the most comprehensive SIL verification program, SILver, allowing extensive Safety Instrumented Function definition, and an IEC 61508-approved calculation engine based on the Markov Modeling technique. Finally exSILentia has direct access to the exida Safety Equipment Reliability Handbook equipment items, speeding up the process of SIL verification by allowing users to simply select equipment items from the Handbook without having to enter reliability data. For more information, please visit www.exSILentia.com. www.info.hotims.com/26886-407

TRAINING

VCESage™ is a collection of modules providing an easy-to-use computerized design/analysis resource consistent with the new API 579-1/ ASME FFS-1 standard. The modules enable users to review and/or analyze existing and new equipment for structural integrity, code compliance, re-rating and remaining life evaluations. VCEDamage Mechanisms™ is a quick reference guide to identify the potential damage mechanisms that can cause equipment failure. It guides users through the damage mechanism identification process, helps in selecting the best inspection method for each damage type, and provides simplified Process Flow Diagrams showing where damage will likely occur. VCEIntelliJoint™ offers a total solution to bolted joint leakage with the latest advanced bolted joint technology, including assembly procedures and gasket test results. The program provides industry best practice gasket specifications and incorporates knowledge in areas required to effectively identify the root cause of a leakage problem. Training Equity Engineering offers software training for the API RBI and VCESage™ programs, as well as training in other engineering disciplines. The software courses, designed to help both the novice and experienced user make more effective use of the software, emphasize both hands-on training and in-class example problems. Public courses are held at E2G offices in Cleveland and Houston, or private courses can be held at your site. To find out more about E2G training courses, go to www.equityeng.com. www.info.hotims.com/26886-406

F A L L 2009

SOFTWARE REFERENCE

U PSTREA M / D OWN STREA M SOFTWA RE REFERENCE

BOXSCORE DATA BASE

ONLINE

www.ConstructionBoxscore.com

2009

NEW PROJECTS BEING ADDED AT A RATE OF 40 PER WEEK!

Export searches to Excel Access to www.HydrocarbonProcessing.com Posted press releases of project announcements 2009 HPI Market Data Book Process Handbooks online: Reﬁning, Petrochemical, Gas Processing, Advanced Control Improved user interface

Contact: Lee Nichols

Phone: +1 (713) 525-4626

E-mail: Lee.Nichols@GulfPub.com

UPS TREAM / DOW NS T R E A M S OF T WA R E R E FE REN CE

PIPELINE ENGINEERING AND FLUID FLOW

Business Management Midstream

Products: CD-adapco’s solutions (software and related consulting services, training, and mentoring) are widely used across many industries, including oil and gas, chemical process, marine, offshore structures, turbomachinery, automotive, aerospace, building systems, electronics, environmental, pharmaceuticals, power generation, rail, and specialized mechanical engineering applications. The technology-leading Computational Fluid Dynamics flow, thermal, and stress simulation (CFD/CAE) STAR codes have outstanding capabilities for handling complex fluid flow and heat transfer problems including transient flows, chemical reaction, free-surface flows, combustion, rotating systems, multiphase and multiphysics. There are four ways in which CD-adapco delivers its CFD technology in software: • STAR-CCM+ is a radically new full-spectrum CFD/CAE processing environment that features the latest object-oriented methods and ergonomically designed GUI for streamlined integration into any company’s engineering process. Solutions on polyhedral cells enable faster and more accurate solutions than any other of the world’s legacy CFD codes. • STAR-CD remains the world’s most advanced CFD code, comes with advanced pre-processing tools, and is now enhanced by the inclusion of any one of the environments from the STAR-CAD Series. • STAR-CAD Series is a range of products that deliver non-complex CFD in an easy to use CAD-embedded environment

ASSET MANAGEMENT

and specific use history, leading to significant operational time and materials savings, reduced risk of a catastrophic string failure and increased human safety due to proper utilization of assets. RFID features include: • Various durable and rugged tags and mounting methods for different components including drill pipe, casing, production tubing and other downhole, sub-sea and surface equipment components • Tags are rated for sustained temperature and pressure expected under harsh drilling and operating conditions • Tags can be installed during the component manufacturing process or retrofitted in the field • RFID data is linked to corporate-wide asset management, maintenance management and ERP systems including Merrick’s Rig-Hand and CATS software or any in-house asset tracking system www.info.hotims.com/26886-416

DATA MANAGEMENT

Company Bio: Merrick Systems helps oil and gas companies to take control of their operations with the industry’s most robust software and hardware solutions addressing production operations, engineering and asset tracking. Recognized for its industry expertise and innovative technologies, Merrick is committed to delivering best of breed solutions to improve production operations, helping companies extend oil and gas producing asset life, lower lifting costs, increase production and optimize operations. Merrick’s integrated applications include realtime surveillance and optimization; field operations management; field data capture; hydrocarbon production accounting; mobile computing for field and drilling operations; engineering workflow orchestration and ruggedized RFID for drilling and asset management.

Products: RFID – Merrick’s RFID-based system is designed to track high-value operationally critical downhole, sub-sea and surface equipment used in drilling and production operations offshore and onshore. The system tracks drill pipe, risers, BOP’s, manifolds, valves and any asset used in harsh environments where traditional tracking methods fail. The system includes Merrick’s rugged Diamond RFID Tags that can withstand extreme conditions typical of drilling environments, Rig-HandTM and CATSTM software for drill site and corporate solutions, hand-held readers and helpful tools for easy implementation. The Diamond Tags can survive sustained pressures of up to 20,000 PSI and temperatures of up to 182°C (360°F) and can be read through drilling mud, diesel fuels, oils, sea water and concrete. Certified for Class1, Div1 or Zone1, the tags allow drilling operators, equipment rental companies and OEM manufacturers to affix an asset identifier that will survive drilling operations. The tags can track the asset location

geoLOGIC systems ltd. 900, 703 6 Avenue SW Calgary, AB Canada T2P 0T9 Phone: 403 262-1992 Fax: 403-262-1987 E-mail: sales@geologic.com www.geologic.com Andrea Hood, VP Business Development & Sales

SOFTWARE REFERENCE

Midstream Upstream DATA MANAGEMENT, CONT. petroCUBETM is an innovative suite of products that provide unbiased, consistent statistical insights that can help you make more profitable decisions about petroleum plays. From reserve and production data through to full-cycle economics, petroCUBE gives you immediate access to a full spectrum of current geostatistical, technical and financial information and comprehensive analytical tools. petroCUBE instantly delivers the data engineers and geologists need to accurately assess risk and justify exploration and development proposals before wells are drilled.

U PSTREA M / D OWN STREA M SOFTWA RE REFER ENC E

petroCUBETM is an innovative suite of products that provide unbiased, consistent statistical insights that can help you make more profitable decisions about petroleum plays. From reserve and production data through to full-cycle economics, petroCUBE gives you immediate access to a full spectrum of current geostatistical, technical and financial information and comprehensive analytical tools. petroCUBE instantly delivers the data engineers and geologists need to accurately assess risk and justify exploration and development proposals before wells are drilled. www.info.hotims.com/26886-408

www.info.hotims.com/26886-408

DATA VISUALIZATION PIXOTEC, LLC

geoLOGIC systems ltd. 900, 703 6 Avenue SW Calgary, AB Canada T2P 0T9 Phone: 403 262-1992 Fax: 403-262-1987 E-mail: sales@geologic.com www.geologic.com Andrea Hood, VP Business Development & Sales

SOFTWARE REFERENCE

FALL 2009

15917 SE Fairwood Blvd. Renton, WA 98058 US Phone: 425-255-0789 Fax: 425-917-0104 E-mail: info@slicerdicer.com www.slicerdicer.com Skip Echert, Director of Marketing

Company Bio: PIXOTEC, LLC specializes in the development of software for the analysis of complex data in three or more dimensions. Dr. David Lucas, the originator of Slicer Dicer, heads the software development efforts and is co-owner of PIXOTEC. Slicer Dicer® and its precursors have been under development since the late 80s.

Products: Slicer Dicer - Volumetric Data Visualization Software for Windows, is designed for geoscientists and engineers involved with complex data defined in three or more dimensions. This easyto-use tool is employed for the analysis of seismic data and geological model outputs. It has users in over 50 countries. The latest version of Slicer Dicer, v5, includes 3VOTM Slicer Dicer’s powerful new 3D viewer. It simplifies rotating, zooming, and other manipulations of your data scene, all by simply moving your mouse. With Slicer Dicer, you can explore your multidimensional volume data visually by “slicing and dicing” to create arbitrary orthogonal and oblique slices, rectilinear blocks and cutouts, isosurfaces, and projected volumes. You can generate animation sequences featuring continuous rotation, moving slices, blocks, parametric variation (time animation), oblique slice rotation, and varying transparency. Use the new 3VOTM viewer to easily rotate, zoom, control lighting and light reflection, and change the center of rotation of your data image. Pricing for Slicer Dicer starts at only $495. Go to our web site, SlicerDicer.com, to download a full-featured demo that is limited only by a 15-day trial period. Low-cost upgrades from

previous versions of Slicer Dicer are also available from the SlicerDicer.com web site. www.info.hotims.com/26886-419

DESIGN, CONSTRUCTION AND ENGINEERING

Products: CD-adapco’s solutions (software and related consulting services, training, and mentoring) are widely used across many industries, including oil and gas, chemical process, marine, offshore structures, turbomachinery, automotive, aerospace, building systems, electronics, environmental, pharmaceuticals, power generation, rail, and specialized mechanical engineering applications. The technology-leading Computational Fluid Dynamics flow, thermal, and stress simulation (CFD/CAE) STAR codes have outstanding capabilities for handling complex fluid flow and heat transfer problems including transient flows, chemical reaction, free-surface flows, combustion, rotating systems, multiphase and multiphysics. There are four ways in which CD-adapco delivers its CFD technology in software: • STAR-CCM+ is a radically new full-spectrum CFD/CAE processing environment that features the latest object-oriented methods and ergonomically designed GUI for streamlined integration into any company’s engineering process. Solutions on polyhedral cells enable faster and more accurate solutions than any other of the world’s legacy CFD codes. • STAR-CD remains the world’s most advanced CFD code, comes with advanced pre-processing tools, and is now enhanced by the inclusion of any one of the environ-

UPS TREAM / DOW NS T R E A M S OF T WA R E R E FE REN CE ments from the STAR-CAD Series. • STAR-CAD Series is a range of products that deliver non-complex CFD in an easy to use CAD-embedded environment • Expert Systems (‘es-solutions’) are applicationspecific bundles that talk the specific engineering language required. They can be viewed as ‘packaged consultancy’ since they are honed for solving particular application challenges. www.info.hotims.com/26886-403

Heat Transfer Research, Inc. Worldwide

Business Management Upstream Midstream

DRILLING ENGINEERING

Products: CD-adapco’s solutions (software and related consulting services, training, and mentoring) are widely used across many industries, including oil and gas, chemical process, marine, offshore structures, turbomachinery, automotive, aerospace, building systems, electronics, environmental, pharmaceuticals, power generation, rail, and specialized mechanical engineering applications. The technology-leading Computational Fluid Dynamics flow, thermal, and stress simulation (CFD/CAE) STAR codes have outstanding capabilities for handling complex fluid flow and heat transfer problems including transient flows, chemical reaction, free-surface flows, combustion, rotating systems, multiphase and multiphysics. There are four ways in which CD-adapco delivers its CFD technology in software: • STAR-CCM+ is a radically new full-spectrum CFD/CAE processing environment that features the latest object-oriented methods and ergonomically designed GUI for streamlined integration into any company’s engineering process. Solutions on polyhedral cells enable faster and more accurate solutions than any other of the world’s legacy CFD codes. • STAR-CD remains the world’s most advanced CFD code, comes with advanced pre-processing tools, and is now enhanced by the inclusion of any one of the environments from the STAR-CAD Series. • STAR-CAD Series is a range of products that deliver non-complex CFD in an easy to use CAD-embedded environment • Expert Systems (‘es-solutions’) are application-specific bundles that talk the specific engiF A L L 2009

SOFTWARE REFERENCE

Midstream Upstream DRILLING ENGINEERING, CONT. neering language required. They can be viewed as ‘packaged consultancy’ since they are honed for solving particular application challenges.

U PSTREA M / D OWN STREA M SOFTWA RE REFER ENC E accurately assess risk and justify exploration and development proposals before wells are drilled. www.info.hotims.com/26886-408

FIELD DATA CAPTURE

www.info.hotims.com/26886-403

www.info.hotims.com/26886-416

EXPLORATION Merrick Systems, Inc.

geoLOGIC systems ltd. 900, 703 6 Avenue SW Calgary, AB Canada T2P 0T9 Phone: 403 262-1992 Fax: 403-262-1987 E-mail: sales@geologic.com www.geologic.com Andrea Hood, VP Business Development & Sales

Products: geoSCOUTTM is a fully integrated, Windowsbased exploratory system that combines presentation-quality mapping and cross-section tools with data handling and analysis software. It integrates public and proprietary data on wells, well logs (Raster and LAS), land, pipelines and facilities, fields and pools, and seismic studies. It includes powerful, easy-to-use tools for searching, viewing, mapping, reporting, graphing, analysis and managing information. The gDCTM (geoLOGIC Data Center) is an online exploration information system that gives users instant access, through their choice of software, to high quality data in the open Public Petroleum Data Model. Extremely fast and reliable, the gDC gives access to general well data, including geoLOGIC Tops, Original Operator data, DST and other well test data, directional well data, land data, and LAS and Raster log data. petroCUBETM is an innovative suite of products that provide unbiased, consistent statistical insights that can help you make more profitable decisions about petroleum plays. From reserve and production data through to full-cycle economics, petroCUBE gives you immediate access to a full spectrum of current geostatistical, technical and financial information and comprehensive analytical tools. petroCUBE instantly delivers the data engineers and geologists need to

SOFTWARE REFERENCE

tential out of order sequencing as the drill string is being made up, a graphic on the handheld will inform the toolpusher of possible thread mismatches. The ease of scanning tags with a single button click on the handheld, even with gloved use, makes it possible to facilitate normal drilling operations speed while maintaining accuracy.

FALL 2009

4801 Woodway, Suite 200E Houston, TX 77056 Toll Free: 800-842-8389 Phone: 713-579-3400 Fax: 713-579-3499 E-mail: sales@MerrickSystems.com www.MerrickSystems.com Faisal Kidwai, V.P. Sales Faisal.Kidwai@MerrickSystems.com

Products: eVIN eVIN provides Pocket PC and PC-based field data capture with on-line AGA calculations, error checking, data validation and graphing. Over 1,000 field operators use eVIN daily for quick data entry using the same process of collecting data as their gauge sheet. This means data is formatted by route, stop/battery, and equipment (well completions, meters, tanks, etc.) and can be sorted by the operator as needed. Once the pumper is done entering information for the day, data can be validated using the end route review screen to highlight discrepancies when comparing 7-day average readings prior to syncing with the main office. When data is ready to be sent, a single press of the ‘send/receive button’ transmits data either remotely or connected directly (via Citrix) to the database server in the main office. RFID-Based rugged handheld system for asset tracking at rig-site and inspection yard operations both intrinsically safe and non-intrinsic. For rig operations, a drill string schematic is automatically created as the tagged drill pipe components are scanned providing the toolpusher with an accurate tally of what is going in and out of the hole and in the correct sequence. For any po-

OPERATIONS

UPS TREAM / DOW NS T R E A M S OF T WA R E R E FE REN CE • STAR-CD remains the world’s most advanced CFD code, comes with advanced pre-processing tools, and is now enhanced by the inclusion of any one of the environments from the STAR-CAD Series. • STAR-CAD Series is a range of products that deliver non-complex CFD in an easy to use CAD-embedded environment • Expert Systems (‘es-solutions’) are application-specific bundles that talk the specific engineering language required. They can be viewed as ‘packaged consultancy’ since they are honed for solving particular application challenges. www.info.hotims.com/26886-403

Business Management Upstream Midstream

lyzing and exporting daily and monthly oil & gas production trends. Catch potential production areas before they become problems. • PetroRegs – Complete regulatory compliance modules for state and MMS reporting • RIO – Technical corporate data warehouse for production and G&G information on well completion and reservoir information coming from operated and non-operated wells. • One Virtual Source (OVS) – Engineering workflow framework for production operations and reservoir management, incorporating realtime engineering data management, integration and visualization, GIS, engineering workflow management, collaboration and analytics, into one desk-top environment. • RFID-Based Asset Tracking System for tracking down-hole, subsea and surface equipment onshore and offshore. The system includes a portfolio of fitfor-purpose tags, Rig-Hand and CATS software for drill-site and corporate-wide asset tracking. www.info.hotims.com/26886-416

PROCESS ENGINEERING AND SIMULATION

Products: Merrick’s suite of products provides a complete production and drilling management solution. From the field to the back office, all of your data is integrated into a single system: • eVIN – Pocket PC and PC-based field data capture system designed for simple, fast and efficient entry of daily readings with field validation and AGA calculations built in. • ProCount – Comprehensive hydrocarbon accounting solution that manages simple and complex daily and monthly production allocations, including full component allocations with over 100 standard reports included. • Carte – Web based production monitoring and reporting tool for viewing, graphing, ana-

lation (CFD/CAE) STAR codes have outstanding capabilities for handling complex fluid flow and heat transfer problems including transient flows, chemical reaction, free-surface flows, combustion, rotating systems, multiphase and multiphysics. There are four ways in which CD-adapco delivers its CFD technology in software: • STAR-CCM+ is a radically new fullspectrum CFD/CAE processing environment that features the latest object-oriented methods and ergonomically designed GUI for streamlined integration into any company’s engineering process. Solutions on polyhedral cells enable faster and more accurate solutions than any other of the world’s legacy CFD codes. • STAR-CD remains the world’s most advanced CFD code, comes with advanced pre-processing tools, and is now enhanced by the inclusion of any one of the environments from the STAR-CAD Series. • STAR-CAD Series is a range of products that deliver non-complex CFD in an easy to use CAD-embedded environment • Expert Systems (‘es-solutions’) are application-specific bundles that talk the specific engineering language required. They can be viewed as ‘packaged consultancy’ since they are honed for solving particular application challenges. www.info.hotims.com/26886-403

The industry-standard software for instrumentation design

Featuring Featurring more mo than 70 routines associated with control c nt co ntrool valves, valves rupture disks, flow elements, relief valvess and pr process data calculations, InstruCalcTM is one of the industry’s most popular desktop applications for instrumentation calculations and analyses.

Version 7.1 Now Available

Features: • Graphs for Control Valves and Flow w Elements • Restriction devices • Material yield strengths file • ISO orifice plate calculations have been updated to ISO 5167, 2003 • Relief Valve programs, sudden entrance and exiti to the calculations. ex +1 (713) 520-4426 4426 +1 (800) 231-6275 6275 277 Software@GulfPub.com com om m www.GulfPub.com com

F A L L 2009

SOFTWARE REFERENCE

Midstream Upstream PROCESS ENGINEERING AND SIMULATION, CONT.

SOFTWARE REFERENCE

FALL 2009

U PSTREA M / D OWN STREA M SOFTWA RE REFER ENC E box heaters and the convection section of fired heaters. It also designs process heater tubes and performs combustion calculations. Xhpe—Designs, rates, and simulates the performance of hairpin heat exchangers. Xist—Designs, rates, and simulates single- and two-phase shell-and-tube heat exchangers, including kettle and thermosiphon reboilers, falling film evaporators, and reflux condensers. Xjpe—Designs, rates, and simulates jacketedpipe (double-pipe) heat exchangers. Xphe—Designs, rates, and simulates plate-andframe heat exchangers. A fully incremental program, each plate channel is calculated individually using local physical properties and process conditions. Xspe—Rates and simulates single-phase spiral plate heat exchangers. Xtlo—Graphical standalone rigorous tube layout software; also integrated with Xist. Xvib—Performs flow-induced vibration analysis of a single tube in a heat exchanger bundle. It uses a rigorous structural analysis approach to calculate the tube natural frequencies for various modes and offers flexibility in the geometries it can handle. Xchanger Suite Educational—Customized version of Xchanger Suite with the capability to design, rate, and simulate shell-and-tube heat exchangers, air-coolers, economizers, and plateand-frame heat exchangers. Available to educational institutions only. R-trend—Calculates and trends fouling resistances for shell-and-tube heat exchangers in single-phase service. Uses Microsoft Excel as working environment with optional link to Xist. www.info.hotims.com/26886-411

PRODUCTION ENGINEERING

Products: CD-adapco’s solutions (software and related consulting services, training, and mentoring) are widely used across many industries, including oil and gas, chemical process, marine, offshore structures, turbomachinery, automotive, aerospace, building systems, electronics, environmental, pharmaceuticals, power generation, rail, and specialized mechanical engineering applications. The technology-leading Computational Fluid Dynamics flow, thermal, and stress simulation (CFD/CAE) STAR codes have outstanding capabilities for handling complex fluid flow and heat transfer problems including transient flows, chemical reaction, free-surface flows, combustion, rotating systems, multiphase and multiphysics. There are four ways in which CD-adapco delivers its CFD technology in software: • STAR-CCM+ is a radically new full-spectrum CFD/CAE processing environment that features the latest object-oriented methods and ergonomically designed GUI for streamlined integration into any company’s engineering process. Solutions on polyhedral cells enable faster and more accurate solutions than any other of the world’s legacy CFD codes. • STAR-CD remains the world’s most advanced CFD code, comes with advanced pre-processing tools, and is now enhanced by the inclusion of any one of the environments from the STAR-CAD Series. • STAR-CAD Series is a range of products that deliver non-complex CFD in an easy to use CAD-embedded environment • Expert Systems (‘es-solutions’) are application-specific bundles that talk the specific engineering language required. They can be viewed as ‘packaged consultancy’ since they are honed for solving particular application challenges. www.info.hotims.com/26886-403

PRODUCTION OPTIMIZATION CD-adapco 60 Broadhollow Road Melville, NY 11747 Phone: 248-246-5803 Phone: 631-549-2300 Fax: 208-575-2685 E-mail: dennis.nagy@us.cd-adapco.com www.cd-adapco.com Dennis Nagy, VP Marketing & Business Development

UPS TREAM / DOW NS T R E A M S OF T WA R E R E FE REN CE stress software, CAD-embedded CFD options, and CAE consulting services and training. Its principal offices are in New York, London and Yokohama with subsidiary offices across the world.

Company Bio: Merrick Systems helps oil and gas companies to take control of their operations with the industry’s most robust software and hardware

Business Management Upstream Midstream

Products: One Virtual Source (OVSTM), an engineering workflow framework for production operations and reservoir management, incorporates real-time engineering data management, integration and visualization, GIS, engineering workflow management, collaboration and analytics, into one desk-top environment. Centrally controlled and locally configurable for global deployment, OVS orchestrates the entire value chain, from reservoir to surface. Highly versatile, OVS offers various solutions to meet different needs.

WELL LOG DATA ACCESS AND MANAGEMENT

geoLOGIC systems ltd. 900, 703 6 Avenue SW Calgary, AB Canada T2P 0T9 Phone: 403 262-1992 Fax: 403-262-1987 E-mail: sales@geologic.com www.geologic.com Andrea Hood, VP Business Development & Sales

Products:

Starting with engineering data management, OVS serves as a tool for data integration, visualization and an electronic wellbook. Coupling dispersed data sources utilizing live data links, OVS provides users a single point of access to all available data, regardless of the underlying type or frequency of the data source. A single virtually integrated dataset allows for monitoring large volumes of data from numerous sources with ease, using a variety of dashboards, reports and charts.

geoSCOUT TM is a fully integrated, Windowsbased exploratory system that combines presentation-quality mapping and cross-section tools with data handling and analysis software. It integrates public and proprietary data on wells, well logs (Raster and LAS), land, pipelines and facilities, fields and pools, and seismic studies. It includes powerful, easy-touse tools for searching, viewing, mapping, reporting, graphing, analysis and managing information.

Taking data management one step further, OVS then allows users to implement unattended surveillance of production operations by defining boundary data tolerance ranges and exception rules based on business logic. Data is continuously monitored and user is notified of any violations of the pre-set conditions. Users can graphically configure and visualize alarm thresholds based on a comprehensive library of algorithms.

The gDCTM (geoLOGIC Data Center) is an online exploration information system that gives users instant access, through their choice of software, to high quality data in the open Public Petroleum Data Model. Extremely fast and reliable, the gDC gives access to general well data, including geoLOGIC Tops, Original Operator data, DST and other well test data, directional well data, land data, and LAS and Raster log data.

OVS takes users to the next level of sophistication with engineering workflow automation. Users can incorporate engineering workflows into the system to perform engineering model update & validation. OVS’s unique capabilities allow users to accommodate their existing work process and introduce workflows that are natural to their environment, easy to maintain and update, and can evolve throughout the asset life.

www.info.hotims.com/26886-416

www.info.hotims.com/26886-408

F A L L 2009

SOFTWARE REFERENCE

Software Reference Index UPS TR EA M / D O WN ST RE A M SOFT WA R E R E FE RENCE

DISPLAY ADVERTISERS CD-adapco . . . . . . . . . . . . . . . . . . . 24 www.info.hotims.com/26886-403

Chemstations . . . . . . . . . . . . . . . . . 11 www.info.hotims.com/26886-404

Codeware . . . . . . . . . . . . . . . . . . . . 23 www.info.hotims.com/26886-405

Equity Engineering Group . . . . . . . 27 www.info.hotims.com/26886-406

geoLOGIC systems . . . . . . . . . . . . . . 5 www.info.hotims.com/26886-408

Haverly Systems. . . . . . . . . . . . . . . 19 www.info.hotims.com/26886-410

Heat Transfer Research Inc. . . . . . . . 2 www.info.hotims.com/26886-411

KBC Advanced Technologies . . . . . 40 www.info.hotims.com/26886-412

m:pro IT Consult. . . . . . . . . . . . . . . 16 www.info.hotims.com/26886-414

M3 Technology . . . . . . . . . . . . . . . . 28 www.info.hotims.com/26886-415

Merrick Systems . . . . . . . . . . . . . . . 7 www.info.hotims.com/26886-416

Soteica LLC . . . . . . . . . . . . . . . . . . 21 www.info.hotims.com/26886-420

Spiral Software . . . . . . . . . . . . . . . 14 www.info.hotims.com/26886-421

BUSINESS MANAGEMENT BUDGETING, CAPITAL ALLOCATION & PLANNING 3esi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4

BUSINESS INTEGRATION Baker & O’Brien Ensyte Energy Software IBM Solutions

m:pro IT Consult . . . . . . . . . . . . . . . . . . . .4

How to use this index: 1.Learn more about the display advertisers by visiting the pages provided in the first column under “Display Advertisers.” For more information, go to www.HydrocarbonProcessing.com/RS and follow the instructions. 2.The companies shown in bold-faced type have product listings on the page numbers provided.

ENTERPRISE OPERATIONS MANAGEMENT

DESIGN, CONSTRUCTION & ENGINEERING

Oildex . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4

AVEVA

OSIsoft P2 Energy Solutions

CD-adapco . . . . . . . . . . . . . . . . . . . . . . . .10 Chemstations. . . . . . . . . . . . . . . . . . . . . .10 Codeware . . . . . . . . . . . . . . . . . . . . . . . . .10 Heat Transfer Research, Inc. (HTRI). . . .11 KRC Technologies . . . . . . . . . . . . . . . . . .11

LAND AND LEASING geoLOGIC systems . . . . . . . . . . . . . . . . . .5

OPERATIONS KBC Advanced Technologies . . . . . . . . . .6

PLANT LIFECYCLE & PERFORMANCE MONITORING ABB Emerson Process Management

KBC Advanced Technologies . . . . . . . . . .6 m:pro IT Consult . . . . . . . . . . . . . . . . . . . .6

PRODUCTION YIELD/ACCOUNTING Bolo Systems

CGI Solutions and Technologies Data Scavenger Merrick Systems . . . . . . . . . . . . . . . . . . . .7

REGULATORY COMPLIANCE Codeware . . . . . . . . . . . . . . . . . . . . . . . . . .8

RISK MANAGEMENT Equity Engineering Group . . . . . . . . . . . .8 Decisioneering Dyadem Paradigm

McLaren Software Peng Engineering

DYNAMIC SIMULATION & OPTIMIZATION CD-adapco . . . . . . . . . . . . . . . . . . . . . . . .12 Chemstations. . . . . . . . . . . . . . . . . . . . . .12 Invensys SimSci-Esscor

KBC Advanced Technologies . . . . . . . . .13 Kinesix Software RSI Simcon

ECONOMIC EVALUATION Axxis

KBC Advanced Technologies . . . . . . . . .13 Spiral Software . . . . . . . . . . . . . . . . . . . .13

ENERGY MANAGEMENT Heat Transfer Research, Inc. (HTRI). . . .14 KBC Linnhoff March . . . . . . . . . . . . . . . .15 Soteica . . . . . . . . . . . . . . . . . . . . . . . . . . .15

ENTERPRISE PORTAL SYSTEMS m:pro IT Consult . . . . . . . . . . . . . . . . . . .15

FLUID FLOW ANALYSIS

DOWNSTREAM ALARM MANGEMENT ProSys. . . . . . . . . . . . . . . . . . . . . . . . . . . . .9

ASSET MANAGEMENT Aspen Technology Asset Performance Networks

Equity Engineering Group . . . . . . . . . . . .9 Lloyd’s Register Expertune ICONICS INOVx Intergraph

KBC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9

ABZ CD-adapco . . . . . . . . . . . . . . . . . . . . . . . .16 CPFD-Software Engineered Software

ONLINE MONITORING & OPTIMIZATION Chemstations. . . . . . . . . . . . . . . . . . . . . .16 Flexware. . . . . . . . . . . . . . . . . . . . . . . . . .17 KBC Linnhoff March . . . . . . . . . . . . . . . .17 Soteica . . . . . . . . . . . . . . . . . . . . . . . . . . .17

PLANNING, SCHEDULING & BLENDING AMI Consultants . . . . . . . . . . . . . . . . . . .18 Haverly Systems . . . . . . . . . . . . . . . . . . .18

Your company can be listed under a single category in this index at no charge. For information, please contact Laura Kane at 1-713-520-4449 or laura.kane@gulfpub.com 38

SOFTWARE REFERENCE

FALL 2009

Software Reference Index UPSTREAM / DOWNSTREAM SOFTWARE REF ERENCE

KBC Advanced Technologies . . . . . . . . .18 m:pro IT Consult . . . . . . . . . . . . . . . . . . .19 M3 Technology . . . . . . . . . . . . . . . . . . . .19 Soteica . . . . . . . . . . . . . . . . . . . . . . . . . . .20 Spiral Software . . . . . . . . . . . . . . . . . . . .21

PLANT LIFECYCLE & PERFORMANCE MONITORING

MIDSTREAM

Peloton

CD-adapco . . . . . . . . . . . . . . . . . . . . . . . .31

PROCESS ENGINEERING &

C-FER Technologies

SIMULATION

UPSTREAM

KBC Advanced Technologies . . . . . . . . .21 Ventyx

CD-adapco . . . . . . . . . . . . . . . . . . . . . . . .34 Merrick Systems . . . . . . . . . . . . . . . . . . .35

PIPELINE ENGINEERING & FLUID FLOW

Multiphase Solutions

Dassault Systemes innotec

OPERATIONS

CD-adapco . . . . . . . . . . . . . . . . . . . . . . . .35 Heat Transfer Research, Inc. (HTRI). . . .36 Softbits Sun Microsystems

ASSET MANAGEMENT

PREDICTIVE MAINTENANCE & REPAIR Codeware . . . . . . . . . . . . . . . . . . . . . . . . .22 Equity Engineering Group . . . . . . . . . . .22 Metegrity Siemens Energy & Automation

PROCESS ENGINEERING & SIMULATION Ansys Bryan Research & Engineering

CD-adapco . . . . . . . . . . . . . . . . . . . . . . . .23 Chemstations. . . . . . . . . . . . . . . . . . . . . .23 Codeware . . . . . . . . . . . . . . . . . . . . . . . . .24

IHS Energy Group

PRODUCTION ENGINEERING

Landmark (Halliburton)

CD-adapco . . . . . . . . . . . . . . . . . . . . . . . .36

Merrick Systems . . . . . . . . . . . . . . . . . . .31

Well Flow Dynamics

Schlumberger Information Solutions

DATA MANAGEMENT

PRODUCTION OPTIMIZATION CD-adapco . . . . . . . . . . . . . . . . . . . . . . . .36

Decision Dynamics Technology

Fekete Associates

Enertia Software

Joshi Technologies

geoLOGIC systems . . . . . . . . . . . . . . . . .31

Merrick Systems . . . . . . . . . . . . . . . . . . .37

Open Spirit

Pavilion Technologies

DATA VISUALIZATION

RESERVES MANAGEMENT

geoLOGIC systems . . . . . . . . . . . . . . . . .32

Geomechanics International

Farris Engineering Services

Paradigm

Petro-Soft Systems

Heat Transfer Research, Inc. (HTRI). . . .24 KBC Advanced Technologies . . . . . . . . .25

Slicer/Dicer (PIXOTEC) . . . . . . . . . . . . . .32

Roxar

Process Systems Enterprise

Total Systems Resources

PRODUCTION/YIELD ACCOUNTING Soteica . . . . . . . . . . . . . . . . . . . . . . . . . . .25

REFINING, PETROCHEMICAL & GAS PROCESSING CD-adapco . . . . . . . . . . . . . . . . . . . . . . . .26 Equity Engineering Group . . . . . . . . . . .26 Heat Transfer Research, Inc. (HTRI). . . .26 KBC Linnhoff March . . . . . . . . . . . . . . . .27 KBC Advanced Technologies . . . . . . . . .28 M3 Technology . . . . . . . . . . . . . . . . . . . .28

SIS / SAFETY SYSTEMS ACM Facility Safety

exida . . . . . . . . . . . . . . . . . . . . . . . . . . . . .29

Sitelark

DESIGN, CONSTRUCTION & ENGINEERING BlueCielo ECM Solutions

Equity Engineering Group . . . . . . . . . . .29

RESERVOIR MODELING

CD-adapco . . . . . . . . . . . . . . . . . . . . . . . .32

CMG

COADE

Geomodeling

Heat Transfer Research, Inc. (HTRI). . . .33

DRILLING ENGINEERING

SEISMIC DATA INTERPRETATION & ANALYSIS

CD-adapco . . . . . . . . . . . . . . . . . . . . . . . .33

Earth Decision

Knowledge Systems

Fugro-Jason

Pegasus Vertex

I/O

EXPLORATION

SEISMIC PROCESSING

Digital Formation

CGGVeritas

geoLOGIC systems . . . . . . . . . . . . . . . . .34

TGS

Knowledge Systems

FIELD DATA CAPTURE

TRAINING

TRC Consultants

Merrick Systems . . . . . . . . . . . . . . . . . . .34

WELL LOG DATA ACCESS & MANAGEMENT geoLOGIC systems . . . . . . . . . . . . . . . . .37

Your company can be listed under a single category in this index at no charge. For information, please contact Laura Kane at 1-713-520-4449 or laura.kane@gulfpub.com F A L L 2009

SOFTWARE REFERENCE

Keep Whatâ&#x20AC;&#x2122;s Important in Focus

Petro-SIM monitoring applications from KBC take your plant data and get to the heart of what you need. How well is your unit running? How good is your LP? How can you improve your unit operation? The latest innovation in Petro-SIM, our monitoring applications seamlessly integrate your plant historian, your process simulator, and your planning tool. Evaluate your data, evaluate your process, and evaluate your models â&#x20AC;&#x201C; and easily maintain your models and optimize your operation.

Petro-SIM brings it all together. Select 412 at www.HydrocarbonProcessing.com/RS

Software Solutions formerly PROFIMATICS