HP_2011_02 by androsov.info

FEBRUARY 2011

HPIMPACT

SPECIALREPORT

TECHNOLOGY

Energy stocks offer positive returns

CLEAN FUELS

Updates on flare systems and design

Advances in cellulosic biofuel production

New methods focus on “bottom-of-the-barrel” and clean fuels

Consider new gas analysis techniques

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FEBRUARY 2011 • VOL. 90 NO. 2 www.HydrocarbonProcessing.com

SPECIAL REPORT: CLEAN FUELS

33 37

HPI Viewpoint: Consumer protection is a key issue for E15 NPRA wants to be sure that adding greater amounts of ethanol to gasoline is safe and will not cause engine damage C. T. Drevna

Slurry-phase hydrocracking—possible solution to refining margins Opportunity crudes require more hydrogen addition to upgrade orphan product streams into higher-value ‘clean’ products M. Motaghi, B. Ulrich and A. Subramanian

Convert bottom-of-the-barrel into diesel and light olefins Integrating residue hydrocracking operations with advanced fluid catalytic cracking optimizes upgrading of heavy crude oils M. Rama Rao, D. Soni, G. M. Sieli and D. Bhattacharyya

What are the future fungible transportation fuels?

How to fabricate reactors for severe service

63 71

00 cutline for fig

Cover Neste Oil started up the world’s largest and most advanced renewable diesel plant in Singapore in November 2010. The plant was completed on-schedule and on budget, and it is located at the industrial area of Tuas, in the southwestern part of Singapore. This facility has a production capacity of 800,000 tons based on the Neste’s NExBTL renewable diesel process; product is targeted for markets in Europe and North America. Nest Oil is constructing a similar sized renewable cutline for fig 00 NExBTL unit in Rotterdam with start-up in the first half of 2011. Photo courtesy of Neste Oil.

Alternatives hold promises to decrease dependence on crude oil, but they also uncover other challenges in distribution and engine use M. Stockle

Many critical factors are involved in the design and welding of hydrocracking reactors D. Quintiliani, G. Fossataro and M. De Colellis

HPIMPACT 13

Energy stocks outperformed market indices in 2010

Team overcomes obstacles to cellulosic biofuel production

Designing atmospheric crude distillation for bitumen service Oil sands add complexity to separation units and require a new approach M. Grande and M. Gutscher

Minimize carbon footprint from Claus tail-gas units Reevaluate emissions efficiencies on sulfur-removal operations M. P. Heisel and M. Rameshni for fig. 00 Cutline COLUMNS

GAS PROCESSING DEVELOPMENTS

Tuneable diode laser analyzers offer diagnostic benefits R. Jenkins

PLANT SAFETY

Avoid these risks concerning combustion control in fired heaters

Circumvent design issues when adding new hydrotreating units Follow these guidelines for substantial capital cost savings with existing flare systems M. H. Marchetti

DEPARTMENTS

HPINTEGRATION STRATEGIES Data historians provide effective decision support in XX near Dewitt petrochemicalreal time

HPIMPACT conference out look

HPIN CONTROL XX Six strategic business Inferential technologiescontrol to watch model input selection

Australia making crucial GTL decisions

IEA assesses energy policies of U.S.

Creating more value in capital projects

7 HPIN BRIEF • 19 HPINNOVATIONS • 25 HPIN CONSTRUCTION 31 HPI CONSTRUCTION BOXSCORE UPDATE 90 HPI MARKETPLACE • 93 ADVERTISER INDEX

HPIN RELIABILITY Alignment choices have consequences

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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 & Tech nology Index, by Chemical Abstracts and by Engineering Index Inc. Microfilm copies available through University Microfilms, International, Ann Arbor, Mich. The full text of Hydrocarbon Processing is also available in electronic versions of the Business Periodicals Index. ARTICLE REPRINTS

If you would like to have a recent article reprinted for an upcoming conference or for use as a marketing tool, contact Foster Printing Company for a price quote. Articles are reprinted on quality stock with advertisements removed; options are available for covers and turnaround times. Our minimum order is a quantity of 100. For more information about article reprints, call Rhonda Brown with Foster Printing Company at +1 (866) 879-9144 ext 194 or e-mail rhondab@FosterPrinting.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 © 2011 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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Marathon Oil Corp. is moving forward with plans to spin off Marathon’s downstream business, creating two independent energy companies. Marathon Petroleum Corp. (MPC), to be headquartered in Findlay, Ohio, is expected to be the fifth largest US refiner with a downstream portfolio of strategically aligned assets concentrated mainly in the Midwest, Gulf Coast and Southeast regions of the US. The spin-off is expected to be tax-free and to be effective June 30, 2011. Marathon Oil Corp. will be a global upstream company with a portfolio of assets delivering defined growth leveraged to crude oil production and with exploration upside. It will continue to be based in Houston, Texas.

PetroChina International is forming a partnership with INEOS for new trading and refining joint ventures related to refining operations in Grangemouth, Scotland, and Lavéra, France. All companies will work toward the formation of the proposed joint ventures by the end of June 2011. Underlying the international importance of PetroChina’s and INEOS’ collaboration, the official signing ceremony for the agreements was witnessed by Nick Clegg, the British deputy prime minister, and Li Ke Qiang, the Chinese vice premier. The deal will create a strategic partnership between the two companies, and INEOS believes it will improve the long-term sustainability of its refineries, enhance security of supply for customers, and secure jobs in both the UK and France.

Axens North America has signed an agreement with Criterion Catalysts and Technology and Shell that allows for the purchase of Criterion’s catalytic reforming catalyst business. The specifics of the deal allow Axens to obtain Criterion’s Willow Island, West Virginia, manufacturing plant for reforming catalyst and appropriate intellectual property rights to pursue such business.

KBR and SK Innovation started up an advanced catalytic olefins (ACO) demo plant in Ulsan, South Korea. Operations to date have met the companies’ expectations for olefins production, particularly propylene, with improved economics relative to steam cracking due to the technology’s higher total olefins yields and increased propylene/ethylene ratios approaching 1.0. The startup marks the first commercial demonstration of the ACO process. The demonstration unit achieved a design feed rate as scheduled in late October 2010. The ACO process provides an alternative to naphtha steam crackers, and, according to KBR, not only does it offer higher olefins production, the process also produces a lower emissions footprint than a conventional cracker.

Iraq’s South Oil Co. has awarded Emerson Process Management a contract to provide crude-oil metering systems and related technologies for the new Al-Basra oil terminal now under construction in the Persian Gulf. The new terminal, which includes both onshore and offshore facilities, will boost Iraq’s oil-export capacity by 2.7 million bpd. The added capacity will give Iraq increased access to global markets as it expands production from its southern oil fields. Emerson’s metering systems will measure the amount of oil as custody is transferred from producers to shippers through the Al-Basra terminal. The systems combine ultrasonic measurement technology with diagnostic software that can detect potential problems before they affect accuracy.

Gushan Environmental Energy, a producer of biodiesel in China, is in the process of assessing the effect of a recently issued notice on consumption tax from the Chinese Ministry of Finance and the Chinese State Administration of Taxation. The notice regarding the exemption from consumption tax on pure biodiesel made from waste animal fats or vegetable oils was issued on December 24, 2010, and became effective immediately. It clarifies that pure biodiesel made from waste animal fats or vegetable oils is exempted from consumption tax in China, and that such exemption will be implemented retroactive to January 1, 2009. HP

■ Ethanol infrastructure lacking The US does not have the infrastructure to meet the federal mandate for renewable fuel use with ethanol but could meet the standard with significant increases in cellulosic and next-generation biofuels, according to a Purdue University study. The report’s authors used US Department of Energy (DOE) and Environmental Protection Agency (EPA) data to determine that the US is at the “blending wall,” the saturation point for ethanol use. Without new technology or a significant increase in infrastructure, the study predicts that the country will not be able to consume more ethanol than is being currently produced. The US federal renewable fuel standard requires an increase of renewable fuel production to 36 billion gallons per year by 2022. About 13 billion gallons of renewable fuel was required for 2010, the same amount the report predicts is the threshold for US consumption. The study contends that there simply are not enough flex-fuel vehicles, which use an 85% ethanol blend, or E85 stations to distribute more biofuels. According to EPA estimates, flex-fuel vehicles make up 7.3 million of the 240 million vehicles on the nation’s roads. Of those, about 3 million of flex-fuel vehicle owners aren’t even aware they can use E85 fuel. There are only about 2,000 E85 fuel pumps in the US, and it took more than 20 years to install them. In order for the US’ infrastructure to match the numbers in the federal mandate, the study’s authors say 2,000 pumps a year would need to be installed through the year 2022. They also note that E85 needs to be substantially cheaper than gasoline to entice consumers to use it, because E85 gets lower mileage. The report says that advances in the production of thermo-chemical biofuels, which are created by using heat to chemically alter biomass and create fuels, would be necessary to meet the renewable fuel standard. HP

HYDROCARBON PROCESSING FEBRUARY 2011

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

Alignment choices have consequences

Modern vs. old school. With modern alignment methods

taking no more time than tinkering with old-style methods, common sense should point toward using precise methods. Inadequate alignment still causes major calamities (Fig. 1); whereas, the results of sound alignment approaches typically show up as improved mean time between repairs (MTBR) and a reduction in maintenance outlay. The November 2006 HPIn Reliability column shed additional light on this topic. A likely consensus among reasonable people holds that precision alignment typically lowers vibration to half of the value of “conventional” alignment. Fig. 2 represents an estimate of bearing operating life extension due to reduced vibration velocity for typical process pumps. Fig. 3 gives an indication of how a major bearing manufacturer rates the effects of misaligned bearings. Most rolling element bearings fit somewhere between the two curve boundaries and at tangents below 0.001; bearing life is thought to exceed a relative rating of 1.2 On average, there is then reason to believe that precision alignment alone would result in a pump MTBR multiplier of somewhere between 1.4 and 1.7. The problem is that best-of-class performers inevitably implement additional upgrades and they will seldom confine their work to just better alignment. That is why Ref. 1 puts the

pump MTBR of a very marginal performer at 1.6 years, while best performers often get 9 years or more between pump failures. HP 1 2

LITERATURE CITED Bloch, H. P. and A. Budris, Pump User’s Handbook: Life Extension, Third Edition, 2010, Fairmont Press, Lilburn, GA 30047; (ISBN 0-88173-627-9). Leibensperger, R. L.; “Look beyond catalog ratings,” Machine Design, April 3, 1975.

The author is Hydrocarbon Processing’s Reliability/Equipment Editor. A practicing consulting engineer with almost 50 years of applicable experience, he advises process plants worldwide on failure analysis, reliability improvement and maintenance. He has authored or co-authored 18 textbooks and close to 500 papers or articles dealing with related subjects.

1.2 1.0 Life, of L10a %

Optimists tell us about steady industry trends toward reliability-imparting procedures and work processes, while realists continually make us aware of pressures to reduce expenditures. As outside observers, we affirm that striving to reduce monetary outlay is quite commendable, but only as long as these aims don’t run counter to the professed longer-term reliability improvement objectives. Conflicting issues are often alluded to in queries that we receive from readers. For instance, we were asked if we knew of literature that quantifies the merits of precision alignment for pumps, and if it’s really appropriate to shun old-style methods.

0.8 0.6 0.4 0.2 0.0 0.0

FIG. 2

0.1

0.2

0.3 0.4 Vibration, ips

0.5

0.6

0.7

Bearing housing vibration velocity vs. bearing life for process pumps.1

1.50

Relative bearing life

1.25

1.00

0.75

0.00

0.50 0.00 0.000

FIG. 1

Process pump failure that started with misalignment, high vibration and bearing distress. Source: Murray & Garig Tool Works, Baytown, Texas.

FIG. 3

0.001

0.002 0.003 0.004 Tangent of misalignment angle

0.005

0.006

How tangent of misalignment angle affects bearing life.

HYDROCARBON PROCESSING FEBRUARY 2011

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HPINTEGRATION STRATEGIES ALLEN AVERY, CONTRIBUTING EDITOR AAvery@Arcweb.com

Data historians provide effective decision support in near real time Plant data historians are moving beyond their traditional role as a tool for collecting and archiving data to better understand past plant performance, to becoming a powerful tool that can be used to improve real-time operations. With increased data throughput and higher data resolutions, historians have also become a foundation for plant asset management initiatives, thanks to new visibility and trending tools that can also be used to support energy management programs. Today’s historians also support techniques, such as complex event processing, which can analyze multiple streams of plant data in real time to identify and diagnose emerging problems before they disrupt the production process in the plant, or negatively affect smart grids or other distributed assets. Plant historians get enhanced functionality. Recent

product advances increase historian data throughput, solution scalability, compatibility and connectivity with plant systems and third-party solutions. They provide powerful visualization and analytical tools. These allow users to access and leverage huge volumes of plant data in near real time. Historians can collect and display real-time data and events, giving users a more comprehensive view of what is happening in a plant or distributed assets. Powerful processing capabilities, coupled with advanced software algorithms, have changed how historians are used. Historians are transitioning from their traditional role, as plant record-keepers and planners, to tools that can have a positive impact on plant operations in real time. With recent advances in computing technology, including 64-bit processing architectures, historians can collect and store large amounts of plant and process information. Many can archive up to several exabytes of data. Many can simultaneously store and retrieve plant data, giving users an up-tothe-minute view of plant performance. Today’s historians can handle hundreds of thousands of discrete events per second, so real-time plant data is available almost immediately for analysis. Modern computing power has enhanced historians to such a degree that, rather than just being used to look back on plant performance, they can be used to predict and positively impact future performance. The use of de facto standards and environments, such as OPC and Microsoft .NET, allows easier interfacing between systems and different historians. This helps users leverage existing historian data, even if they choose a new solution from a different vendor. OPC compatibility also enables easy access to, and use of, data from HMI, DCS, CMMS and other plant-level applications. Since suppliers are also beginning to offer OPC-UA compliant products, historian data is now also readily available to applications running on non-Microsoft platforms. In addition to plant-level equipment, historians also interface well with EAM, ERP and advanced optimization applications.

Historian suppliers have worked to offer improved data access and visibility tools with their solutions. Many offer webbased, thin-client access to historians, and most offer access to historian data via mobile devices. Powerful trending and graphics tools allow users to generate custom reports and charts to visualize plant data. Suppliers have also emphasized ease of use and configuration in their product development. Users can easily create custom interfaces and role-based dashboards to view and manipulate historian data. Due to their high data capture rates, today’s historians can act as a foundation for plant asset management programs. The ability to store, access and analyze plant data in near real time can help users identify any anomalies or troubling performance trends that could indicate a problem with production equipment. Historical data can be used to develop models or profiles that help users determine how a given asset should behave under normal conditions, and to set alarms or formulate maintenance strategies to balance production needs with asset viability, remotely and in real time. We expect historians to play a role in energy-management initiatives as well, by helping to develop energy-consumption models that can be used to identify under-performing and inefficient plant equipment, or to make real-time adjustments to production to minimize energy costs. Coming soon: Complex event processing. Though in

its infancy, complex-event processing is another technology that can harness the capabilities of plant historians. Historians can be used to complement and augment complex event processing, a technology that can analyze multiple incoming streams of data in near real time. When viewed individually, these streams might mean little. But when viewed simultaneously and in context, they could help identify process or plant equipment problems using advanced data filtering and algorithms. ARC analysts are following recent trends in data historians closely. These include the evolution of many plant historians from large-capacity historical data repositories, to real-time decision-support and business intelligence platforms, and—ultimately—to platforms that enable real-time operations centers functionality for a single plant or even a set of plants. HP readers should stay tuned to this column, or visit www.arcweb.com for details on future reports on this important topic. HP

Allen Avery is an analyst at ARC Advisory Group. His focus areas include field systems (flow, level, pressure, temperature and gas detection) and wireless networks. In addition, he covers plant asset management, energy management issues, and SCADA systems. He recently completed an extensive end-user study on energy management practices, and is the author of the report “SCADA Systems Oil & Gas Industry Worldwide Outlook.”

HYDROCARBON PROCESSING FEBRUARY 2011

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HPIMPACT BILLY THINNES, NEWS EDITOR

BT@HydrocarbonProcessing.com

Energy stocks outperformed market indices in 2010 Despite a poor start, 2010 finished as a “wonderful year” for energy investors, with more than 65% of oil and gas stocks delivering positive returns last year, according to a report from IHS Herold. Driven by economic growth, crude prices, which hit bottom in late May 2010 at around $65 per barrel, rose steadily and consistently through the second half of the year, and took oil company shares with them. The median gain for the 503 stocks covered in the report was 21%, which, while it did not match the record-setting 59% gain posted in the 2009 IHS report, did outperform the market indices of nearly all Organization for Economic Cooperation and Development (OECD) countries. Total capitalization jumped by more than $300 billion, further reducing the severe losses the sector incurred in 2008 the report said, but did not extinguish them. “Sometime in the first quarter of 2009, equity markets began to move upward in response to the economic growth that was becoming apparent in OECD countries,” said Robert Gillon, senior vice president and co-director of energy equity research at IHS. “It seemed as though every statistic that confirmed expansion was under way was reflected in a rise in the price of crude, which boded well for oil stocks. That pattern continued throughout the year, with oil prices and oil shares at a recovery high at the closing bell of 2010. In particular, North American oil stocks delivered the most returns to their investors.” Group returns. After finishing second-

to-last as a peer group in 2009, US royalty trusts earned redemption by taking top honors in 2010 as the best-performing peer group reviewed, posting a gain of more than 44%. MV Oil Trust led the group by posting a return of 111%. Companies in the E&P limited income partnerships group followed closely with gains of nearly 43%. According to the IHS report, these survey-leading returns were in response to monetary stimuli by numerous central banks, where open-market

interest rates fell to the lowest levels seen in decades, which forced yield-conscious investors to take on more risk in order to maintain their desired level of income. “The vast amount of liquidity being injected into the economic system, particularly in the US, has resulted in a strong correlation between equity prices and oil prices,” Mr. Gillon said. “By contrast, for many years prior to 2009, there was a reverse relationship, with higher crude prices perceived to cause a reduction in disposable income, lower consumer spending, and declining domestic product and stock prices. To our mind, this is the normal state of affairs, but to predict we will be back to normal in short order would be unwise.” As a group, master limited partnerships (mostly pipeline and storage companies) enjoyed a hearty gain of nearly 35%, while the peer group of integrated oil stocks with

refining margins. BHP Billiton is the only member of the 2009 crop to repeat in the top 10 this year. Natural gas. While oil stocks carried the

sector in 2010, continued weakness in the North American natural gas market did not prevent the large producers from generating solid shareholder returns, with the median performance of the group nearly matching that of the entire survey. However, a high concentration of North American natural gas in the production mix detracted from returns, since US natural gas spot prices, which began the year at what now seems like the lofty price of $6/MMBtu, ended the year at a nine-year low for the date, which was about 30% below where they began. “Natural gas inventories were well above average, and US domestic production showed no signs of topping out,” Mr.

■ “The vast amount of liquidity being injected into the economic system, particularly in the US, has resulted in a strong correlation between equity prices and oil prices,” Mr. Gillon said. “By contrast, for many years prior to 2009, there was a reverse relationship, with higher crude prices perceived to cause a reduction in disposable income and lower consumer spending.” US downstream returned 22%, which was marginally above the survey average. Canadian integrated oil stocks and integrated oil stocks without US downstream operations gained less than half that amount, at 10% and 9%, respectively. Returns from the latter group, the report said, were dragged down by the generally poor performance of European markets. On the other hand, shares in the refining and marketing category offered a healthy median gain of 38% and did well globally as demand for distillates rose with increasing economic activity. Among the largest integrated and diversified oils group, top-ranked Ecopetrol’s 84% gain reflected rapidly growing oil production, and it also got an updraft from the soaring Bogotá market. Sunoco Inc. and Valero Energy, last year’s bottom two performers in this grouping, moved into the top 10 due to a dramatic turnaround in

Gillon said. “Fortunately for everyone but the Europeans, it has been ferociously cold in Europe, so gas is being shipped to the higher-priced markets. The world is well supplied with gas, and the modest upward slope to the current futures curve is testimony to the glut in supply.” Alternative energy. Stocks in the alter-

native energy group held the basement position as worst in class, posting losses of more than 24% after gaining 26% in 2009. “We’re not sure what to say about alternative energy, except perhaps a requiem. In the five years we have shown this segment in the survey, it has been the worst performing group twice, second worst twice, and soared to fourth from the bottom on one happy occasion,” Mr. Gillon said. “They suffer when natural gas prices go down, when government subsidies are cut, when the wind HYDROCARBON PROCESSING FEBRUARY 2011

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HPIMPACT doesn’t blow, when it blows too much, and when the sun doesn’t shine. There may be other problems, as well, which we will probably find out about in 2011.”

Team overcomes obstacles to cellulosic biofuel production A newly engineered yeast strain can simultaneously consume two types of sugar from plants to produce ethanol, researchers report. The sugars are glucose, a six-carbon sugar that is relatively easy to ferment; and xylose, a five-carbon sugar that has been much more difficult to utilize in ethanol production. The new strain, made by combining, optimizing and adding to earlier advances, reduces or eliminates several major inefficiencies associated with current biofuel production methods. The findings, from a collaborative led by researchers at the University of Illinois, the Lawrence Berkeley National Laboratory, the University of California and BP, are described in the Proceedings of the National Academy of Sciences. The Energy Biosciences Institute, a BP-funded initiative, supported the research.

“Xylose is a wood sugar, a five-carbon sugar that is very abundant in lignocellulosic biomass but not in our food,” said Yong-Su Jin, a professor of food science and human nutrition at Illinois and a principal investigator on the study. “Most yeast cannot ferment xylose.” A big part of the problem with yeasts altered to take up xylose is that they will suck up all the glucose in a mixture before they will touch the xylose, Dr. Jin said. A

glucose transporter on the surface of the yeast prefers to bind to glucose. “It’s like giving meat and broccoli to my kids,” he said. “They usually eat the meat first and the broccoli later.” The yeast’s extremely slow metabolism of xylose also adds significantly to the cost of biofuels production. Dr. Jin and his colleagues wanted to induce the yeast to quickly and efficiently consume both types of sugar at once, a pro-

Yeast strains. Yeasts feed on sugar and

produce various waste products, some of which are useful to humans. One type of yeast, Saccharomyces cerevisiae, has been used for centuries in baking and brewing because it efficiently ferments sugars and, in the process, produces ethanol and carbon dioxide. The biofuel industry uses this yeast to convert plant sugars to bioethanol. And while S. cerevisiae is very good at utilizing glucose, a building block of cellulose and the primary sugar in plants, it cannot use xylose, a secondary—but significant—component of the lignocellulose that makes up plant stems and leaves. Most yeast strains that are engineered to metabolize xylose do so very slowly.

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FIG. 1

Illinois University food science and human nutrition professor Yong-Su Jin, center, and his colleagues engineered a yeast that outperforms the industry standard.

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HPIMPACT cess called co-fermentation. The research effort involved researchers from Illinois, the Lawrence Berkeley National Laboratory, the University of California at Berkeley, Seoul National University and BP. Adjustments. In a painstaking process

of adjustments to the original yeast, Dr. Jin and his colleagues converted it to one that will consume both types of sugar faster and more efficiently than any strain currently in

use in the biofuel industry. In fact, the new yeast strain simultaneously converts cellobiose (a precursor of glucose) and xylose to ethanol just as quickly as it can ferment either sugar alone. “If you do the fermentation by using only cellobiose or xylose, it takes 48 hours,” said post-doctoral researcher and lead author Suk-Jin Ha. “But if you do the co-fermentation with the cellobiose and xylose, double the amount of sugar is con-

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sumed in the same amount of time and produces more than double the amount of ethanol. It’s a huge synergistic effect of co-fermentation.” The new yeast strain is at least 20% more efficient at converting xylose to ethanol than other strains, making it “the best xylose-fermenting strain” reported in any study, Dr. Jin said. Critical changes. The team achieved

these outcomes by making several critical changes to the organism. First, they gave the yeast a cellobiose transporter. Cellobiose, a part of plant cell walls, consists of two glucose sugars linked together. Cellobiose is traditionally converted to glucose outside the yeast cell before entering the cell through glucose transporters for conversion to ethanol. Having a cellobiose transporter means that the engineered yeast can bring cellobiose directly into the cell. Only after the cellobiose is inside the cell is it converted to glucose. This approach eliminates the costly step of adding a cellobiose-degrading enzyme to the lignocellulose mixture before the yeast consumes it. It has the added advantage of circumventing the yeast’s own preference for glucose. Because the glucose can now “sneak” into the yeast in the form of cellobiose, the glucose transporters can focus on drawing xylose into the cell instead. Bottleneck solutions. The team then tackled the problems associated with xylose metabolism. The researchers inserted three genes into S. cerevisiae from a xylose-consuming yeast, Picchia stipitis. The team identified the bottleneck in this metabolic pathway. By adjusting the relative production of these enzymes, the researchers eliminated the bottleneck and boosted the speed of xylose metabolism in the new strain. They also engineered an artificial “isoenzyme” that balanced the proportion of two important co-factors so that the accumulation of xylitol, a byproduct in the xylose assimilitary pathway, could be minimized. Finally, the team used “evolutionary engineering” to optimize the new strain’s ability to utilize xylose. The cost benefits of this advance in co-fermentation are very significant, Dr. Jin said. “We don’t have to do two separate fermentations,” he said. “We can do it all in one pot. And the yield is even higher than the industry standard. We are pretty sure that this research can be commercialized very soon.” HP

Sulzer Chemtech

Tower Technical Bulletin Proper Design of Mass Transfer Internals in the FCC Flue Gas Scrubber Can Help Reduce PM Emissions Background The EPA’s New Source Performance Standards (40 C.F.R. §60.100-1-0, subpart Ja) regulates refinery particulate emissions, including the discharge of catalyst fines from the FCCU flue gas scrubber stack. Because refiners have traditionally correlated particulate matter (PM) emissions with FCCU cokeburn, high flue gas stack PM can result in reducing severity or throughput in the FCCU at a potentially huge economic cost. The proper selection of mass transfer internals in the scrubber can contribute to its performance in controlling PM emissions, and can improve the refinery’s bottom line.

fouling resistance and is designed to be self-draining to avoid any solids trap-out problem. The Mellagrid smooth angles and transitions minimize shearing of liquid droplets, aiding in droplet settling. The Sulzer F-GridTM or Nutter GridTM can be utilized as drop-in replacements for an existing ﬂue gas scrubber de-entrainment bed during a turnaround, or Sulzer can customize the grid design for optimum capacity, pressure drop, efﬁciency, and fouling resistance with a combination bed.

A unit turnaround is a prime opportunity for the refiner to address such issues as de-entrainment section fouling, chimney tray plugging, and overall poor performance contributing to stack PM. Removing Solids with a Flue Gas Scrubber Flue gas scrubbing is one method to control particulate and SO2 in FCCU flue gas vents. In scrubbers with external venturis, the flue gas is mixed with water and caustic to neutralize SOX. The combined stream enters a disengaging drum through large venturis, where centrifugal force is used to separate the liquid from the flue gas. The flue gas then travels upward toward the stack. A bed of structured grid packing is used to eliminate entrained droplets that contain particles of catalyst or salt. The condensate is collected in a chimney tray and drained to the bottom of the disengaging drum. The scrubbed and de-entrained vapor is allowed to exit the scrubber stack. Design of the Chimney Tray A Sulzer chimney tray design for flue gas scrubbing service features a sloping floor to prevent solids accumulation and multiple small chimneys. The open area is sized to minimize pressure drop, while the riser arrangement allows for the best distribution into the packed bed. Selection of Packing Grid-type structured packing is used in direct-contact heat transfer, scrubbing, and de-entraining services such as the FCC flue gas scrubber. Due to its high open area, grid has a very low pressure drop and high capacity. Grids have low wetting rates compared with structured packing, and can therefore achieve low turndowns. An excellent option for de-entrainment in the flue gas stack is Sulzer MellagridTM, which has a smooth surface to provide the maximum

Sulzer F-GridTM and Sulzer MellagridTM Grid Packing Design of the Grid Wash Sprays Scrubber packing is subject to plugging from the residual salts and catalyst fines that are removed from the flue gas. A set of wash sprays is positioned above the bed for a periodic solids removal water wash. High stack velocities can entrain the spraying wash water overhead, not allowing adequate washing of the grid. Sulzer takes this into consideration in our design of the spray header, with the selection of nozzle type and nozzle pressure drop keeping the droplet sizes large and preventing re-entrainment. The sprays would be designed to fully cover the cross sectional grid area with sufficient overlap to account for some droplet carry-up. The Sulzer Refinery Applications Group Sulzer Chemtech has over 50 years of operating and design experience in refinery applications. We understand your process and your economic drivers. Sulzer has the know-how and the technology to provide a scrubber internals design with reliable, high performance.

Sulzer Chemtech, USA, Inc. 8505 E. North Belt Drive | Humble, TX 77396 Phone: (281) 604-4100 | Fax: (281) 540-2777 TowerTech.CTUS@sulzer.com www.sulzerchemtech.com

Legal Notice: The information contained in this publication is believed to be accurate and reliable, but is not to be construed as implying any warranty or guarantee of performance. Sulzer Chemtech waives any liability and indemnity for effects resulting from its application.

Select 68 at www.HydrocarbonProcessing.com/RS

CRYO-PLUS™ Get More Valuable Liquid from your Gas Streams Linde Process Plants, Inc. provides engineering, design, fabrication and construction of cryogenic plants for the extraction of hydrocarbon liquid from natural gas, refinery and petrochemical gas streams. Recovered liquid components can include ethylene, ethane, propylene, propane, isobutane as well as other valuable olefinic and paraffinic hydrocarbons. Combine your CRYO-PLUS™ plant with a Linde PSA to recover high purity hydrogen from refinery and petrochemical off-gas streams.

Why choose Linde’s CRYO-PLUS™ – Proprietary technology with a proven track record in: – Refinery Off-Gas – Petrochemical Off-Gas – Natural Gas – Robust, adaptable and flexible design, and operation – Typical payout times of six (6) months to two (2) years

A member of The Linde Group Linde Process Plants, Inc. 6100 South Yale Avenue, Suite 1200, Tulsa, Oklahoma 74136, USA Phone: +1.918.477.1200, Fax: +1.918.477.1100, www.LPPUSA.com, e-mail: sales@LPPUSA.com Select 81 at www.HydrocarbonProcessing.com/RS

HPINNOVATIONS SELECTED BY HYDROCARBON PROCESSING EDITORS editorial@gulfpub.com

Siemens expands anaerobicdigestion product offering Siemens Water Technologies has acquired the JetMix hydraulic mixing system from Liquid Dynamics Corp. This proprietary system agitates sludge within the anaerobic digestion process, optimizing digestion and methane production. The latter can be captured and used as energy within a wastewater treatment facility. Compared to similar mixing systems, the JetMix system allows operators to schedule mixing times—reducing power usage by 60%–80% without decreasing gas production or negatively affecting volatile solids reduction. Suitable for use in new installations, as well as for retrofits or upgrades for a variety of municipal and industrial applications, the JetMix system complements Siemens’ existing line of equipment and solutions for anaerobic digestion. The JetMix system creates an effective mixing volume rating of 95% or more, even with internal piping and roof support columns. The system uses powerful jets to maintain or resuspend solids. Nozzles mounted inside the tank can be rotated 360° to create a flow pattern that virtually eliminates solids settling, reduces energy requirements, and makes dead spots obsolete. A top nozzle effectively controls scum and grease as well as foam and other floatables. The modular design of the JetMix system allows for various pumps and nozzles to be used in combination to meet a wide range of application requirements and load fluctuations. Viscosity, particle size, density, settling rate and tank geometry are all considered when designing the mixing system. The mixing system can be paired with thermophilic and mesophilic digesters, and can be coupled with heat exchangers. The system can be used in channels as well as in circular, square and rectangular tanks. Suitable applications include tanks with gas holders, or fixed and membrane roofs, with the tanks located either above or below ground. Select 1 at www.HydrocarbonProcessing.com/RS

Accurate field calibrator measures differential pressure Crystal Engineering is releasing a significant addition to their nVision Refer-

ence Recorder. This most recent (and free) quarterly update enables the intrinsically safe, hand-held field calibrator to graph and record average and differential pressure data. Now, the nVision (Fig. 1) can display, record and graph differential pressure to a remarkable accuracy of 0.025% of the differential reading up to 300 psi static, 0.05% up to 3,000 psi static, and 0.1% up to 10,000 psi static pressure. The nVision can also record 500,000 data points from each of its two modular sensors, simultaneously. It takes these measurements as frequently as every 0.1 sec, without any change in accuracy between –20°C and 50°C. The nVision delivers this accuracy while maintaining excellent field capability, and without risking sensor damage. Other differential calibrators sustain damage easily, when an improper connection or operation of valves exposes their single sensor to full static pressure. Because the nVision Reference Recorder uses two independent pressure modules, operators cannot damage either sensor–providing they have selected the appropriate pressure modules for the anticipated static pressure. “Our customers needed a reliable, safe, and portable device for differential measurements at high static pressure. The nVision was already recording from two sensors with extraordinary accuracy across a broad range of temperatures and pressures. Measuring the difference between the two was a logical step for us. However, accurate differential pressure measurement with two sensors was only possible because of the arrow-straight linearity inherent in our technology. At no additional cost, this new capability puts tremendous value in the hands of our users.” said Tom Halaczkiewicz, president of Crystal Engineering.

proprietary FIBER FILM technology and caustic to remove acidic impurities during refining. Reducing high TAN (> 0.1 mg KOH/g) feed levels allows production of higher-quality and more-profitable products from lower-grade and less-expensive crudes. Other advantages of the NAPFINING HiTAN and FIBER FILM technologies are lower capital costs and a smaller plant footprint. “NAPFINING HiTAN is another practical example of the innovation that is driving a transformed Merichem in service to an evolving refining industry,” said

FIG. 1

nVision differential pressure recorder.

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Next-generation technology removes high acidic impurities Merichem Company, introduced NAPFINING HiTAN, a next-generation technology that removes high levels of naphthenic acid compounds in kerosine, jet fuel and diesel. NAPFINING HiTAN is based on Merichem’s popular, cost-effective NAPFINING platform, and it employs Merichem’s highly reliable and efficient

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.

HYDROCARBON PROCESSING FEBRUARY 2011

I 19

HPINNOVATIONS Kenneth F. Currie, Merichem chairman and CEO. NAPFINING HiTAN and NAPFINING technologies employ the FIBER FILM contactor as a mass-transfer device and caustic as the treating reagent to remove naphthenic acid compounds mainly from jet fuel, kerosine and diesel, condensate and crude oil streams. “NAPFINING HiTAN and FIBER FILM are non-dispersive and extremely reliable when compared with commercially available treating alternatives. The smaller footprint and smaller capital expenditure are attractive as well,” said Tom Varadi, vice president and general manager of Merichem Process Technologies. “The onstream factor between routine turnarounds is 100%, whereas electrostatic precipitators are much less reliable and incapable of processing high TAN feeds. Select 3 at www.HydrocarbonProcessing.com/RS

Additives reduce flare SOx emissions Baker Hughes has developed additives specially designed to reduce sulfur oxide (SOx) emissions from refinery flaring oper-

ations. Baker Petrolite SULFIX additives reduce SOx air pollution that is created when hazardous hydrogen sulfide (H2S) is burned; helping US refiners meet the Environmental Protection Agency’s New Source Performance Standards (NSPS) for petroleum refineries. Refineries produce SOx emissions when H2S-laden gases are flared. This combustion process converts H2S to SOx. Now refineries can quickly reduce SOx emissions by treating the flare gas with Baker Petrolite SULFIX additives to reduce the amount of H2S it contains and avoid noncompliance issues without major capital investment. Baker Hughes provides comprehensive services for effective control of flare gas H2S levels to help refiners select suitable additives, use the correct injection system equipment and design, and implement an appropriate monitoring program. “Baker Hughes has successfully applied SULFIX additives and helped refinery customers reduce SOx emissions to comply with environmental regulations,” notes Jerry Basconi, vice president and general manager of industrial services of Baker Hughes. “SULFIX products for flare gas reduce air

pollution from SOx and H2S, improving air quality and environmental compliance.” Select 4 at www.HydrocarbonProcessing.com/RS

Automation module improves tank farm logistics Building on years of experience and technology in terminal and tank farm logistics operations, Emerson has added a movement logistics management module to its Syncade Smart Operation Management Suite. The new application complements Emerson’s established base of instrumentation, control and custody transfer systems for tank farm and terminal product movements. Initial installations include terminals and tank farms in North America, Europe and Asia. Combining the power of the DeltaV automation system with the Syncade suite’s operations management capabilities, the new movement logistics manager application supports marine, rail, truck and pipeline site operations. Key components include order management, logistics planning and scheduling, inventory management, and production accounting. It connects and interacts with every level

Make confidence part of your process Get Aggreko’s dependable temporary utilities, and expect success in all of your operations. From turnaround projects to emergency outages, Aggreko has the equipment you need to maintain productivity—no matter what. Whether your job calls for rental generators, HVAC or more, Aggreko delivers the industry standard of quality every time. With over 50 locations across North America, plus our 24/7/365 service, Aggreko is standing by with the resources you can depend on in your processes— so you can always focus on results.

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I FEBRUARY 2011 HydrocarbonProcessing.com

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Catalyst valve problems? We Have Solutions! The Hemiwedge® Valve was designed to take on the severe conditions of catalyst handling. If you thought there was no alternative to traditional valve designs, we have great news!

The STATIONARY CORE in the Hemiwedge® Valve protects the seating surfaces from the solids ﬂow, resulting in greatly increased service life over conventional metal seated ball valves. In some instances, where traditional metal seated ball valves were lasting 2-3 months, the Hemiwedge® Valve has tripled or quadrupled the service life of the valve . . . and is still going strong!

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A Better IEEE 841 High strength cast iron frame, endplates, conduit box and fan cover are designed to reduce vibration and assure accurate mounting dimensions

Super-E® windings meet or exceed NEMA Premium® efficiency standards

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Oversize bearings on each end for long life

Insulation system meets requirements of NEMA MG 1, Part 31.4.4.2 for VFD use and considered inverter-ready

Inpro/Seal™ VBXX Bearing Isolators at both ends assure protection from contamination

Exclusive PLS® (Positive Lubrication System) assures proper bearing lubrication in all mounting positions

Two-part epoxy primer inside and out, plus epoxy finish coat to prevent corrosion

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Baldor•Reliance 841XL severe duty motors are engineered and built to meet or exceed the most rigid severe duty service standards. You’ll find Baldor•Reliance severe duty motors hard at work around the world in some of the most brutal conditions you can imagine, like petrochemical, pulp & paper and mining operations. So, no matter how you look at it, you can always count on Baldor•Reliance severe duty motors to perform under the most extreme conditions...inside and out.

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HPINNOVATIONS of the operation, from enterprise resource planning (ERP) systems to the devices that load the ships and trucks and open the gate at the terminal. The system manages tasks such as custody transfer of products, printing shipping documents and reporting final accounting results back to the ERP for invoicing. â&#x20AC;&#x153;Todayâ&#x20AC;&#x2122;s pressures on safety, security, cash flow and cost reduction require terminal operations and tank farms in production facilities to be more reliable, repeatable, secure and safe,â&#x20AC;? said Jim Nyquist, president of Emersonâ&#x20AC;&#x2122;s PlantWeb solutions group. â&#x20AC;&#x153;These needs expand beyond physically controlling material movement to managing the business information associated with them. Thatâ&#x20AC;&#x2122;s why Iâ&#x20AC;&#x2122;m proud that Emerson can now offer our customers this powerful, comprehensive solution.â&#x20AC;? Automation can dramatically improve tank farm and terminal efficiency, with fewer people handling more activities and doing it more reliably in less time. Adding integrated order management and scheduling can help to increase the number of trucks and ships handled by the facility. Embedding the knowledge behind a paperdriven process into an electronic system also means the operation can do more with less-experienced employees.

the compressor. The gastight compressor housing eliminates gas emission and losses to the environment. The â&#x20AC;&#x153;Golar Freezeâ&#x20AC;? was converted from an LNG carrier to an FSRU and is capable of storing ~125,000 m3 of LNG and delivering up to 480 million cubic feet per day (MMf3/d) of regasified LNG to Dubai Supply Authority (DUSUP) for further distribution into the Dubai natural gas network. Shell, as DUSUPâ&#x20AC;&#x2122;s appointed

adviser for the project has worked closely with Golar LNG Limited on the development of this project. Laby-GI compressors are used for liquid gas carriers, LNG/LPG FPSOs, FSRUs, LNG RVs and production platforms. They are extremely reliable with unexcelled availability, combining best performance with unmatched operational flexibility and long lifetime. Select 6 at www.HydrocarbonProcessing.com/RS

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Flue gas compressor successfully commissioned On December 10, 2010 Burckhardt Compression successfully completed the mechanical test run of the Laby-GI compressor. DNV certified the test run and issued the survey report. The Laby-GI was commissioned by Golar LNG Limited and Burckhardt Compression on the floating storage and regasification unit (FSRU) â&#x20AC;&#x153;Golar Freezeâ&#x20AC;?, which is now permanently moored at the Jebel Ali port in Dubai. The Laby-GI Compressor is used as a boil-off gas (BOG)/minimum send-out compressor and has been successfully in operation at full capacity. The Laby-GI compressor is fully balanced, eliminating unbalanced forces and moments guaranteeing a smooth operation for all offshore applications. The unique design combines two well established sealing technologies in a single crankgear for lubricated or non-lubricated compression. Therefore, the Laby-GI compressor easily manages the compression of LNG BOG at suction temperatures to -250Â°F (-170Â°C) without pre-heating the gas or pre-cooling

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4PNF WBMWF QPTJUJPOFST BSF EFMJDBUF BOE QSPOF UP QSPCMFNT 8IP XBOUT UIFN 3PCVTU BOE SFMJBCMF '*&-%76& %7$ EJHJUBM WBMWF DPOUSPMMFST IBWF CFFO UFTUFE BOE QSPWFO JO BQQMJDBUJPOT XJUI IJHI MFWFMT PG WJCSBUJPO DPSSPTJPO PS NBUFSJBM FOUSBQNFOU /P NPSF QSPDFTT JOUFSSVQUJPOT DBVTFE CZ MJOLBHF GBJMVSFT°%7$ JOTUSVNFOUT IBWF MJOLBHF MFTT OPO DPOUBDU GFFECBDL UFDIOPMPHZ UP FMJNJOBUF XFBS XIJMF NBJOUBJOJOH BDDVSBDZ 8IBU´T NPSF UIFZ DBO TQPU WBMWF BTTFNCMZ JTTVFT CFGPSF UIFZ JNQBDU UIF QSPDFTT XIFO FRVJQQFE XJUI 1FSGPSNBODF %JBHOPTUJDT %7$ EJHJUBM WBMWF DPOUSPMMFST DBO CF NPVOUFE PO BOZ BDUVBUPS BOE DPNNVOJDBUF WJB )"35 '06/%"5*0/ » FMECVT PS 130'*#64 5IFZ IBWF $4" *&$ '. BOE "5&9 IB[BSEPVT BSFB BQQSPWBMT -FBSO NPSF CZ WJTJUJOH XXX 'JTIFS DPN %7$ Select 69 at www.HydrocarbonProcessing.com/RS

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HPIN CONSTRUCTION HELEN MECHE, ASSOCIATE EDITOR HM@HydrocarbonProcessing.com

North America The Dow Chemical Co. plans to increase ethane-cracking capabilities on the US Gulf Coast over the next two to three years, and improve these capabilities by 20%–30% in this timeframe. In addition, Dow is also reviewing joint-venture options for building a natural gas liquids (NGL) fractionator to secure this ethane supply. Both actions are intended to capitalize on the favorable supply dynamics in North America, and further bolster the competitive advantage of Dow’s plastics franchise, as well as its high-margin, downstream performance businesses. Alfa Laval has received an order for its Packinox heat exchangers to be used in what is said to be the world’s first full-scale integrated-gasification combined-cycle (IGCC) process for power generation with carbon capture, which will be placed in the US. The order value is about SEK 80 million and delivery is scheduled for 2012. The heat exchangers will be used in a gas-treatment process of an IGCC powergeneration plant. The project has received funding from the US Department of Energy and will, when finalized, include a state-of-the-art gasification facility with a capacity of more than 500 MW and an integrated carbon-capture facility. Medicine Bow Fuel & Power LLC has awarded Aker Solutions the frontend engineering and design (FEED) package for its industrial gasification and liquefaction plant located near the town of Medicine Bow, Wyoming. Aker Solutions successfully completed a pre-FEED study for the project in July 2010. Since then, Aker Solutions has worked under a letter of intent to provide services relating to design review and licensor support, as well as additional pre-EPC engineering and design. The facility will produce liquid transport fuels and is due to come online in 2015. When complete, the plant will convert coal into up to 21,000 bpd of gasoline and liquefied petroleum gas (LPG) liquid fuels. The Dow Chemical Co. has announced that Dow and Mitsui & Co., Ltd., of Tokyo, Japan, have completed the forma-

tion of a previously announced 50/50 manufacturing joint venture to construct, own and operate a new membrane chlor-alkali facility located at Dow’s Freeport, Texas, integrated manufacturing complex. The new chlor-alkali facility is expected to begin operations in mid-2013, and will have a capacity of approximately 800 kilotons/yr. The new plant will create approximately 50 long-term jobs at the Freeport location, along with approximately 500 construction jobs.

South America Foster Wheeler AG’s Global Engineering and Construction Group has been awarded a basic engineering design and front-end engineering design (FEED) contract for two grassroots refineries in Brazil for Petrobras. The Premium I Refinery will be a dual-train, 600,000-bpsd facility in Maranhao State, and the Premium II Refinery will be a single-train 300,000bpsd facility in Ceara State. Foster Wheeler will be the prime subcontractor to Honeywell’s UOP, the managing process-technology licensor. The value of the contract was not disclosed. The contract includes basic design and FEED for the main process units and auxiliary units. Petrobras has selected Emerson Process Management to provide process automation technologies and services for the Petrochemical Complex of Rio de Janeiro (Comperj) in Brazil. As the main automation contractor for Comperj, Emerson will deliver engineering services and technologies for integration of the refining unit’s process automation and systems, and selected project utilities and offsite operations. Built on an area of 45 million m2, the Comperj complex will be able to process 165,000 bpd of heavy crude when its first refining unit begins operations in 2013, and the same amount in a second unit is expected five years later. In addition to systems for process control, safety, fire and gas detection, machinery monitoring, and management of process and maintenance information, Emerson will also supply measurement instruments, control valves, pressure regulators, and other related prod-

ucts and services. Engineering work has already begun, with hardware delivery to begin in 2011.

Europe Technip has been awarded an engineering, procurement services and construction-management contract by Total to increase hydrocracker capacity at the Normandy refinery located in Gonfreville, France. This project, which is part of a larger investment plan for the refinery, is valued at more than €100 million (of which Technip’s share is 20%). Technip’s scope includes debottlenecking of the hydrocracking plant and debottlenecking of the hydrogen unit needed to operate the hydrocracker. This extension will increase hydroconversion capacity to 10,000 tpd from the current 8,000 tons, thereby enabling production of more diesel fuel and kerosine. BASF plans to expand its existing superabsorbent polymer-production capacities at its sites in Antwerp and Belgium, and at its Freeport, Texas, site. Gradual debottlenecking and technical expansion measures are to raise annual capacity by 70,000 tons to a total of 470,000 tons by 2012, with each site contributing an additional 35,000 tons A subsidiary of Foster Wheeler AG’s Global Engineering and Construction

Trend analysis forecasting Hydrocarbon Processing maintains an extensive database of historical HPI project information. The Boxscore 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 depends on the size and complexity of the sort requested. You can focus on a narrow request, such as the history of a particular type of project, or you can obtain the entire 35-year Boxscore database or portions thereof. Simply send a clear description of the data needed and receive a prompt cost quotation. Contact: Drew Combs P.O. Box 2608, Houston, Texas, 77252-2608 713-520-4409 • Drew.Combs@GulfPub.com HYDROCARBON PROCESSING FEBRUARY 2011

I 25

HPIN CONSTRUCTION Group has been awarded a contract by Kuwait Petroleum International Lubricants to provide detailed engineering services for a brown-field lube-oil blending plant to be built at Kuwait Petroleum’s facility in Antwerp, Belgium. The lube-oil blending plant will substantially enhance the Antwerp facility’s ability to operate at European scale by increasing production capacity from 125 million lpy to 250 million lpy. The detailed

engineering activities will be completed by mid-2011. The State Oil Co. of the Azerbaijan Republic (SOCAR) and TURCAS Rafineri A.S. (STRAS), the joint venture of SOCAR and TURCAS Petrol A.S. (TRCAS), have awarded Fluor Corp. a project-management consultant (PMC) contract for a new refinery to be built in Aliaga, Turkey. The new planned refin-

Paratherm GLT™ Synthetic Heat Transfer Fluid showed 30% less degradation than a widely used Synthetic Heat Transfer Fluid.

ery will be integrated at the Petkim petrochemicals site on the Aegean coast. As PMC for the SOCAR and TURCAS Aegean Refinery (STAR) project, Fluor will assist STRAS in selecting and managing the engineering, procurement and construction (EPC) contractor(s) and provide overall project and construction management. Project work is underway, with the start of site preparation. EPC work is estimated to be in mid-2011, and construction startup is scheduled to begin in the first quarter of 2012.

Africa Technip has been awarded a contract by Sonatrach, the Algerian national oil company, for refurbishment and revamping of the Algiers refinery. This lump-sum turnkey contract, worth approximately $908 million, will last 38 months and cover the execution of the complete scope of works, including the design, supply of equipment and bulk material, construction and startup. The revamp of the existing installations will enable refining capacity to be increased from 2.7 million tpy to 3.6 million tpy. The new units will allow the refinery to produce gasoline at specifications similar to those in force in Europe. This project will be carried out by Technip’s operating center in Paris, France.

Middle East

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Petroleum Development Oman (PDO) has awarded a seven-year engineering and maintenance services contract (EMC) to Wood Group–CCC, a joint venture set up to provide operations and maintenance services for the oil and gas and petrochemical industries in Oman, Bahrain, Kuwait, Qatar, Saudi Arabia, UAE and Yemen. The contract, which has a three-year extension option, will include integrated engineering, construction, maintenance and support services for existing PDO facilities onshore in Southern Oman.

Shell Global Solutions International B.V. has signed three license agreements with the state-owned North Refineries Co. of Iraq, in Kirkuk, Northern Iraq. Shell Global Solutions will provide a process license and basic-engineering package for a kerosine hydrotreater, a diesel hydrotreater and a vacuum gasoil (VGO) hydrocracker unit as part of the agreement. Each agreement includes the grant

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HPIN CONSTRUCTION of a license to Shell proprietary technology and the provision of engineering services. Agreements for the supply of catalysts and reactor internals are expected to be signed in the future as part of the deal. Based on Shell’s experience as both an owner and an operator, these licensed technologies are likely to provide North Refineries Co. with an integrated solution that will help optimize the new refinery’s operations.

Asia-Pacific CB&I has announced that Lummus Technology has been awarded a contract by Liaoning Tongyi Petrochemical Co., Ltd., for the license and engineering design of grassroots olefins-conversion technology (OCT) units and CATOFIN dehydrogenation units at several of its sites in the People’s Republic of China. The units will produce 684,000 metric tpy of isobutylene and 950,000 metric tpy of propylene.

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Jacobs Engineering Group Inc. has received a contract from CPC Corp., Taiwan, to design and license Jacobs’ proprietary EUROCLAUS technology for a desulfurization unit as part of the Ta-Lin refinery expansion project in Kaoshiung, Taiwan. This project is said to be the first to combine Jacobs’ EUROCLAUS technology with DynaWave technology, which is engineered and licensed by US-based MECS, Inc. The combination of these two unique technologies reportedly makes it possible to achieve very-lowsulfur emissions at low-investment cost compared to existing technologies. The new desulfurization unit will be integral to CPC’s refinery operations. CPC will design and build the Ta-Lin refinery expansion. The new facility, scheduled to be operational in 2013, will produce clean-fuel products for the local Taiwanese market. The Shaw Group Inc. has been selected by GAIL (India) Ltd. to provide its proprietary technology and basic engineering for a new 450,000-tpy ethylene plant. Shaw will also provide support during detailed engineering, procurement and construction, and commissioning and startup of the plant, which will be part of GAIL’s petrochemical complex in Pata, Uttar Pradesh, India. The undisclosed value of the contract was included in Shaw’s Energy & Chemicals segment’s backlog of unfilled orders in the first quarter of fiscal year 2011. Stamicarbon, the licensing and intellectual property center of Maire Tecnimont S.p.A., has signed a license agreement with Inner Mongolia Bodashidi Co., Ltd., in the People’s Republic of China (PRC) for a urea plant with a capacity of 2,860 metric tpd. The plant will be built in the Industrial Zone of Nalinriver, Wushen, Inner Mongolia, PRC. The urea plant will use the Stamicarbon Urea2000Plus pool condenser technology. Stamicarbon will deliver the process design package (PDP) and associated services. The plant will be built by Wuhuan Engineering Corp. of China as the subcontractor of China Chemical Engineering Second Construction Group. Wuhuan has been chosen by the customer as the designated EPC contractor. Startup is planned in 2013. HP

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REFINING

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HPI CONSTRUCTION BOXSCORE UPDATE Company

City

Plant Site

Project

Capacity

Unit Cost Status Yr Cmpl Licensor

Naftec Spa Harouge Oil Operation OCP

Skikda Ras Lanuf Jorf Lasfar

BTX Storage, Oil DAP (4)

CNOOC Rashtriya Chemicals Hyundai Petrochem Co Ltd Chinese Petroleum Corp Map Ta Phut Olefins

Dongfang Thal Vaishet Daesan Kaohsiung Map Ta Phut

Refinery Ammonia Aromatics Extraction Diesel, HDS (2) Aromatics Complex

Hellenic Petroleum SA Montedipe SpA AGIP KCO Petrochemical Holding AG

Thessaloniki Porto Marghera Kashagan Onesti

Thessaloniki Porto Marghera Kashagan Field Onesti

Naphta Aromatics Extraction FPSO Paraxylene

Lukoil

Perm

Aromatics Complex

320 Mtpy

Barrancabermeja Matanzas El Aromo Cangrejera

FCC Gasoline Refinery, Heavy Ends Refinery Styrene

bbl 150 bpd 300 bpd 100 Mtpy

Esfahan Ras Laffan Yanbu

Isomerization MEG Clean Fuels

Benicia Toomsboro Billings Canton Ardmore Houston Woods Cross Medicine Bow

Benicia Toomsboro Billings Canton Billings Houston Woods Cross Medicine Bow

FCC Gasoline Proppant resin FCC Gasoline FCC Gasoline Coker, Delayed Coker, Delayed Benzene Reduction Gasification and Liquefaction

Engineering

Constructor

AFRICA Algeria Libya Morocco

None None None

U 2012 U 2012 P 2013

GTC, Inc Punj Lloyd Ltd Jacobs Engineering SA

Punj Lloyd Ltd Jacobs Engineering SA

U U E A C

2013 2011 2011 2010 2010

Haldor Topsøe HRI Axens GTC, Inc

PDIL KBR|HEC Fu-Tai Engr

HEC Fu-Tai Engr

U U E P

2011 2012 2012 2012

Montedipe

Tecnimont KBR

ASIA/PACIFIC China India South Korea Taiwan Thailand

None bbl Mtpy 50 Mbpd 600 Mtpy

34.6

EUROPE Greece Italy Kazakhstan Romania Russian Federation

2600 400 150 400

bpsd Mtpy kbpd Mm-tpy

184 30000

Tecnimont

GTC, Inc

E 2011

GTC, Inc

30 4300 12500

P P 2015 P 2013 H

UOP

187

E 2011 P F 2013

UOP

LATIN AMERICA Colombia Cuba Ecuador Mexico

Ecopetrol PDVSA Refineria del Pacifico-CEM Petroleos Mexicanos

AltairStrickland PGN

MIDDLE EAST Iran Qatar Saudi Arabia

Esfahan Oil Refinery Co Qatar Shell GTL Ltd SAMREF

27 Mbpsd 1.5 m-tpy None

200

Namvaran|HEC

Dorriz

UNITED STATES California Georgia Montana Ohio Oklahoma Texas Utah Wyoming

Valero Refining Co CARBO ExxonMobil Marathon Oil ConocoPhillips LyondellBasell Industries Holly Corp Medicine Bow Fuel

RE RE RE RE RE

bbl None bbl bbl bbl bbl None 21000 bpd

5 8 8 12

U P P P P P E F

2011

2013 2011 2015

AltairStrickland

FW GTC, Inc Aker Solutions

AltairStrickland AltairStrickland AltairStrickland AltairStrickland

See http://www.HydrocarbonProcessing.com/bxsymbols for licensor, engineering and construction companies’ abbreviations, along with the complete update of the HPI Construction Boxscore.

BOXSCORE DATABASE

ONLINE

THE GLOBAL SOURCE FOR TRACKING HPI CONSTRUCTION ACTIVITY For more than 50 years, Hydrocarbon Processing magazine remains the only source that collects and maintains data speciﬁcally for the HPI community, publishing up-to-the-minute construction projects from around the globe with our online product, Boxscore Database. Updated weekly, our database helps engineers, contractors and marketing personnel identify active HPI construction projects around the world to: • Generate leads • Market research • Track trend analysis • And, decide future budget planning. Now, we’ve made our best product even better! Enhancements include: • Exporting your search results to Excel so you can compile your research • Delivering the latest updated projects directly to your inbox each week • Designing customized construction reports for your company using our 50 years of archived projects. For a Free 2 -Week Trial, contact Lee Nichols at +1 (713) 525-4626, Lee.Nichols@GulfPub.com, or visit www.ConstructionBoxscore.com

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I 31

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HPI VIEWPOINT

Consumer protection is a key issue for E15 NPRA wants to be sure that adding greater amounts of ethanol to gasoline is safe and will not cause engine damage Charles T. 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 US refining capacity and most all petrochemical manufacturers in the US. Prior to his election as president in 2007, Mr. Drevna served as NPRA’s executive vice president and director of policy and 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 and regulatory affairs for the Oxygenated Fuels Association, where he held similar responsibilities, and as vice president at Jefferson Waterman International, a Washington, DC-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, DC, 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.

Americans have long counted on our nation’s petroleum refineries to provide them with safe, affordable, efficient and reliable gasoline and diesel fuel for their vehicles and outdoor power equipment. Unfortunately, a decision last October by the US Environmental Protection Agency (EPA) to authorize the sale of gasoline containing 15% ethanol (E15) for late-model vehicles—up from the current limit of 10% ethanol (E10)—could reduce the safety of the gasoline Americans rely on. Concern about the potential safety threat of a 50% increase in the amount of ethanol in gasoline motivated many refiners and the National Petrochemical & Refiners Association (NPRA), to call on the EPA to conduct thorough and objective scientific tests on the impact of E15 on gasoline engines before authorizing use of the fuel. Unfortunately, the EPA rejected our call and decided to rush to judgment, under pressure from the ethanol industry. As a result, we believe the EPA decision approving E15 for limited use was a disservice to the American consumer.

NPRA is not anti-ethanol—our members blend it with gasoline every day to manufacture the E10 fuel that safely powers most US vehicles. We simply want to be sure that adding greater amounts of ethanol to gasoline is safe and will not cause engine damage. Following the old proverb to “look before you leap,” we believe that learning more about E15 before approving its use is just common sense. Because of our concern with consumer protection, NPRA has filed a lawsuit asking a US appeals court to overturn what we believe was the EPA’s premature and unwise decision to approve the use of E15 in cars and light trucks for the 2007 and later model years. Misfueling. Based on experience with leaded and unleaded

gasoline years ago, we know that millions of consumers would no doubt use the wrong fuel for the wrong vehicle—a problem called misfueling—if E15 becomes widely available. No matter what warning signs the EPA requires gasoline retailers to post at their pumps, many consumers would undoubtedly pump E15 into older cars and trucks and use it in outdoor power equipment, motorcycles, boats and snowmobiles. Some of this misfueling would be unintentional—consumers not paying attention to warning labels on pumps when they drive up in their older vehicles, or filling gasoline cans to run their lawnmowers and chain saws after they fill up their cars without going to a different pump. Some misfueling would be deliberate because E15 may be slightly cheaper than E10 gasoline at times, due to variability in the price of oil. Many consumers would not realize that ethanol packs less energy than gasoline and, hence, gives them lower mileage, canceling out the value of a slightly lower price. The EPA’s decision threatens consumer safety in numerous ways, even if we assume—and we do not—that testing has proven conclusively that E15 is safe for cars and light trucks from 2007 and later model years. Misfueling could cause costly damages to all sorts of gasoline engines. Snowmobile engines could conk out in the middle of the frozen wilderness, and boat engines could fail in the middle of the ocean—stranding people in life-threatening conditions. Chain saws could overheat and run when their operators wanted to turn them off, endangering operator safety. NPRA members don’t want the gasoline they manufacture to cause these kinds of problems for consumers. Like any manufacturer, refiners know the truth of the Ford Motor Co. slogan of the 1990s—“quality is job one.” And no element of quality is more important than safety. Refiners are concerned that if E15 causes engine problems— particularly those that lead to injuries or worse for consumers—a wave of class-action liability lawsuits could follow, seeking billions of dollars in damages. HYDROCARBON PROCESSING FEBRUARY 2011

I 33

HPI VIEWPOINT ■ In early January, NPRA filed suit along

with the International Liquid Terminals Association and the Western States Petroleum Association, asking a federal appeals court to overturn the EPA’s decision to approve the use of E15 for latemodel vehicles. US automakers and engine manufacturers have filed similar lawsuits. Significantly, the ethanol industry has refused to accept liability for engine damage that could be caused by E15. Ethanol producers are happy to profit from E15, but leave it to refiners, retailers and others to remain liable for any damages that E15 might cause. The good news for consumers is that the EPA’s decision does not require refiners or retailers to blend or sell E15 and does not require consumers to buy the fuel. Based on initial opposition to E15—not just from refiners and retailers, but also from the auto, boat, snowmobile and outdoor power equipment industries—it is not likely that E15 will become widely available anytime soon. Nevertheless, NPRA is concerned about harm that E15 could cause to American consumers should it come into widespread use without adequate testing. We are also concerned about procedural irregularities that the

EPA engaged in to cut corners to approve the use of E15 before its use has been justified by scientific testing. For example: • The Clean Air Act clearly requires that any group petitioning the EPA for a waiver to change the blend of ethanol in gasoline provide all the information necessary to approve the waiver. But Growth Energy—the ethanol industry group seeking the E15 waiver—failed to do this, since substantial additional testing by the EPA and the US Department of Energy (DOE) was required. We believe yet more testing and evaluation of data is needed. • The EPA based its E15 partial-waiver decision on studies submitted to the public rulemaking docket on the day before the EPA announced the partial waiver, providing no time for stakeholder review or meaningful public comment on crucial information used to justify the approval of E15. The EPA’s partial-waiver decision was based almost entirely on data submitted to the record after the public comment period closed in 2009. We believe this is a violation of the Administrative Procedures Act. These irregularities are important—not just minor technicalities. If the EPA or any federal agency is allowed to operate outside the constraints of the law, a dangerous precedent would be set, usurping the power of our elected representatives in Congress to pass laws limiting the powers of the executive branch of government. This would open up a Pandora’s box of problems in the future, no matter who is president and no matter what political party is in power at any given time. We believe testing of E15 should continue and be broadened to determine which engines—if any—can safely use the higher ethanol blend.

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HPI VIEWPOINT Things not tested for. DOE testing of E15 simply looked

at the ability of the pollution control equipment of some cars to stand up to E15. The DOE did not conduct needed testing to determine the impact of E15 on: • Engine durability • Tolerance of the check-engine light • Durability of other components, such as the fuel pump and the fuel level sensor

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• Evaporative emissions from fuel leaks and permeation, such as vapors leaking out of an idle car with the engine off and parked outside on a hot and sunny day. Extensive testing in all of these areas is well underway—with the knowledge of both the EPA and DOE—by the privately funded Coordinating Research Council. However, those tests require more time for completion. Many issues of public policy are remote and don’t directly affect the majority of Americans. The fate of E15 is not one of these. The US Department of Transportation estimates there are about 255 million cars and passenger trucks on the road in the US. Millions of Americans own boats, motorcycles, snowmobiles, lawnmowers, chain saws, and other products that run on gasoline. So the safety of E15 is an issue that directly affects just about every American family. The EPA is being sued by a broad range of organizations that object to its E15 decision on a number of grounds. These include claims by the food industry that using more ethanol in gasoline would drive up corn prices and thus raise the price of many food items, and claims by environmentalists that expanded ethanol production and use would harm the environment. We trust the courts will give the issue of E15 the serious consideration it deserves. NPRA believes that, right now, there are just too many unanswered questions about E15 to allow approval of its use. Instead of asking the American people to pump first and ask questions later, the EPA should get more answers first to the many questions remaining about the safety of E15. HP

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CLEAN FUELS

SPECIALREPORT

Slurry-phase hydrocracking— possible solution to refining margins Opportunity crudes require more hydrogen addition to upgrade orphan product streams into higher-value ‘clean’ products M. MOTAGHI, B. ULRICH and A. SUBRAMANIAN, KBR Technology, Houston, Texas

Crude price. The cost of crude is the single most important fac-

tor in setting refinery margins. This is the primary reason for the recent surge in refinery upgrades targeted at processing “opportunity crudes.” While the definition of opportunity crudes is nimble and can vary from refinery to refinery, for the purpose of this article, it makes sense to simply define these crudes as the cheapest possible crude basket available to any given refinery on any given day. This basket may consist of heavy or extra heavy crudes, bitumen-derived crudes, high-acid/high-metals naphthenic crudes or high metals-containing, paraffinic, heavy inland crudes. Most refiners are limited in their ability to handle this wide range of opportunity crudes; more often than not, they are constrained by the residues derived from these crudes. In recent years, the surge in interest over resid upgraders was catalyzed by the growing light-heavy differentials. This, in turn, forced refiners to evaluate their bottoms processing technologies, as margins dictated a higher percentage of heavy oils in their crude diet. Although the large light-heavy differentials have since diminished, this phenomenon is likely to be temporary. The renewed interest in monetizing heavy-oil reserves and the influx of substantial heavy crude volumes to the marketplace suggests that in the long run, refinery margins are likely to return, in large part influenced by the restoration of the light-heavy differentials. Central to this theory is that light-oil fields are on the decline and almost all new

Product quality. Global trends show a growing diesel demand and stable-to-declining gasoline demand (Fig 2). As the world emerges from the global recession and as the growth margin in 40% of the world’s population continues at a rapid pace, this trend can only be expected to amplify. With the majority of existing refinery configurations slanted towards gasoline production, the price differential between diesel and gasoline will widen over the long haul, validating the market tilt towards dieselization. In addition, regulatory demands will only accelerate the shift towards lower density, higher-cetane index, ultra-low-sulfur die34

1.3

1.2

32 1990 FIG. 1

1995

2000 2005 2010 2015 Global petroleum outlook

2020

Sulfur, %

Definitions of profitability. A simple analysis of refinery economics will reveal that margins are largely impacted by three basic factors; crude cost, type of products produced and disposition of low-value, stranded streams. While the first two factors are simple to understand, the relationship between the refiner’s ability to handle these orphaned streams and margins is more complex.

crudes entering the market place are substantially heavier than the current crude basket. This is evident by the decreasing API as shown in Fig. 1, of the composite worldwide crude blend and increasing volumes of extra-heavy crudes such as Canadian and Latin American bitumens. As the world’s supply of crude oil becomes heavier and contains higher sulfur levels, the challenge to the refiners will be compounded by the need to meet the growing demand for light, high-quality, ultra-low-sulfur transportation fuels. This leads to the next major determining factor that sets refinery margins, i.e., quality of products.

API gravity

efinery margins are complex topic; margins are subject to substantial uncertainties and are impacted by global fluctuations in regional feed and product pricing structures. A conscientious analysis of historical data will indicate that for every one good year, on average, refiners are subject to seven years of depressed margins. New globalization trends, which include a changing transport-fuel supply/demand balance, geographic shift in consumption, soaring crude-oil prices, depressed natural-gas prices and impending regulations, all pose interesting challenges to the very survival of many small- and medium-sized refineries.

1.1 2025

Crude API trends, 1990–2025.

HYDROCARBON PROCESSING FEBRUARY 2011

I 37

SPECIALREPORT

CLEAN FUELS

sel production, as the regional outlets for lower quality transport fuels diminish. This combination of lower cost “opportunity crudes” and the need to produce high-quality distillate-selective products is an important consideration for refiners, when making long-term, high-dollar investment decisions. Choices. The least understood variable in determining refin-

ery margins is the disposition of stranded streams. Refineries are littered with low-value streams that are blended off, often downgrading higher-value products for the sole purpose of finding positive outlets for less saleable streams. While the ability to upgrade these streams is a major factor that sets refinery complexity, the solutions for these streams often rests in understanding its potential applications and value within and outside the refining industry. The single largest stranded stream for most refineries is the vacuum residue (VR). The bulk of the operating refineries around the world have little or no residuum processing capability and produce large volumes of high-sulfur fuel oil and bunker fuel. A small volume is used to produce road asphalt. The future of VR is, therefore, intrinsically tied to the future of these three outlets. The large growth market for residues may appear to be the bunker fuel market predominantly influenced by globalization trends and consequential incremental trade and shipping traffic. However, the use of VR as the major blending component in bunker fuel will come under serious scrutiny as new maritime regulations come in to effect starting in 2015 (Fig. 3). This will significantly inhibit VR demands, and the eventual solution may come from either the shipping or the refining industry. While one of the solutions under debate involves using onboard flue gas scrubbers, this issue is more complex. There are several reasons to underscore the reluctance of the shipping indus35

Diesel

Price projection

30 25 20

Gasoline

15 10 5 0 1990

FIG. 2

1995

2000

2005

2010

2015

2020

Demand for gasoline and diesel, 1990–2010.

try to take on the burden of these operating facilities. Regulatory trends are almost always unidirectional, and the shipping industry can only expect the sulfur oxide (SOx) regulations to extend to nitrogen oxide (NOx), particulates, volatiles and other controls, not to mention the added capital investment, operating cost, monitoring and reporting requirements. Conversely, the refining industry is unlikely to invest in expensive VR hydroprocessing with the sole purpose of producing specification bunker fuels. Regulation directs actions. The global trends show a sharp decline in high-sulfur fuel oil demand (Fig. 4), driven mainly by environmental regulations. While the sharp decline in fuel oil prices seen through the mid part of this decade has been temporarily arrested by the installation of many cokers, a reversal can be expected as regulatory pressures extend to the rest of the world. As is evident from the crack margins, producing large volumes of fuel oil will result in negative refinery economics and cannot be sustained. Road asphalt is a relatively small market (Fig. 5), and environmental pressures are also likely to force refiners to produce specification-grade bitumens without resorting to air blowing. While this may lead to investment in alternate technologies such as solvent de-asphalting, the overall impact on the volume of stranded VR or its pricing, will be minimal. All of these factors lead to one obvious conclusion. Going forward, high refining margins will depend upon the ability to capitalize on opportunity crudes, while consistently producing high-quality distillate-selective products from refinery residues. Selecting the appropriate residue upgrading technology, therefore, is a critical part of this puzzle that will define the future of refining and refinery margins. Selecting residue upgrading technologies. To better understand the technology options, one must recognize that VR, in essence, is defined by what is not VR. The quality and quantity of VR is a function of crude selection and the lowest boiling impurity contained within the resid fraction that shows up as the limiting factor in the vacuum gasoil (VGO) fraction that is fed to a catalytic hydrotreater, hydrocracker or fluid catalytic cracking (FCC) process. The choice of resid conversion technology must be set by project economics, preferred reaction chemistry and mechanism of conversion aimed at reliably achieving the overall processing objectives. We present seven questions that one would expect refiners to ponder as they investigate the appropriateness of available technology options. The direct relevance of these questions is premised on projected market trends and is intended to address the desire to achieve and sustain high refinery margins:

Possible delay until 2025 4 3

Global ECA

2 1 0 2005

FIG. 3

Fuel oil demand, million bpd

Sulfur maxium content, %

2010

2015

2020

2025

Expected timeline for IMO regulation enactment.

I FEBRUARY 2011 HydrocarbonProcessing.com

2030

12 Western hemisphere Eastern hemisphere

10 8 6 4 2 0 1990

FIG. 4

Source: Purvin & Gertz

1995

2000

2005

2010

2015

Declining oil demand trend, 1990–2015.

2020

2025

CLEAN FUELS

2.5 2.0

Western Hemisphere Eastern Hemisphere

1.5

Thermal processing or slurry phase

16 14

Ebullated bed or slurry-phase

12 10 8

Resid FCC 6

0.5

FIG. 5

1.0

0.0 1990

weighed against the prevalent market conditions of the past, the conclusions are obvious. However, going forward, with projected high crude oil prices, low natural gas prices and diminishing outlets for low-grade petroleum coke, the need for hydrogen addition is now here. In the rest of this article, we will examine the landscape of the available resid upgrading hydrogen addition technologies against this backdrop. As shown in Fig. 6, the technology choice for resid

Conradson carbon, %

Demand for asphalt, million bpd

1. Has the technology been demonstrated in one or more large scale units? 2. Can the technology handle residues irrespective of the feed quality? 3. Can the technology achieve near complete conversion on a once-through basis? 4. Can the technology produce finished diesel-selective products? 5. Does the technology database demonstrate the ability to handle a whole range of crudes? 6. Can the technology do all of this with high reliability? 7. Can the technology achieve all of this at an attractive net present value (NPV)? Aided by low crude oil prices and high natural gas prices, the delayed coker has, thus far, been the technology of choice for resid upgrading. When tested against the “seven questions” above, and

SPECIALREPORT

Source: Purvin & Gertz

1995

2000

2005

2010

2015

2020

Fixed-bed hydrocracker

2025

Demand for asphalt for road and roofing applications, 1990–2025.

FIG. 6

100 1,000 Metals content, Ni + V ppm

10,000

Resid upgrading technology options as directed by CCR %.

less waste

more profit

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HYDROCARBON PROCESSING FEBRUARY 2011

I 39

SPECIALREPORT

CLEAN FUELS

make the process capital intensive with limited overall benefits. To improve the economics of fixedHot 1st stg. 2nd stg. Offgases bed resid hydrocrackers, the unit must separator reactor reactor sulfur etc. be protected from feed impurities. A feed cleanup unit such as a solvent deasphalter Gas Recycle gas (SDA) may be installed upstream of the cleaning compressor Additive hydrocracker to reject the heaviest CCR and Cold metals containing fraction as a pitch stream. separator C4 The SDA works on the principles of solubility driven separation and is capable Vacuum Naphtha H2 column of lifting light deasphalted oil (DAO) from Middle resid feeds. For most crudes, especially the distillate Makeup lower value opportunity crudes, the overFractionator compressor all lift will be low, limited by the CCR Residue VGO and metal specifications set by the DAO hydrotreating catalyst. FIG. 7 Typical resid hydrocracker flowsheet. As a result of the low DAO yield, the reject asphaltenic stream will be large and can range from 50 wt%–80 wt% of the VR. For refiners who lack an economic outlet for this pitch stream, the hydroprocessing is inherently determined by the metals and Convalue derived from the incremental distillate production through radson Carbon Residue (CCR) content in the residuum. hydroconversion of the DAO is negated by transportation and Fixed-bed resid hydrocrackers. Fixed-bed technologies handling costs associated with moving the pitch from the facility. have been used to hydrotreat residues containing low concentraThus, DAO derived from the vast majority of solvent deasphalters tions of metals and CCR. In most cases, the operation of these operating in fuel services is directed to an FCC unit. units is severely inhibited by the rapid deactivation of the catalyst Fixed-bed resid hydroconversion processes will achieve minisystem. The resultant combination of high operating pressure, low mal overall resid conversion, will produce a large volume of fuel conversion, poor quality products and low catalyst cycle length oil, and are inherently limited by changing feed qualities. This incompatibility is evidenced by high operating pressures, large capital investments, low catalyst cycle length and a maintenanceintensive operating history. The quality of the products will not meet Euro V specifications, and the overall investment will not be commensurate with the derived benefits. When tested against the “seven questions to ponder,” it is obvious that fixed-bed resid hydrocracking technology based schemes would need to be critically examined by the refiner on almost every issue. Vacuum residue

Ebullated-bed hydrocrackers. Another option that has been considered and practiced by refiners for resid conversion is the ebullated bed technology. In this case, the same deactivation phenomenon seen in fixed-bed technologies is inherent with the one exception: the issue of low catalyst cycle length may be resolved through continuous addition and removal of catalysts. Every resid handling process is subject to asphaltene precipitation as the saturates and aromatics contained in the feed that hold the asphaltenes in solution are removed or converted. This phenomenon is essentially driven by asphaltene-solubility chemistry, and the achievable conversion is a function of the saturates, aromatics, resins and asphaltene content in the residue, which in effect defines crude compatibility. In most cases, these units operate at a nominal 55% to 75% conversion, and in an era of “opportunity crudes”, this inherent limitation must be recognized. While refinery economics dictate the need to operate at or near the asphaltene-precipitation boundary limits, the operation of these units can be fairly complex as the refiner balances the need to operate at maximum conversion while minimizing reliability issues associated with asphaltene-induced fouling. With this narrow operating window, any changes in feed quality can contribute to higher maintenance costs and low onstream factors. To achieve a relatively small overall improvement in resid Select 164 at www.HydrocarbonProcessing.com/RS 40

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CLEAN FUELS conversion, and to improve reliability, operators often limit oncethrough conversion, recycle polynuclear aromatics (PNAs) and add other external aromatic-rich streams to help solubilize the asphaltenes, which, in turn makes the process more capital intensive and will result in higher operating costs. Although these processes are catalytic and use metal-containing catalysts, the conversion chemistry is a blend of catalytic cracking and deactivationinduced thermal cracking. Along with the addition of aromatic external feeds, the chemistry will result in lower naphtha, diesel and gasoil qualities requiring the streams to be re-hydroprocessed to meet Euro V product quality specifications. This need to add two catalytic steps makes the process capital intensive, thus challenging the economics of this option. With declining fuel-oil prices, and tightening fuel-oil quality regulations, the large volume of unconverted fuel oil will leave the refiner with much of the same issues to deal with in the post investment scenario, although in a smaller scale. When tested against the “seven questions to ponder,” the choice of crudes, achievable conversion, product qualities, reliability and investment threshold gain significance. Slurry-phase hydrocrackers. With high crude price and

low natural gas prices on the horizon, slurry-phase hydrocracking (Fig. 7) is emerging as the preferred approach for upgrading residue streams via hydrogen addition. The principles of slurry-phase hydrocracking essentially overcome the limitations of fixed-bed and ebullated-bed technologies and provide for substantially higher conversion of the residuum. The primary conversion of residues can be achieved through either catalytic or noncatalytic routes. Investigations for using catalysts or noncatalytic additive systems for primary conversion of the residues can be traced back to the early 1900s and span the entire century, with several hundred patents that have been awarded in support of these activities. Over the past few years, substantial effort has been expended by technology providers exploring nanocatalysts to enable the primary conversion of residues at marginally lower operating pressures. While catalyst-based systems are technically viable, the use of a relatively expensive catalyst system, catalyst deactivation, low quality of derived products and the need for catalyst recovery, all contribute to the economic considerations which in the authors’ view, is likely to make this option less attractive.

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Key performance criteria. We will focus on the non-

catalytic slurry-phase hydrocracking in the context of hydrogen addition and examine the appropriateness of the technology to the current market conditions. HP Extended version avaiable online at HydrocarbonProcessing.com. Mitra Motaghi is a process engineer with the KBR Technology business unit with special focus on resid hydrocracking and VCC technology. She holds an MS degree in chemical engineering from Texas A&M Kingsville.

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CLEAN FUELS

SPECIALREPORT

lobal demand for diesel is projected to grow from approximately 23 million barrels per day (MMbpd) in 2006 to 37 MMbpd by 2030, while the demand for gasoline is expected to increase from 22 MMbpd to 27 MMbpd over the same period.1 This increase in diesel demand (14 MMbpd) is almost three times the increase in gasoline demand (5 MMbpd). Gasoline demand in the US and Western Europe is expected to stay flat or even decrease. These trends have led refiners to consider various options for maximizing diesel production from current operations and/or adding new units targeted at meeting this projected new demand for diesel while improving margins. Olefin demand trends. Demand for light olefins (ethylene, propylene and butylenes)—the building blocks for the petrochemical industry—is also growing significantly. Several announced steamcracker projects are expected to produce sufficient ethylene to meet new petrochemical demand. While the propylene production—a byproduct of liquid-feed steam crackers—will also increase, it will be insufficient to meet the growing future demand. In looking ahead, catalytic cracking is expected to continue to be the prominent propylene source.2

ferential between light/sweet and heavy/ sour crudes is driving the market to process larger quantities of heavier crudes. There are many options on how to upgrade the “bottom of the barrel.” Carbon rejection. Among the carbon rejection processes, delayed coking has been quite popular recently. Solvent deasphalting (SDA) is used to separate residue from deasphalted oil (DAO), which is a feedstock for fluid catalytic cracking (FCC) or hydrocracking units. Although this process maximizes DAO, the pitch (bottoms of the SDA unit) contains very high levels of Conradson carbon residue (CCR) and metal contaminants, thus posing serious concerns for disposal and/or utilization. Visbreaking is also used to reduce residue viscosity while maximizing distillate production. Products from all of these processes require a substantial degree of post treatment to improve quality and to meet desired fuel specifications. Hydrogen addition. Conversely, hydrogen addition technologies, such as atmospheric residue desulfurization (ARDS) and vacuum residue desulfurization (VRDS), produce better quality products. However, because of the high investment and high hydrogen addition requirements, these technologies are used for only about 20% of the global residue upgrading capacity.

Adapting to market conditions.

New challenges. When determin-

The decline in fuel oil demand and tighter fuel specifications, coupled with more stringent environmental regulations, have compressed refinery margins. There is a growing drive to cost-effectively maximize production of high-value products from every barrel of crude oil processed. In addition, the considerable price dif-

ing which process(es) to implement, it is necessary to broadly examine the refiner’s many challenges, including possible changes in product demand, quality and pricing, and the need for the refinery to be able to process heavy/sour crudes. Advancements in process technologies play a crucial role. Now, more than ever, the

ability to upgrade the bottom of the barrel and to produce high-quality products while processing a heavy crude slate are key drivers for better margins. Several options have the capability not only for handling heavy crudes using various residue upgrading technologies, but also for tailoring schemes to maximize high-demand products such as diesel and light olefins. The scheme described here involves the integration of the innovative ebullated-bed hydrocracking process and advanced fluidized catalytic cracking (FCC) processes. The ebullated-bed residue hydrocracking process is a highly effective hydrogenaddition process that upgrades heavy residue feeds to good-quality diesel and FCC feed. The advanced FCC process is a catalytic cracking process that maximizes light olefins from various feedstocks such as vacuum gasoils (VGO), atmospheric residues, etc. This scheme is also flexible enough to shift the product slate to meet fluctuations in the marketplace with respect to the required products and/or the type of crude processed. New hydrocracking process. The ebullated-bed residue hydrocracking processa features high distillate yields while efficiently removing feed sulfur, CCR content and metal contaminants from vacuum residues. It is safe, reliable and easy to operate. Over the years, advances in the ebullatedbed residue hydrocracking process have significantly reduced capital investment and operating costs while extending the conversion and process capabilities, including: • Hydrogen purification systems • Low treat-gas rates • Integrated hydrotreating/ hydrocracking HYDROCARBON PROCESSING FEBRUARY 2011

I 45

SPECIALREPORT

CLEAN FUELS

• Inter-reactor separator/stripper • Third-generation bottoms recycle pan • Onstream catalyst addition and withdrawal • Maintaining constant pressure drop across the reactor • Isothermal reactor operation • Ability to process heavy, high-metals, high-solids content feedstocks. Integrating the ebullated-bed residue hydrocracking unit with hydroprocessing results in significant cost savings. The

recycle of high-temperature vacuum bottoms to the reactor and the use of aromatic diluents, such as FCC slurry oil, help in controlling coke and sediment formation, which could otherwise lead to potential difficulties in maintaining proper catalyst bed ebullation. The advent of membrane purification systems has resulted in very high-purity recycle gas and reduced recycle gas rates to the ebullated-bed residue hydrocracking reactor. This enhances the total reactor operation since internal liq-

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uid recirculation is increased as a result of reduced superficial gas velocity and holdup. This also helps in better back-mixing of liquid and catalyst bed, thereby minimizing incidences of hot spots, catalyst-bed slumping, channeling and flow maldistribution. The ebullated-bed residue hydrocracking process has great inherent flexibility to meet variations in feed quality and throughput, product quality, and reaction operating severities (temperature, space velocity, conversion, etc).3,4 This is a direct result of the ebullated catalyst-bed-reactor system. Online catalyst addition and withdrawal capabilities facilitate in the controlling the catalyst consumption and activity in response to variations in feed quality (metals, sulfur, asphaltenes, etc.) Depending on feed quality, diesel and gasoil (FCC feed) yields in the range of 19 vol%–43 vol% and 30 vol%–40 vol%, respectively, can be produced in the ebullated-bed residue hydrocracking unit. Typical operating parameters, feed quality and product yields can be found elsewhere.3 New advanced FCC process. This

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process combines a proprietary advanced FCC catalyst with proprietary state-of-theart FCC/RFCC technology.b The advanced FCC process is unique for its direct conversion of heavy feeds, such as VGO and residue oils, to high yields of light olefins. It features: • A proprietary advanced FCC catalyst formulation that is: 0 Very selective in cracking molecules of different shapes and sizes to produce high yields of light olefins 0 Highly tolerant of metals and can operate with a high vanadium concentration on the equilibrium catalyst. This feature is very important for residue-feed processing as it minimizes the fresh catalyst consumption rate. • A highly selective reaction system that involves only riser cracking without any recycle of the spent catalyst. • Easy adjustment of operating conditions and catalyst formulation to meet the changing requirements of product demands and feedstock quality. The reactor regenerator section equipment and hardware pieces are designed to utilize the maximum potential of the advanced FCC catalyst with the specific feedstock to produce light olefins. This FCC process utilizes higher riser reactor temperature (530°C–600°C), higher catalyst-to-oil ratio (12–20), and lower hydrocarbon partial pressure to achieve high con-

CLEAN FUELS

the base refinery configuration, which

Crude unit Kerosine + Sat gas Light GO plant

involves adding a new ebullated-bed residue hydrocracking unit and revamping the existing FCC unit to an advanced FCC design. This case is based on the refinery processing 80 vol% heavy crude, as listed in Table 1. The increased volume of heavy crude results in a higher volume of atmospheric tower bottoms (ATB) and vacuum residues (VR). Part of the VR is routed to the ebullated-bed hydrocracking process to maximize diesel product and to produce feed for the advanced FCC unit. The LP modeling studies suggest that a TABLE 1. Crude oil slate comparison Crude name

Base Case, bpsd

Case 1, bpsd

USD/bbl

Maya

35,000

80,000

60.39

Urals

35,000

80,000

64.48

Bonny Light

65,000

20,000

70.57 66.74

Sarir

65,000

20,000

Total

200,000

HT Lt Nap

Lt naphtha Hvy naphtha Crude oil

Case 1. The refinery upgrade (Fig. 2)

Naphtha HT Hvy Nap hydrotreater C5/C6 isomerization HT unit Distillate distillates hydrotreater

DC naphtha LCGO

Atm GO

HC Lt Nap

Vacuum unit

LCO

HC Hvy Nap

Coke

Reformate

LPG

Jet/diesel pool

FCC + gas DC C3s plant Delayed DC C s 4 coker

Reformer

Gasoline pool

HC Dist

FCC gasoline treater

HVGO

Vac residue

FIG. 1

Hydrocracker

HVGO

Atm residue

Petrochemical naphtha

Base Case. The Base Case represents

HCGO

The refinery considered in this study plans to improve its capability to process heavier crudes and also maximize diesel, jet fuel and light-olefin products. The consequences of processing higher quantities of heavy crude are: • A substantial reduction in middle distillate yields or a higher yield of atmospheric bottoms, leading to limitations in vacuum tower capacity • Inferior product quality: 0 Requiring additional treating facilities and/or 0 Resulting in secondary processing units, such as hydrocracking and FCC units, to utilize more hydrogen and/or catalyst. Such a plan is likely to require a significant level of capital investment. To optimize the refinery configuration, an in-house linear programming (LP) model was used that captures the changes in crude quality, optimizes product blend to meet the desired product specifications and estimates the incremental utilities required. The model also features economic evaluation capabilities that account for new investments, incremental utility costs, cost of feed/product, imports/exports, etc. The LP model initially was configured for a base refinery operation, and then reconfigured to account for changes in crude slate and associated effects on the product yields and quality, and changes in costs. These parameters were used in the LP modeling study:

uses a delayed coking unit for residue upgrading as shown in Fig. 1. As indicated in Table 1, the crude blend consists of 35 vol% heavy crude (mix of Maya and Urals) and 65 vol% light crude (Bonny Light and Sarir).

HC Bot

Process integration/reconfiguration.

• In both cases, refinery crude throughput capacity is 200,000 bpsd • Base refinery is currently processing a blend of 35 vol% heavy and 65 vol% light crudes; the reconfigured refinery is expected to process 80 vol% heavy crude • Capacity potential of all existing process units is to be fully utilized • Production of diesel, jet fuel and propylene is maximized while processing the heavy crude slate • Fuel quality is to meet Euro-IV specifications • Crude and product prices are based on Rotterdam 2007 average spot prices. Several configurations were investigated to meet the objectives of the refinery in a cost-effective manner. It was found that incorporating an ebullated-bed residue hydrocracking unit and revamping the FCC unit to an advanced FCC process would provide significant advantages, especially if a refinery is geared to process heavy crudes for the cost advantage. This combination of processes provides the refinery with greater flexibility to accept wider variations in crude quality while optimizing refinery margins. For a better understanding of the proposed scheme, several case studies are presented here.

LVGO

version and selectivity for light olefins. Since all the cracking reactions take place in the short-contact-time riser reactor, with very high catalyst-to-oil ratio and all high-activity catalyst, the selectivity to light olefins is very high. The LPG produced contains about 45 wt%–50 wt% propylene. Total olefins in LPG can be as high as 80 wt%. The major concerns when processing heavier feedstocks having high CCR and metals are: excessive coke make, high regenerator temperature, high dry-gas make and high catalyst makeup rates. The advanced FCC catalyst’s low selectivity to delta coke and dry gas and its high tolerance to metals, in conjunction with the advanced hardware design, allow this unit to easily handle these difficult feedstocks. Demonstrating the full flexibility of the advanced FCC process, it can accept feedstocks ranging from hydrotreated VGO to heavy residue oils and can be designed and operated to maximize propylene, or propylene plus ethylene, or propylene plus gasoline.5

SPECIALREPORT

C4s

Alkylation

FCC gasoline Alkylate

SHT

FCC slurry oil

Simplified flow diagram of the Base Case refinery.

HYDROCARBON PROCESSING FEBRUARY 2011

I 47

SPECIALREPORT

CLEAN FUELS TABLE 2. Comparison of FCC feedstock quality

HT Lt Nap

Lt naphtha Hvy naphtha Crude unit Kerosine + Sat gas Light GO plant Atm GO

Crude oil

Petrochemical naphtha

Lt Nap

Naphtha HT Hvy Nap hydrotreater C5/C6 isomerization HT unit Distillate distillates hydrotreater

DC naphtha LCGO

HCGO HC Bot

HVGO

LVGO

Reformer

Reformate

LCO

LPG

Diesel

VGO

Residue hydrocracker/ HT Bottoms Vac residue

DC C3s

Advanced FCC + gas plant

Vacuum unit

Jet/diesel pool

C4s

FCC gasoline treater Alkylation

FCC gasoline Alkylate

Delayed DC C4s SHT coker Coke

FCC slurry oil

Simplified flow diagram of an upgraded refinery with ebullated-bed residue hydrocracking process and advanced-FCC unit.

TABLE 3. Comparison of process unit capacity Case 1 Incremental

Base Case Process unit

bpsd

Ktpy

bpsd

Ktpy

Crude unit

200,000

9,450

340

Vacuum unit

87,554

4,591

9,430

660

Delayed coking unit

29,570

1,701

—

20,005

1,173

Ebullated–bed residue hydrocracking process FCC (advanced FCC unit)

27,325

1,401

–3,080

–130

Hydrocracker

44,810

2,285

6,300

335

Naphtha hydro treater

27,246

1,159

590

Reformer

40,651

1,710

–3,160

–160

Hydrogen plant, MMscfd Amine regeneration, gpm, DEA SRU + TGT, metric tpd

1,177

415

285

—

C5 isomerization

5,113

195

140

FCC gasoline HT

15,671

669

–6,680

–290

Alkylation

4,365

171

–115

–4

C4 SHT unit

4,335

142

–520

–16

Diesel HT unit

67,028

3,180

180

blend of 80 vol% heavy and 20 vol% light crude is optimal because it maximizes the amount of diesel and light olefins. Even though increasing the heavy crude portion beyond 80% lowers feed cost, it poses 48

I FEBRUARY 2011 HydrocarbonProcessing.com

limits on yields and in meeting Euro-IV diesel quality. The delayed coker capacity is maintained equivalent to the Base Case by processing a blend of virgin VR and ebullated-

Case 1

22.1

18.7

1.12

2.0

Con. carbon content, wt%

1.35

2.5

Nickel, ppmw

0.73

6.2

Total nitrogen, ppmw

Hvy Nap

HC Dist

HVGO

FIG. 2

HC Hvy Nap

Base Case Sulfur, wt%

Vanadium, ppmw Gasoline pool

HC Lt Nap Hydrocracker

Atm residue

Gravity,

°API

1.6

13.8

1,495

2,557

bed residue hydrocracker bottoms. The feed to the advanced FCC unit consists of the heavy vacuum GO (HVGO) cut from the ebullated-bed residue hydrocracking unit and virgin VGO, which is significantly less than the Base Case feed to the FCC unit. To supplement the advanced FCC unit feed, ATB is included as one of the feed constituents. Typically, the inferior feed quality of this stream (Table 2) would adversely affect the FCC product yield pattern and catalyst makeup rate. However, this effect is minimized in the advanced FCC unit as the process can efficiently handle inferior feedstocks without a catalyst cooler and huge catalyst makeup rates. Despite the inferior feed, propylene and butylenes production is increased from 5.1 wt% and 4.1 wt% to 17 wt% and 8.2 wt% in the advanced FCC unit, respectively. The propylene from the advanced FCC unit, after treatment, can be used as a petrochemical feedstock. A portion of the C4s is used to produce alkylate for the gasoline pool. Light cycle oil (LCO) from the advanced FCC unit is processed in the existing hydrotreater. Distillate from the ebullated-bed residue hydrocracker is processed in an integrated hydrotreater/ hydrocracker reactor arrangement, with the hydrocracker processing incremental virgin VGO. Slurry oil (CLO) is recycled to the ebullated-bed residue hydrocracker as aromatic diluent to minimize coke and sediments formation. This scheme has the flexibility to process a higher quantity of heavy/opportunity (i.e., lower cost) crudes and still produce Euro-IV quality fuels and petrochemical feedstocks. Table 3 summarizes the feed capacities of all the processing units. As shown in Table 3, the revised configuration is able to effectively utilize the capacities of most of the existing process units. The FCC gasoline hydrotreating unit and C4 selective hydrotreating (SHT) unit capacities are under-utilized, as the current objective is to reduce gasoline production. As expected, hydrogen consumption is increased con-

CLEAN FUELS siderably and has been considered in the evaluation of the refinery upgrade. Table 4 shows that diesel and jet fuel product increase from a total of 4,387 Ktpy in the Base Case to 4,556 Ktpy in Case 1. Although it is possible to increase jet fuel production, it was limited to the projected demand of 33% over the Base Case (i.e., equivalent to 453 Ktpy). Note: Revamping the existing FCC unit to an advanced FCC design resulted in an increase in propylene from 70 Ktpy (Base Case) to 183 Ktpy in Case 1. Even though the heavy crude content was increased from 35 vol% (Base Case) to 80 vol% (Case 1), it was possible to increase the quantity of diesel, jet fuels and propylene by incorporating the ebullated-bed residue hydrocracking and advanced FCC units. Otherwise, the middle distillates yield/ quantity would have been much lower than that of the Base Case. The incremental butylenes (98 Ktpy) produced from the advanced FCC unit are used to produce alkylate, meeting the internal fuel requirements and minimizing natural gas imports, which is a specific requirement in this case. Alternatively, the incremental butylenes can also be sold separately as a petrochemical feedstock. Economic benefits. The estimated

total installed cost for Case 1 is presented in Table 5, together with the gross margin for the Base Case and Case 1 and the simple payback for Case 1. The economics of the project are attractive, with an estimated simple payback period of less than 3.8 years. The proposed scheme results in significant incentives for refiners aiming at improving crude blend flexibility with increased diesel and propylene production. Conclusions: Several recent factors have influenced the refinery outlook: • Demand and growth of diesel compared with gasoline, coupled with stringent automotive fuel specifications • The use of the refinery as an alternate source for petrochemical feedstocks, leading to integration of refinery operations with a petrochemical complex • Shrinking refinery margins due to higher/volatile crude oil prices, which increase the need to process opportunity/ inferior feedstocks into useful products while enhancing yields, product quality and selectivity. To address these issues, many existing refinery configurations include an FCC unit and delayed coker to maximize gasoline production and to upgrade the bottom

SPECIALREPORT

TABLE 4. Product prices and comparison of product rates and imported feeds Products

USD/bbl

Base Case bpsd Ktpy

bpsd

Case 1 Ktpy

Propylene-PG

74.7

2,401

6,316

183

Euro-IV 92 RON gasoline

76.93

69,511

2,938

63,405

2,664

Petrochemical naphtha

72.78

33,669

1,319

31,935

1,263

Euro IV diesel

82.26

87,023

4059

88,370

4,106

Jet fuel

85.01

7249

328

10,000

453

Sulfur

25 ($/metric ton)

190 (metric tpd)

435 (metric tpd)

152

Coke

30 ($/metric ton)

1,303 (metric tpd)

456

1,525 (metric tpd)

534

94,272

4,387

98,370

4,556

444 (metric tpd)

155

364 (metric tpd)

127

90.07

6,750

281

7,038

294

Diesel + Jet fuels Imported feeds Natural gas ($/MMBtu) MTBE

TABLE 5. Total installed cost, gross revenue and simple payback Investments costs, MMUS$ ISBL

Base

Case 1

—

590.4

Utilities + offsites

—

178.3

Total installed cost, MMUS$

—

768.7

Gross revenue, MMUS$/yr

576.7

780.7

Increase in gross revenue, MMUS$/yr

—

204.0

Simple payback, yr

—

3.77

of the barrel, respectively. However, adding a new ebullated-bed hydrocracker and revamping the FCC unit to an advanced design can result in: • Increased diesel and light-olefins product yields and quality • Process integration via feed/product stream sharing • Improved feed quality for FCC unit • Ability to handle heavier crudes efficiently and more cost effectively. These advantages make the combination of the ebullated-bed residue hydrocracking process and the advanced FCC units an attractive option for refiners. HP LITERATURE CITED For complete literature cited, visit HydrocarbonProcessing.com.

NOTES The process is licensed by Chevron Lummus Global (CLG), a joint venture between Chevron U.S.A. Inc., a wholly owned subsidiary of Chevron Corp., and Lummus Technology, a CB&I company. Process developed by Indian Oil Corp. Ltd.’s Research & Development center, with the stateof-the-art FCC/RFCC technology and know-how of Lummus Technology.

Rama Rao Marri is a principal process technology engineering specialist at Lummus Technology in Houston, Texas. He has more than 17 years of experience in the area of FCC process design, development and technical services. He was the co-inventor of the Indmax FCC process developed by IOC R&D center for converting heavy feeds, including residue to light olefins, i.e., propylene and ethylene. He has about 11 patents and 20 publications/papers to his credit. Mr. Marri has a MS degree in chemical engineering from Indian Institute of Technology, Kanpur, India.

Dalip Soni is the director, FCC Technology, at Lummus Technology in Houston, Texas. He has 30 years of experience in process design, research, development and evaluation of petroleum refining and synthetic fuel processes. The majority of his experience has been related to FCC technology having worked on several design and development projects. He has BS degree in chemical engineering from Panjab University, India, and an MS degree in chemical engineering from Oklahoma State University.

Gary Michael Sieli is the director of process planning for Lummus Technology’s Process Planning Group in Bloomfield, New Jersey, and has been with Lummus since 2002. He has a BS degree in chemical engineering from the New Jersey Institute of Technology and an MS degree in chemical engineering from Rutgers University. Mr. Siele has authored several papers on refinery planning, heavy oil upgrades and delayed coking, and has more than 32 years of experience in the refining industry. Debasis Bhattacharyya is a senior research manger in the R&D Center of Indian Oil Corp. Ltd. He holds a B. Tech degree in chemical engineering from Calcutta University and M. Tech degree from Indian Institute of Technology, Kanpur. He joined Indian Oil in 1991 and has been engaged in providing technical services to refineries on catalyst selection, process optimization, troubleshooting, revamping various refining processes and also the development and commercialization of new technologies. He holds 10 US patents and authored more than 35 papers in national and international journals and symposiums. He is a member of Indian Institute of Chemical Engineers. HYDROCARBON PROCESSING FEBRUARY 2011

I 49

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What are the future fungible transportation fuels? Alternatives hold promises to decrease dependence on crude oil, but they also uncover other challenges in distribution and engine use M. STOCKLE, Foster Wheeler, Reading, Berkshire, UK

he drive to reduce carbon emissions has resulted in the development of a number of alternatives to diesel and gasoline for transport fuels. One of the key factors influencing how readily these fuels could be adopted is the level of infrastructure investment required and how readily these fuels can make use of the existing distribution systems. Based upon recent studies, there are a number of these alternative fuels, and this article will summarize the advantages and challenges of each alternative, paying particular attention to how readily these fuels can be used within the existing infrastructure and fleet. Drive for alternative fuels. The

use of transport fuels other than mineral oil-derived gasoline and diesel is driven by two main concerns—climate change and security of supply. These drivers have seen a number of governments introduce targets regarding renewable content of the transport fuel pool. Often, these targets are influenced not only by the sustainable level of production for the renewable fuel but also how fungible the renewable is in comparison to existing fuels. Fungibility is defined as “the property of a good or a commodity whose individual units are capable of mutual substitution.” For a transport fuel to be fully fungible, it must be capable of completely replacing the current mineral oil-derived fuel in the present infrastructure. Given this definition, this article only considers gasoline and diesel replacements and not fuels like hydrogen or electricity, which would be consumed in completely different engines/power trains and for which the distribution infrastructure is completely different.

Current transport fuels. If we are to consider the fungibility of alternative fuels, we first need to understand the specifications for present-day transport fuels. The major transport fuels used are gasoline, diesel, jet kerosine and marine bunker fuel. The main focus of government legislation has been on fuels used in the road transport industry, that is, gasoline and diesel. These two transportation fuels will be the focus of this discussion. Specifications. The fuel specifications

for both gasoline and diesel are generally set by either state or national government with significant variation around the globe between the specifications required. However, the drive towards clean (low-sulfur) fuels and pressure from engine manufacturers to have consistent specifications globally have seen a general convergence in current or planned fuel specifications world-wide. Key differences now generally relate to the progress toward clean fuel mandates by the individual countries. The key global specifications are those used in the US and the European Union (EU). To illustrate the typical qualities of gasoline and diesel, this article will use specifications from the Worldwide Fuels Charter Category 4 (as this reflect the general trend in fuels specification) to reflect these key performance and quality targets. Table 1 summarizes the key specifications from the Worldwide Fuels Charter Category 4 for gasoline; Table 2 lists diesel specifications. The alternative fuels considered here can be split into either gasoline or diesel replacements. Table 3 lists fuels to be considered. Gasoline replacements. Table 4 compares the typical properties of gasoline replacements with the gasoline specifica-

tion. The advantages and disadvantages of each fuel are discussed here: Ethanol. The amount of ethanol that can be blended into the gasoline pool is generally limited to 10% (although the US has just gone to E15 (15% blend) for 2007+ cars and light trucks). This limitation is imposed by current car engines and TABLE 1. Gasoline specifications from the Worldwide Fuels Charter Category 4 Property

Value

RON

Rvp, kpa (varies by region)

Aromatics, vol% max

kg/m3

715–770

Density,

Benzene, vol% max

Oxygen content, wt%

2.7 max

Olefins, vol% max

10 max

Sulfur content, wt ppm

10 max

Ethanol, vol%

10 max

TABLE 2. Diesel specifications from the Worldwide Fuels Charter Category 4 Property Cetane index Density,

kg/m3

Value 51 820–840

Sulfur content, wt ppm

T95 boiling point ASTM D86°C

350

FAME content, vol%

CFPP, °C

–5

Viscosity @ 40°C cst

2–4

Flash Point, °C

HYDROCARBON PROCESSING FEBRUARY 2011

I 51

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CLEAN FUELS by the present infrastructure. This is due to the corrosive nature of ethanol—some engine components and parts of the infrastructure (for example, filling nozzles on pumps)—need to be specifically designed to handle higher ethanol concentrations. Blending ethanol into the pool also produces challenges in meeting gasoline specifications. Ethanol appears to be a good blendstock, but if we look at the measured properties of pure ethanol, when added to the gasoline pool, it behaves in a far from ideal way. The key impact is that ethanol raises the Rvp, so that the Rvp of the blend is higher than either of the blend components. This can make it difficult to add ethanol to gasoline pools that are already tightly constrained on Rvp. Ethanol also presents problems when transporting fuels. The key issue is that ethanol is soluble in water. If a gasoline blend with ethanol comes into contact with water, the ethanol will preferentially dissolve in the water, not only contaminating the water but also possibly sending the gasoline off-specification. This means that ethanol needs to be added into the blend as late as possible, generally at the terminal before distribution to retail outlets, but after transportation by pipeline or ship. Therefore, refiners often have to blend some or all of their gasoline in such a way that ethanol is not in the pool but that the pool is blended to meet the specifications after the ethanol is added. A number of vehicles are now being produced that can run on 85% ethanol (E85) blends and this offers the opportunity for more extensive use of ethanol. However it would require a separate distribution system and separate pumps at retail stations to avoid issues with contamination. Despite the challenges of using ethanol, it is still the most widely used alternative to gasoline, and Brazil has been running higher ethanol blends (20%–25% ethanol) for some time. In Brazil, it is easy to produce ethanol from a number of readily available feedstocks; it is also possible to use more sustainable, non-food competing feedstocks in the future. The infrastructure issues can be overcome as was demonstrated in Brazil by having flexfuel engines and upgrading pumps. But there is a cost associated with this. Overall, ethanol can be considered only partly fungible, as market penetration beyond 10% of the pool would require dedicated infrastructure. Butanol. This alcohol (butanol) is similar to ethanol but is based on a four-chain

rather than on a two-chain carbon molecule. However, butanol has some advantages and some disadvantages when compared to ethanol. On the plus side, because butanol has a higher molecular weight than ethanol, it has lower vapor pressure, lower water solubility and a higher energy density. The first two attributes mean that it can be more easily added to gasoline than ethanol. In addition, it is less corrosive than ethanol; thus, it can be more easily transported in pipelines and used in vehicle engines in higher blend concentrations than ethanol without the need for extensive modifications. The lower oxygen content of butanol means that more can be blended into the pool before the oxygenate specification is reached. In theory, butanol can be blended at about 18% rather than the 10% limit for ethanol. On the down side, butanol is more toxic than ethanol. Unlike ethanol, there is no body of experience in its application as a transportation fuel. Fischer-Tropsch naphtha. The conversion of biomass into syngas and then into hydrocarbons via the Fischer-Tropsch (FT) process is a prime candidate for producing alternative transport fuels. While this process is primarily aimed at producing diesel, it also produces some naphtha. This naphtha is primarily paraffins with traces of aromatics; thus FT naphtha cannot be used as gasoline or even

SPECIALREPORT

as a gasoline-blendstock without further processing, due to the very low octane of the product. However, FT naphtha can be further processed to improve the octane, with light naphtha routed to an isomerization unit and the heavy naphtha reformed to improve octane. The isomerate and reformate produced are identical in their properties to those produced from similar units processing fossil-derived naphtha. However, this does not mean that an on-specification gasoline can be produced from FT

■ We could potentially

combine technologies to produce fully fungible gasoline and diesel TABLE 3. Fuels considered Gasoline replacements

Diesel replacements

Ethanol

Fatty acid methyl esters (FAMEs)

Butanol

Hydrotreated vegetable oil

Fischer-Tropsch (FT) naphtha

Fischer-Tropsch diesel Di-methyl ether (DME)

TABLE 4. Properties of gasoline replacements Property

Gasoline spec

Mineral gasoline

Ethanol

Butanol

FT naphtha

1071

kg/m3

715–770

740

794

814

700

Benzene, vol%

1% max

Aromatics, vol%

35% max

35%

Oxygen, wt%

2.7% max

2.7

34.8%

21.6%

6.43

RON Density,

Rvp, Mpa

65 kpa

Sulfur, wt ppm

10 ppm

5 ppm

1 2

A higher figure is often used for blending due to interactions in the pool. Ethanol interactions with gasoline are nonlinear and effective Rvp of ethanol is different to the pure Rvp and varies depending on the level of ethanol blended into the pool. The figures used are generally higher than the specification for the blend. Figure used for blending.

TABLE 5. Properties of diesel replacements Property Cetane Density,

kg/m3

Diesel Spec

Mineral Diesel

FAME

HVO

FT Diesel

50–65

70–90

820–840

840

880

770–800

Gaseous at normal conditions

FAME, vol% CFPP, °C

5% max

100%

-5

-5–13

-30– -5

N/A

HYDROCARBON PROCESSING FEBRUARY 2011

I 53

SPECIALREPORT

CLEAN FUELS

naphtha as it is almost impossible to blend gasoline from just isomerate and reformate if a Euro V type specification is to be met. This is due to the octane (aromatics) Rvp limitations of the blend. In this case, every time the blend is changed to meet one of the specifications, one of the other specifications is exceeded. To produce an on-specification blendstock, a third component is needed, such as ethyl tertiary-butyl ether (ETBE) or alkylate. Ethanol is not that useful due to its impacts on the already constrained Rvp of the pool. This means that although FT naphtha is highly fungible, once processed, it is not fully fungible; a fully on-specification product cannot be produced from FT naphtha on its own. Diesel replacements. Table 5 shows the properties for diesel replacements

100 90 80 70 60 50 40 30 20 10 0

Mineral gasoline

FIG. 1

Ethanol

compared to diesel specifications from the Worldwide Fuels Charter Category 4. FAME. Fatty acid methyl esters (FAME) are produced from triglycerides found in animal and vegetable oils. The triglycerides are reacted with methanol (or ethanol to make fatty acid ethyl esters (FAEE) to produce three esters and a glycerine. FAME has some pluses and minuses as a diesel blendstock. It has good cetane, but its high density makes it hard to blend into some pools. The biggest drawback is that FAME is corrosive and can only be blended at relatively low levels into diesel. It can also â&#x20AC;&#x153;go off specification,â&#x20AC;? and, so, it can only be stored for a relatively short time. The level of FAME is limited to 5% by European (Euro V) diesel specifications. This may be relaxed to 7%, but is unlikely to move beyond this.

Butanol FT naphtha Mineral (processed) diesel

FAME

HVO/ FT diesel

DME

Fungibility of alternative fuels as a percentage of total blend.

Ferment

Gasoline

ETBE Alkylation

Dehydrogenation Biomass

C4 isomerization Isomerization

LPG

CCR

Fractionation

Alkylation GasiďŹ cation

FIG. 2

HCK

Possible links for clean fuels and blending components.

I FEBRUARY 2011 HydrocarbonProcessing.com

Diesel

Hydrotreated vegetable oil and FT diesel. Although hydrotreated vegetable oil (HVO) and FT diesel are produced by different processes, the products from the two processes are very similar. The materials can be considered as being the same for the purposes of evaluating their fungibility. HVO is produced from direct hydrotreating of vegetable oil, producing three long-chain hydrocarbons and a propane molecule from each triglyceride fed to the process. The properties of the produced diesel are dependent on the process used with a better quality diesel produced from a dedicated process where the product can be isomerized from a straight-chain to a branched-chain structure. FT diesel produced from biomass via syngas is very similar to HVO once the FT wax has been hydrocracked and isomerized. The products consist almost entirely of paraffins and, in many ways, make an excellent diesel. It is certainly a very good blendstock for mineral oilderived diesels. There are some challenges. Cold-flow properties can be a problem, although this can be improved somewhat by isomerization. The density of the diesel from FT and HVO can also be a problem; typically they are in the range 770 kg/m3 to 800 kg/m3. Thus, they are well below the minimum specification of 820 kg/m 3. This is not a major problem for engines, but could produce issues with consumers achieving much lower mileage because of the lower energy density. A bigger challenge is that the almost total lack of aromatics in HVO and FT diesel can cause problems in engines that have been run previously on mineral-derived diesel. The aromatics in the mineral-derived diesel replace the plasticizers in rubber and plastic. When pure FT diesel is run, the aromatics are stripped out leading to embrittlement and failure of seals and hoses in the engine. It may be theoretically possible to overcome this problem by producing kerosine-range aromatics material from alkylation of gasoline-range aromatics and olefinic liquefied petroleum gas (LPG) to improve not only the aromatics content but also the density of the blend. The aromatics problem can also be overcome by limiting the amount of FT diesel in the blend to around 50%, meaning that FT diesel, while highly fungible, is not fully fungible. Dimethyl ether. Another molecule being evaluated as a diesel replacement is dimethyl ether (DME). This ether can be run in conventional diesel engines with

CLEAN FUELS some modifications. It is produced from methanol made from syngas. DME behaves more like LPG than other conventional fuels, and this means it needs a separate handling and distribution system similar to LPG. DME is not really compatible with conventional diesel. Given this, DME is not considered fungible. Moving forward. Fig. 1 summarizes the limits on the blending of each of the alternative fuels considered. We can see from the figure that none of the alternative fuels commonly considered is actually 100% fungible. None can be used directly as a fully on-specification substitute for either gasoline or diesel. This does not mean that there are no replacements for gasoline and diesel. But these replacements may need to meet different specifications and possibly also require different distribution systems. For example, an E85 gasoline could be produced from ethanol and FT naphtha, but this would require different distribution systems. It may also be possible to produce fully fungible fuels by further processing some of the alternative fuels considered. This article has already considered the option of reforming and isomerizing FT naphtha. Combining this product with butanol may produce an on-specification gasoline and further processing of the LPG from the FT process or from hydrotreating butanol should allow production of a third blendstock for gasoline, and thus meet the current specifications. Combining dehydration with alkylation, oligomerization or ether production (ETBE) should provide a blendstock that allows a non-fossil-fuel-derived gasoline to be produced. Diesel may be more challenging; but, even here, there are options. Producing pyrolysis oil from biomass and hydrotreating this material could produce aromatics containing a high-density material that, when blended with FT diesel, will produce a fully on-specification material. It may also be possible to boost the aromatics content and density by combining gasoline-range aromatics with olefinic LPG to produce an aromatic kerosinerange material. Fig. 2 shows how we could potentially combine technologies to produce fully fungible gasoline and diesel. We have seen that there are a number of challenges in moving away from fossil fuels while making as much use of the existing infrastructure as possible. We have also seen that, while current proven technologies cannot

produce fully fungible fuels, the development of some new and existing technologies means that we may not be far away from a direct replacement for fossil-fuelderived-transport fuels. The facilities to produce these fully fungible fuels will be more complex and will require a level of integration between facilities. Getting this integration right will be key to the attractiveness of the process, and this will involve a holistic approach assessing a wide range of possible options. HP

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Mike Stockle is chief engineerâ&#x20AC;&#x201D;Refining Technology and currently works in Foster Wheelerâ&#x20AC;&#x2122;s Business Solutions Group in Reading, UK. He graduated from Nottingham University in 1995 and is a Chartered Engineer and a Fellow of the IChemE. During his time at Foster Wheeler, he has worked on a number of refining projects ranging from a grassroots refinery configuration studies and FEEDs, through major refinery revamps. Mr. Stockle is an experienced LP modeller and has undertaken a number of studies looking at the impacts of changing markets and legislation on refineries across the globe.

Select 168 at www.HydrocarbonProcessing.com/RS 55

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How to fabricate reactors for severe service Many critical factors are involved in the design and welding of hydrocracking reactors D. QUINTILIANI, G. FOSSATARO and M. DE COLELLIS, Walter Tosto SpA, Chieti, Italy

emand for transportation fuels and other crude oil-based products has been increasing. To meet growing demand for “cleaner fuels,” refiners are using more severe processing methods such as hydrocracking. Demand for refined products has increased to the extent that refiners desire larger hydrocracking reactors that can operate at higher pressures with design conditions that are even more severe. New feedstock diets for refineries utilize more difficult to “crack” crudes; demand for reactors that can withstand higher temperatures (over 450°C) and higher hydrogen partial pressures (12 MPa to 15 MPa) likewise is increasing. Under such severe processing conditions, reactor vessels are constructed from low alloy chromium (Cr)-molybdenum (Mo) steel of various grades.

Severe processing environment. Hydrocracking or crack-

ing, in the presence of hydrogen or dehydrogenating, is a catalytic process; heavy oils are converted into lighter fractions. The upgrading is done by several chemical reactions and involves the saturation of aromatics, cracking (breaking the bonds of chains of Carbon NDR) and isomerization in the presence of hydrogen. Hydrocracking is, therefore, one of the two major conversion processes used by the modern refining industry. The other important process is the fluid catalytic cracking (FCC). However, this processing operation is mainly used to produce gasoline. “Cracking” operations play a more versatile role in refining hydrocarbons. This process can be adapted to produce middle distillates; thus, it is widely adopted due to its ability to provide a wider range and higher yield of quality products. Typical products from hydrocracking include: liquefied petroleum gas (LPG), naphtha, jet fuel (kerosine), diesel, ethylene, lubricating oils and gasoline. Process level. The chemical reactions of the hydrocracking

processes are grouped into two broad classes. The first group includes hydrotreating reaction, during which impurities—such as nitrogen, sulfur, oxygen and metals—are removed from the hydrocarbon mixture. The second group of reactions involves hydrocracking, in which the carbon-carbon bonds are broken with the help of hydrogen, using bifunctional catalysts. Typical variability of hydrogen partial pressure in representative applications is: • Mild hydrocracking of vacuum gasoil (VGO), Arab or Urals: 800 psia to 1,200 psia (5.5 Mpa to 8.2 Mpa)—depending on the desired operating period

• Arab hydrocracking of VGO with 70% conversion mode single-stage once through ( SOT)—1,800 psia–2,000 psia (12.4 Mpa to 13.8 Mpa) • Arab hydrocracking of VGO with 100% conversion mode TSREC—1,800 psia–2,000 (12.4 Mpa to 13.8 Mpa). Typical variability of starting operation temperature of the catalyst in various treatment schedules are: • SSOT, 390°C to 430°C • Second phase of optimized partial conversion (OPC) or TSREC, noble metal catalyst/zeolite, 290°C–350°C, catalyst and base metal/zeolite, 320°C–400°C. As shown here, the severe operating conditions—high temperature, high pressure and high partial pressure of hydrogen—increase the activity of the catalysts. And only under these harsh conditions can the best performance be expected from catalyst materials; and therefore, the refining operations can be more effective. Designing for severe service. Under these extreme con-

ditions, reactors need to be constructed from high-performance materials that are both resistant to high pressure at high temperature and are resilient to corrosive attack from the inside. In fact, the majority of hydrocracking reactors in operation today, are built from a low alloy Cr-Mo type 2.25Cr-1Mo steel. But the trend in recent years is to build hydrocracking reactors with materials with even better performance. A new generation of steels such as low alloy Cr-Mo with enhanced vanadium (V) 2.25Cr-1Mo-0.25V [plate steel SA542 D4a and forgings SA336 F22V (P-No.5C-ASME IX)]. Usage of better-performance materials has increased the service life of high-pressure vessels and can exceed the service life length as compared to those manufactured with more conventional materials, even in cases where hydrogen partial pressures are higher than those comparable to conventional 2.25Cr-1Mo reactors. The industry has seen that 2.25Cr-1Mo-0.25V can provide better mechanical properties at room temperature, hot and creep as compared to conventional 2.25Cr-1Mo. In short, the 2.25Cr-1Mo-0.25V, when compared to conventional 2.25Cr1Mo, is considered to be: • Stronger in tensile strength at elevated temperatures • Less vulnerable to temper embrittlement • Less vulnerable to hydrogen embrittlement • Less vulnerable to hydrogen attack • More resistant to weld overlay disbonding. HYDROCARBON PROCESSING FEBRUARY 2011

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CLEAN FUELS The American Society of Mechanical Engineers (ASME) in the Boiler and Pressure Vessel code has also recognized these advantages. In the ASME VIII Division 2 Ed. 2007, these additions are listed: • Design stress intensity changed for this material, ASME Code Allowable Stress Intensity Changed • 2007 ASME Section VIII Division 2 Pressure Vessel Code permits significantly higher design-stress intensities for 2.25Cr-1Mo-0.25V steel than the previous edition: 2004 Edition: 169.1 MPa @ 454°C, 163.0 MPa @ 482°C 2007 Edition: 199.8 MPa @ 454°C, 164.6 MPa @ 482°C. The conventional 2.25Cr-1Mo material properties are: • 2004 Edition 127.8 MPa @ 454°C, 110.0 MPa @ 482°C • 2007 Edition 149.8 MPa @ 454°C, 112.0 MPa @ 482°C. The significant revision of the allowable stress intensity from the 2004 Edition to the 2007 Edition of the Code, shows, at 454°C an increase of 18.2%, and, in the 2007 Edition, shows an overall increase of the V-modified steel over conventional material of 33.3%. This increase above conventional material means that the V-modified steel will have even greater application in the future. Cost issues. Thanks to all these benefits, reactors can be built lighter and, therefore, cheaper. For the reactor manufacturer, this translates into fewer and lighter movements in the factory, easier transportation, lighter loads on the roads and lighter lifting, which opens up crane availability and using a lighter crane while loading on a ship or during erection, which means less cost. The foundations where the reactor will sit can now afford to be lighter and shallower. Each of these activities provides cost benefits with a

SPECIALREPORT

lighter weight reactor. The industry cannot deny these benefits as they give considerable economic advantage. Manufacturers are becoming more confident in the construction of V-steel vessels and are able to assist the engineering, procurement and construction (EPC) companies in the evaluation of possible alternatives, even hybrid solutions between plate and forgings to assess the best results in terms of operational safety, quality and cost. Another aspect to consider is the inside surface protection. Classically, hydrocracking reactors need to protect their inner surface from direct contact from process fluids. This protection is provided by an internal liner that is capable of protecting the base metal from high-temperature corrosion. This cladding is typically carried out by overlaying a weld metal over the base metal.

FIG. 1

Macro of 2¼Cro-1Mo-¼V decarburization and fissuring in high-temperature hydrogen service.

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HYDROCARBON PROCESSING FEBRUARY 2011

I 59

SPECIALREPORT

CLEAN FUELS

This process of weld overlay uses austenitic stainless steel, usually the type SS 347, niobium-stabilized to resist the phenomenon of precipitation of carbides at the grain boundary, in particular, during construction and, especially, during post-weld heat treatment (PWHT). However, the real purpose of the cladding is for process service of the reactorâ&#x20AC;&#x201D;namely preventing hydrogen (H2) and other corrosive media attacks on the base metal wall of the reactor. A major problem is that an H2 attack can provoke: â&#x20AC;˘ Decarburization of the surface as carbon migrates to the surface of the material exposed to the process fluids â&#x20AC;˘ Carbon at the surface combines with the free hydrogen to form methane (CH4) and causes blistering on the undersurface (see Fig. 1). Tough fabrication process. Following so many positive

characteristics, there must be another side to this coin. And there is, in fact, the only weak link in this design-materials-construction-in service chain is limited to fabrication. All the potential risks are borne by the manufacturer, so it is necessary to assign

these projects to reliable manufacturersâ&#x20AC;&#x201D;experts with credentials. Some of the risks in using 2.25Cr-1Mo-0.25V are: â&#x20AC;˘ Greater sensitivity to weld cracking during fabrication â&#x20AC;˘ Susceptible to re-heat cracking â&#x20AC;˘ Intermediate stress relief (ISR) mandatory for highly stressed-pressure retaining welds and catalyst-bed supports zone â&#x20AC;˘ Greater control required on preheat and inter-pass temperatures â&#x20AC;˘ Higher weld-metal hardness compared to the conventional 2Âź Cr-1Mo steel â&#x20AC;˘ Difficult to guarantee toughness for the V-modified steel with 54 joule impact energy level at â&#x20AC;&#x201C;29Â°C. â&#x20AC;˘ Welding consumables suppliers are limited globally â&#x20AC;˘ Very low toughness of â&#x20AC;&#x153;as weldedâ&#x20AC;? weld deposit prior to PWHT, can cause: o Cracking from not carrying out ISR for sufficient time for nozzle welds o Cracking resulting from weld flaw in nozzle welds o Cracking resulting from cutting nozzle opening through a bed support weld build up after DHT

TABLE 1. Procedures for weld types in reactor construction Before PWHT

After PWHT

After hydro test

Longitudinal welding

MTâ&#x20AC;&#x201C;TOFDâ&#x20AC;&#x201C;MANUAL U.T.

Circumferential welding

MTâ&#x20AC;&#x201C;TOFDâ&#x20AC;&#x201C;MANUAL U.T.

MT â&#x20AC;&#x201C; MANUAL U.T. PHASED ARRAY

MTâ&#x20AC;&#x201C;MANUAL U.T. PHASED ARRAY

PTâ&#x20AC;&#x201C;UTâ&#x20AC;&#x201C;FERRITE

PTâ&#x20AC;&#x201C;UT

Nozzle welding Overlay

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EMISSIONS

REDUCED

FUEL CONSUMPTION

t 4$') ! ÂĄ ' JO )FBU 3FDPWFSZ .PEF t )FBU 3FDPWFSZ 4ZTUFN SFEVDFT GVFM DPOTVNQUJPO t %JSFDU 'JSF .PEF EFMJWFST / ÂĄ' ÂĄ' VQ UP 4$') ! 14* t &RVJQQFE XJUI TQBSL BSSFTUPST FNFSHFODZ LJMM IJHI UFNQFSBUVSF QSFTTVSF TIVU EPXO EFWJDFT t $ " 3 # &1" 5JFS FNJTTJPO DPNQMJBOU 5P DPNQMJNFOU UIF %.1 $VEE &OFSHZ 4FSWJDFT PĂ˛FST UIF 2VFFO $SZPHFOJD storage UBOL XIJDI TBGFMZ TUPSFT NJMMJPO 4$' PO TJUF /JUSPHFO USBOTQPSUT BSF VTFE UP TBGFMZ SFQMFOJTI UIF 2VFFO XJUIPVU JOUFSSVQUJOH QVNQJOH PQFSBUJPOT *ODSFBTJOH PO TJUF OJUSPHFO JOWFOUPSZ BMMPXT GPS HSFBUFS TVTUBJOFE QVNQ UJNFT IPVST ! 4$'. Ă¸FYJCMF USBOTQPSU EFMJWFSZ TDIFEVMFT SFEVDUJPO JO DPTUMZ EFNVSSBHF DIBSHFT BOE SFMJFWFT QPUFOUJBM DPOHFTUJPO PO MPDBUJPO

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CLEAN FUELS

Critical quality issues. Material quality from the mill is critical; consumable-material quality and management are also critical. V-modified steel is difficult to work with and it needs to be managed well. The manufacturer needs to properly plan the construction of the reactor or vessel. From initial material handling, through to cutting, rolling, beveling, welding, heat treating and non-destructive testing (NDT) inspection, all need to be tackled by skilled trained personnel. Moisture problems. The real price to pay for its advantages in mechanical properties is that V-modified steel is extremely difficult to weld. To make the welding easier, an increased overall material management system of the welding process and welding consumables are necessary. In particular, electrodes and flux are subject to intense drying, between 350°C and 400°C, and maintained at temperatures well above 130°C, to remove any sign of moisture. Moisture is extremely harmful inside the welding process; moisture contains hydrogen—the primary element for cracking. It is imperative that even the welding material held in the welding equipment during the feeding process of the weld should be kept at elevated temperatures. The elevated temperatures help avoid forming condensation and ensure that when weld consumable material reaches the weld zone, it is dry and fully cleared of moisture. Managing the welding and controlling the heat treatments helps to obtain the desired mechanical properties, especially the required toughness. From historical evidence, typically the heat-affected zone is the weakest area in most welded metals. In V-modified steel, regarding toughness at low temperatures, the critical zone is the area melted—the weld deposit. Today, despite all the technological efforts, the filler material still faces some difficulties keeping up with the requirements of industry. The welding consumable materials are characterized by very low storage of hydrogen, specifically designed for welding steels with 2.25% Mo, 1% Cr, 0.25% V, resistant to creep and hydrogen attack. The weld metal is resistant to embrittlement caused by the high-temperature service, and is verified during step cooling tests. The values—“X factor” and “J factor”—are very low, on average below 15 and 100, respectively. Another important factor in fabricating reactors in 2.25Cr-1Mo-0.25V is the PWHT. In fact, compared to the conventional 2.25Cr-1Mo, V-modified steel requires a higher temperature PWHT with longer holding times, typically 710° +/–5°C for 8–9 hours. Critical temperature parameters. Specialists in this field recognize that the weld metal on these types of materials has a critical PWHT temperature of 705°C and a holding time at that temperature for at least 8 hours. These two parameters of temperature and holding time are higher than the standard required by ASME where: • ASME VIII Div. 2 Ed. 2009b Table 6.11 for P-No.5C states a minimum 675°C • ASME VIII Div. 2 Ed. 2009b Table 6.11 P-No.5C states a Holding time minimum for tn < 50 mm 1h • Many specialists consider these temperatures and holding times to be insufficient. Therefore, to have good mechanical properties of materials in welding, PWHT is carried out at higher temperatures and over longer periods of time in special furnaces capable of treating whole or sections of reactors from 800 tons to 900 tons.

In addition to these two parameters, the temperature profile is critical. It is essential that the temperature is the same all the way through the reactor body, and that during the temperature rise and fall, the differences in metal temperature is minimal. Problems for reactors where temperatures of the PWHT are not homogeneous can include: • Potentially leave residual welding stresses and generate new stresses due to the different temperatures in various parts of the reactor • Reduce toughness (and risk H2 attack) in the zones under temperature • Increase hardness in the zones under temperature • PWHT at over temperature with over soak (e.g., 720°C/12 h) along with higher X factor and J factor, can compromise stepcooling test results (an accelerated thermal aging test)

Pressure, Mpa

• Field-weld repairs are much more difficult to carry out, due to heating steps necessary in the welding process.

SPECIALREPORT

13.0 12.5 12.0 11.5 11.0 10.5 10.0 9.5 9.0 8.5 8.0 20

35 40 Temperature, °C

FIG. 2

Minimum pressure temperature cure.

FIG. 3

Circumferential welding of 2 x 2¼Cro-1Mo-¼V shell cans with preheat burners. HYDROCARBON PROCESSING FEBRUARY 2011

I 61

SPECIALREPORT

CLEAN FUELS 1Mo-¼ V alloy for service with hydrogen at high pressures and temperatures is under continuous review. American Petroleum Institute’s publication of API 934-F is under development exclusively for this topic. Reactor fabrication. In summary, there are only a small

FIG. 4

Submerged arc welding (SAW) of the 2¼Cro-1Mo-¼V shell cans.

• PWHT and other cumulative heat treatments influence the properties of materials (base metal and weld metal). It is clear that the target must be to create a homogeneous temperature profile over the whole reactor, where the temperature gradient must be steady enough to ensure that temperature differentials do not occur through the thickness of the metal. Also, it can be demonstrated that the PWHT during construction plays a vital role in determining the service life of the reactor, and that, critically, any one activity can jeopardize the success of a project, but none more so than PWHT. A well-executed PWHT can be proven to extend the service life of the reactor. Non-destructive testing. Another very important aspect in the construction of the reactors is nondestructive testing (NDT). For reactors in 2.25Cr-1Mo-0.25V, the acceptance criteria are necessarily higher and more stringent than conventional steels. Even small indications may give rise to problems later in fabrication, where they can be a trigger for defects with greater importance, such as cracks. Table 1 lists examples of typical examination procedures used on certain weld types in the manufacturing cycle. Fitness for service. A final consideration should be made to

the minimum pressurization temperature (MPT). Process equipment fitness-for-service assessments using API RP 579 is a sophisticated prediction tool to assess the metallurgical condition of a section of process equipment. The analyses of stresses and strains of pressure equipment can assist in predicting whether operating equipment is fit for its intended service. The studies predict how the material will behave according to certain operating conditions and is used to establish an MPT curve. This curve provides an accurate limit for operating characteristics. In this manner, startup and shutdown procedures can be set closer to these limits, making the plant more flexible. If the MPT is under the curve, then we are in optimal conditions. Other critical information necessary to calculate the MPT include actual data from the material used. There is a direct correlation between the X and J factors and MPT. The lower the X and J factors, the lower the MPT. And to achieve a low X and J factor, then cleaner materials with fewer impurities are necessary. Fig. 2 shows a typical MPT curve. This field of research regarding the use of materials and process standards for fabrication of heavy-wall vessels of 2¼ Cr62

I FEBRUARY 2011 HydrocarbonProcessing.com

number of key factors that greatly influence safer reactor fabrication. Intensive training of all personnel involved in the fabrication and inspection of the reactor is paramount. It is important that each individual takes responsibility and care for himself, his (her) fellow workers, as well as the entire team. The importance of special care required in the management of welding consumables is also illustrated here. We have highlighted the importance of good reliable automated process control during each of the welding phases—from pre-heating, to welding, to post-weld heat treating. Control of the complete manufacturing process should be guaranteed by developing and following specific welding procedures, and by fixing welding parameters in production with automatic continuous recording and control methods. To minimize the risk of premature brittle fracture, it is advisable to have an ISR furnace in the shop. It is indispensable to be critical in NDT, as small indications can propagate into larger failures. Consequently, specific training and qualification are required for all technicians and operators. Finally, and arguably most importantly, it is important to have reliable execution of PWHT procedures, with well controlled furnaces and skilled personnel to guarantee precise temperature curves with a temperature profile no greater than +/- 5°C. HP BIBLIOGRAPHY ASME CODES API 579 API 934-A & -B API 941

Davide Quintiliani is an international welding technologist and international welding inspector, and II Level of several NDE techniques. He joined Walter Tosto in 1996 as a quality control Inspector; in 2004, he became head of the quality control department with roles of NDE and welding coordinator. From 2008 to present, he is the head of the welding department, chief welding coordinator and material selection specialist. Mr. Davide has a degree from the University of Chieti G. D’Annunzio, in health and safety at work and a second degree in techniques of loss prevention at work and the environment. He has authored 24 technical articles regarding PED, quality, NDE and welding.

Giacomo Fossataro is the technical and operation manager at Walter Tosto with global responsibility for design, manufacturing and quality control activities. He started his professional career in Walter Tosto’s technical department and has held many positions within Walter Tosto including head of technical department and manager of site activities. Mr. Fossataro holds a degree in engineering (industrial technologies) from the Politecnico di Milano.

Michael De Colellis is a project manager at Walter Tosto SpA in Chieti, Italy. He has a BE degree in manufacturing systems engineering from the University of Hertfordshire, UK, and an MSc degree in advanced manufacturing systems and technology, from the University of Liverpool. Mr. De Colellis began in the automotive and earthmoving equipment industry, working from quality engineer to quality manager, at General Motors and Case New Holand, before transferring into the oil and gas pressure equipment construction business.

CLEAN FUELS

SPECIALREPORT

Designing atmospheric crude distillation for bitumen service Oil sands add complexity to separation units and require a new approach M. GRANDE and M. GUTSCHER, Fluor Canada Ltd., Calgary, Alberta, Canada

itumen blends derived from the Alberta oil sands are becoming a significant feedstock for North American refiners. In 2009, Canada produced about 1.5 million bpd of raw bitumen with about 0.46 million bpd of bitumen blends exported to the US.1,2 This export figure becomes even larger when considering bitumen blends that are commingled with conventional heavy oil and are, therefore, classified as conventional heavy oil, such as Western Canadian Select (WCS). The steep production decline from Mexico’s Cantarell field and Venezuela’s recent shift toward non-US markets, such as China, could make securing supplies from Canada more attractive.3 Many US refineries in the Gulf Coast area are already configured to process heavy oil and a pipeline network is already established to transport oil sands production to refineries located within Canada as well as in the US West, Midwest and Gulf Coast areas.1 Additional pipeline capacity has been recently completed to the US Midwest with additional proposals for other areas, including the Gulf Coast, indicating that more refiners will have access to feedstocks containing bitumen.

BACKGROUND

Bitumen from the Alberta oil sands has an extremely high viscosity (typically approaching 1 x 106 cSt at 15°C) and a high asphaltene content approaching 20 wt% C5 insoluble. Consequently, transportation of bitumen is accomplished by forming blends with a diluent comprised of gas condensates or naphtha (C5+) that is termed dilbit, with synthetic crude oils termed synbit, or a combination thereof referred to as syndilbit. The blending ratio for dilbit is typically about 70:30 bitumen to diluent by volume; whereas for synbit, the blending ratio is typically 50:50. These blending ratios are based on meeting pipeline specifications of 18°API and 350 cSt. Bitumen from the Alberta oil sands is similar in gravity but typically much more viscous than the “extra heavy oil” produced from Venezuela’s Orinoco Belt.

• Increased salt hydrolysis in the fired heater as desalting a dilbit feed has not been proven commercially reliable. Processing issues. Processing bitumen blends, particularly dilbit containing Athabasca bitumen from the Alberta oil sands that is the focus of this discussion, requires specific considerations that impact the design of a crude unit within an upgrader or the revamp of such a unit within an existing refinery. Revamp considerations may include existing crude units that will process various bitumen blends with other conventional feedstocks. In the case of an upgrader, this unit is often referred to as the diluent recovery unit (DRU) because the recovered naphtha/gas condensate is recycled as transportation diluent. Refiners processing dilbit or other feeds may also sell a portion of the recovered naphtha/condensate as transportation diluent as opposed to further refining this material for the gasoline pool or as a petrochemical feedstock. Due to a shortage of diluent in Alberta in 2009, more than 60,000 bpd of diluent was returned to Alberta by rail from the US.1 The completion of the Enbridge Southern Lights diluent pipeline will provide the capacity to deliver 180,000 bpd of diluent to Alberta from the US Midwest. Furthermore, with the use of the Capline pipeline, diluent from the US Gulf Coast area will be able to connect with the new Enbridge pipeline via the Chicap pipeline.1 DRU COLUMN DESIGN

The main objectives of a DRU column are to recover transportation diluent remaining in the column feed (after preflash) and to fractionate distillates, such as atmospheric gasoil (AGO), from the bitumen feed that can be processed directly in a hydroprocessing unit. To achieve these objectives, a typical column configuration, as shown in Fig. 1, consists of a diluent rectification section, an AGO pumparound section, an AGO product-side stripper, an AGO wash section and an atmospheric residue (AR) stripping section.

Challenges with bitumen. Some other challenging proper-

Naphtha rectification section. The degree of fractionation

ties of bitumen from the Alberta oil sands include: • Higher fouling tendencies and a lower thermal stability than other higher hydrogen-content crudes due to a high aromatic content, particularly asphaltenes • Large atmospheric residue (AR defined as 343+°C TBP) content of approximately 85 vol% • High total acid number (TAN) value of approximately 2.5 to 3.5 mg KOH/g, a high sulfur content of approximately 4.5 wt% to 5 wt%, and a high nitrogen content of approximately 0.3 wt% to 0.55 wt%

required between the recovered naphtha in the DRU column overhead and the AGO product is dependent on whether the recovered naphtha will be further refined or will be returned as transportation diluent. If the recovered naphtha is further fractionated and refined, the downstream naphtha processing units will determine the naphtha endpoint and the sharpness of fractionation required. When the recovered naphtha is returned for transportation purposes, the degree of fractionation between the recovered naphtha and the AGO product is typically determined HYDROCARBON PROCESSING FEBRUARY 2011

I 63

CLEAN FUELS

HERMETICALLY SEALED SUBMERSIBLE PUMPS

Not the length is important … …but the technique ■

Abstain from drive shafts being long and susceptible to troubles

■

Spare needless shaft and guide bearings

■

Forget complex and cost-intensive seal technology

■

Require best available technology for a long service life and high availability

based on the percentage of diluent recovery desired while maintaining a total recovered diluent composition that is essentially the same as the originating feed diluent, i.e., provide sufficient fractionation gap between the diluent and the AGO products. As the initial boiling point of bitumen typically resides in the kerosine boiling range, providing this fractionation gap is easily achievable based on the typical boiling range of transportation diluent. If the naphtha is recycled for use as transportation diluent, the recovered naphtha from the DRU column overhead, together with that of the preflash section, is typically routed to a reboiled stripper to remove hydrogen sulfide (H2S) and other light materials. The level of H2S stripping is dependent on the amount of cracked H2S formed in the fired heater and is a function of the feed sulfur content and film temperatures reached in the fired heater. Significant diluent losses to the overhead of a stripper may be incurred if a stringent vapor pressure specification also applies. For these cases, the recovered naphtha may be processed through a refluxed column (i.e., a debutanizer) that will also achieve the required H2S specification. The rectification section of a refluxed column ensures that a high diluent recovery is maintained. AGO PA and product stripping. The AGO pumparound (PA) section removes a significant portion of cooling duty lower in the column to help condense the AGO product and the AGO wash oil sent to the wash section. The heat removed in the AGO Preﬂash vapor Offgas Recoverd naphtha

Sour water

if 2 or 20 meters – we are ﬂexible

support and cable pipe

Fired heater COT, COTMax +/- °C

extremely short drive shaft

Typical DRU column configuration.

120

114

108 COT

102

-5

90 Diameter

-10 -15 25

Select 171 at www.HydrocarbonProcessing.com/RS 64

AR product

Column feed from ﬁred heater

FIG. 1

HERMETIC-Pumpen GmbH P.O. Box 1220 D-79191 Gundelﬁngen info.hp@lederle-hermetic.com www.lederle-hermetic.com

AGO product

FIG. 2

45 55 65 Diluent preﬂash diluent feed, %

Diameter DBase, %

pressure / discharge line

Stripping steam

84 75

78 85

Impact of diluent preflash on fired-heater COT and column diameter.

CLEAN FUELS PA section reduces the vapor traffic and the resulting required column diameter of the diluent rectification section while providing higher heat recovery than that available from the column overhead. The AGO withdrawn from the DRU column is steam stripped in a product side stripper for flash point reduction. The TAN content of the AGO material is typically about 2 mg KOH/g. This TAN content requires upgraded metallurgy for this column section, as well as for the hot portions of the AGO PA and product circuits.

SPECIALREPORT

the preflash for a fixed AGO yield. Trays are best suited to achieve multiple stages of fractionation in this section. The bottoms stripping section requires a smaller diameter relative to the upper sections based on the steam and stripped hydrocarbon vapor loading. However, to minimize column height, using a full-diameter sump is more practical for providing the required AR product residence time. An internal cylinder may be utilized with multi-pass trays (preferably two-pass) that minimize liquid stagnant zones with suitable active and fractional hole areas that will minimize fouling and maximize tray efficiency.

AGO wash section. The degree of fractionation required

between AGO and AR products is based on the desired distillate yield and endpoint specification (ASTM 95% temperature). The yield of AGO and its associated endpoint is determined by the level of distillate hydrotreating required to meet distillate product specifications while minimizing AGO material in the AR product. The objectives of the wash zone are to minimize AGO product endpoint by rectifying the flash zone vapor, and to de-entrain AR in the flash zone vapor. Minimizing the endpoint for a desired yield will improve the quality of the AGO product that is fed to a hydroprocessing unit. The wash section also minimizes the amount of solids/ultra fines, which can be particularly troublesome with mined bitumen feedstocks, from entering the AGO product draw. The selected wash-oil rate and design of wash section internals is important to ensure that the listed objectives are achieved. The wash-oil rate should be based on the governing requirement between the required rectification for the AGO endpoint specification and the required overflash for de-entrainment of AR/ solids. Overflash is defined as the true reflux, excluding entrained liquid that exits the wash section. Good fractionation between the AGO and AR products is best achieved with a combination of a low specific surface area (grid) type packing that is placed as a bottom layer followed by a higher specific surface area (structured) type packing as a top layer. The resulting combination improves the de-entrainment and fractionation ability while maintaining a reasonable packed-bed height and minimizing fouling. The larger open area (relative to trays) also allows packing to better handle a sudden increase in vapor rate, such as an upset that can occur if a liquid water slug is carried over in the feed to the fired heater. Bottoms stripping. Bottoms stripping improves the fractionation between AGO and AR products and allows for decreasing the fired-heater coil outlet temperature (COT) or increasing

PREFLASH TARGET CONSIDERATIONS

Due to the large amount of transportation diluent in the dilbit feed, a preflash system is often applied. The preflash removes a substantial portion of this diluent to lower the flow through the remaining preheat circuit and the fired heater, as well as to reduce the DRU column diameter. The main process parameters involved in achieving distillate lift are diluent slip (diluent that is remaining in the column feed), stripping steam and fired-heater duty at the permissible COT. Diluent slip and stripping steam assist in stripping distillate material in the bitumen feed that allows for a lower fired-heater COT or an incremental gain in AGO yield. The fired-heater COT required for reliable operation in bitumen service is typically lower than that encountered when processing light conventional crudes. Consequently, optimizing the preflash target requires assessing the impact that the diluent slip and stripping steam rate have on the fired-heater COT and column diameter. This assessment should also include the costs associated with producing the steam required and treating the resulting sour water produced. These concepts in optimizing the preflash section can also be applied to the revamp of an existing crude distillation unit (CDU) to unload the upper portions of the column and column-overhead system. These areas may become bottlenecks due to the high naphtha content of dilbit feeds even with preflash processing schemes. Column diameter assessment. The impact that the

diluent preflash has on the DRU column diameter and firedheater COT is illustrated in Fig. 2 This figure is based on the column configuration discussed earlier with a fixed stripping steam rate as well as a fixed AGO yield and endpoint specification. Fig. 2 illustrates that the fired-heater COT is reduced as diluent preflash decreases at a fixed stripping steam rate. However, 120

3.6

120

Diameter 5

102

96 90

-5 COT

-10 -15 1.25

FIG. 3

1.75

2.25 2.75 3.25 Stripping steam rate, % AR

3.75

78 4.25

Impact of stripping steam rate on fired-heater COT and column diameter.

3.3

114

3.0

108

2.7

102

2.4

2.1

90 Diameter

1.8 1.5 25

FIG. 4

45 55 65 Diluent preďŹ&#x201A;ash, % diluent feed

Diameter, % DBase

108

Stripping steam rate, wt% AR

114

Diameter DBase, %

Fired heater COT, COTMax +/- Â°C

Steam rate

84 78 85

Impact of diluent preflash and stripping steam on column diameter. HYDROCARBON PROCESSING FEBRUARY 2011

I 65

SPECIALREPORT

CLEAN FUELS

this reduction is obtained at the expense of significantly increasing the column diameter due to the additional diluent feed (vapor traffic) to the column. The higher (and lighter) content of diluent in the column feed provides marginal incremental lift with single-stage separation that occurs in the flash zone. This single-stage separation, coupled with the resulting relative volatility of the diluent mixture, does not effectively reduce the required fired-heater COT when the resulting impact on column diameter is considered. Consequently, fired-heater designs that allow for an incrementally higher COT while maintaining suitable film temperatures and residence times will significantly reduce the required column diameter due to the allowable diluent reduction in the column feed. Achieving this incrementally higher COT may also have a significant impact when considering the revamp of an existing CDU. Any modifications to the fired heater that will achieve a higher COT will allow for a higher preflash (practicality needs to be determined on a case-by-case basis). This higher preflash will unload the upper portions of the column and column-overhead system that may result in a higher dilbit feed throughput to the existing unit. The impact that the stripping steam rate has on column diameter and fired-heater COT is illustrated in Fig. 3. This figure is based on the column configuration discussed earlier with a fixed-column feed diluent content as well as a fixed AGO yield and endpoint specification. Fig. 3 illustrates that the fired-heater COT is significantly reduced as the stripping steam rate increases. Furthermore, the corresponding column diameter increase is not as significant as that required to achieve the same effect by increasing the diluent content in the column feed (see Fig. 2). The stripping steam provides more incremental lift due to its higher relative volatility and multiple stages of fractionation provided in the stripping section. Another advantage that the stripping section stages provide is sharper fractionation between the AGO and AR products. Consequently, the combined vapors from the stripping and flash sections require less rectification in the wash section. If the washoil rate is dictated by the AGO endpoint (i.e., the rectification requirement discussed earlier), the required wash-oil rate will decrease. This decrease will further lower the required fired-heater COT because less bitumen material needs to be lifted to supply the required wash-oil rate. The disadvantage of significantly increasing the stripping steam rate is the increased operating costs associated with supplying steam and treating the additional produced sour water. Furthermore, the water dew point of the column overhead increases and needs to be addressed in the design of the overhead system. With the fired-heater COT set to the constraint established, the required column diameter vs. diluent preflash and stripping steam rate may be determined. Fig. 4 illustrates this relationship. Single-stage preﬂash system

FIG. 5

Column feed

PREFLASH TARGET OPTIMIZATION

Considering the impact that preflash has on the DRU column diameter, the overall preflash target can be optimized with the remaining unit capital and operating costs. This optimization should consider the cost of steam required for stripping, the operating cost to treat the resulting produced sour water and any environmental issues/limitations in water usage. The preflash target will also have implications on the heat-integration scheme. As the diluent preflash is increased, the preheat temperature required for preflash can increase significantly. For the example utilized in the earlier figures, the preheat temperature required for a total diluent preflash of 55% is 185°C and increases to 235°C for a total diluent preflash of 80%. These temperatures are at the second stage of a two-stage preflash drum configuration. The preheat temperature(s) required to achieve the desired preflash can have a significant impact on the heat-recovery arrangement and on the utility heat and/or fired heater duty. Therefore, the resulting heat integration scheme, including the cost benefits of using utility heat and the desired flexibility in preheat/preflash control, should be considered. Preflash configuration. The preflash

Two-stage preﬂash system

Preﬂash vapor

Dilbit feed

This figure is based on the column configuration discussed earlier with a fixed AGO yield and end-point specification. Fig. 4, as expected from Figs. 2 and 3, illustrates that column diameter is reduced when diluent preflash is maximized. This trend is observed up to a preflash value of approximately 80%. At this high level of preflash, limitations of the overhead system to maintain column reflux and a margin above water dew point become a concern. For a two-stage condensing configuration (as shown in Fig. 1), as the amount of preflash increases, the hydrocarbon flowrate at the column overhead decreases and the steam rate increases. This combined effect significantly increases the steam partial pressure, which reduces the amount of condensable material available for column reflux at a fixed condensing temperature. At a diluent preflash of about 80%, the net overhead liquid product available from the reflux drum is fully consumed by the reflux requirement. To increase preflash beyond 80%, the reflux temperature must be reduced and/or AGO PA duty must be shifted to the overhead system. Reducing the reflux temperature is not desirable as this quickly eliminates any margin between the reflux temperature and the water dew point temperature of the column overhead. This reduced reflux temperature may lead to water condensing in the first-stage overhead drum. Shifting the PA duty to the overhead condenser increases the vapor traffic in the naphtha-rectification section, which will increase the required column diameter, reversing the trend of increasing preflash. Furthermore, shifting the PA duty reduces the amount of high-level heat that can be recovered from the column through heat integration.

Preﬂash vapor

Dilbit feed

Preflash configurations.

I FEBRUARY 2011 HydrocarbonProcessing.com

Column feed

target may be achieved with either a singleor multiple-stage preflash configuration, as illustrated in Fig. 5. A preflash column is not generally required due to the significant volatility gap between the portion of transportation diluent preflashed and the bitumen. Preflash drum(s) will provide adequate separation within the range of preflash levels presented in the earlier examples without impacting the desired fractionation between the diluent and the AGO products.

CLEAN FUELS

Design. Dilbit feeds contain water and light-diluent compo-

nents that significantly increase the feed vapor pressure (particularly water). To achieve higher levels of preflash, the required preheat temperatures increase, resulting in very large increases in the feed vapor pressure. An advantage of the two-stage configuration is that the desired total preflash can be controlled at the second stage, allowing the first-stage preheat temperature to be selected independently of the total desired preflash. The preheat temperature for the first stage can be selected with the objective of only removing all of the free water normally present in the feed, thereby minimizing the vapor pressure of the first stage. Minimizing this vapor pressure will minimize the resulting operating pressure required to suppress vaporization in the first-stage preheat circuit. The desired total preflash is then fully accomplished in the second stage at a comparably lower vapor pressure than that required with a single-stage configuration. Consequently, the head requirement of the preflash feed pumps as well as the design pressures of downstream exchangers/piping in both stages for a two-stage system are reduced compared to a

single-stage system. These reductions are achieved at the expense of adding a second-stage flash drum and pump. The intent is to reduce cost with the reduction in heat-exchanger design pressures and piping flange ratings permitted by a two-stage configuration. Fig. 6 illustrates the reductions in vapor pressure achievable with a two-stage system by plotting the resulting vapor pressure vs. the desired preflash with a single- and a two-stage flash-drum configuration. For the two-stage configuration, the first-stage flash is maintained constant with the objective of only removing all free water resulting in a first-stage preflash of approximately 27%. To achieve the total desired preflash, any additional diluent flash is generated with the second stage. 4,000 Single stage

3,500 Vapor pressure, kPaA

To minimize fouling and provide reliable parallel flow control for multiple heat-exchanger services and fired heater, single liquid phase dilbit preheat is desired. Single-phase dilbit preheat should be maintained through to the inlet of the preflash flow control valve(s) and the inlet of the fired-heater pass control valves. To suppress vaporization at the required preheat temperatures, an adequate pump head must be supplied with the dilbit control valve(s) placed at the back (i.e., hot) end of the preheat circuit(s), immediately upstream of each stage of preflash.

SPECIALREPORT

3,000 2,500 2,000 1,500

Second stage

1,000 First stage 500 0 25

FIG. 6

45 55 65 Diluent preﬂash, % diluent feed

Effect of diluent preflash on vapor pressure.

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SPECIALREPORT

CLEAN FUELS

Fig. 6 illustrates that the resulting exchanger design pressures, piping flange ratings and combined pump-head requirements for the single-stage preflash configuration become much greater than for the two-stage configuration as the diluent preflash increases. Consequently, a two-stage configuration may become more appealing for higher levels of diluent preflash. For integrated mineupgrader facilities, where higher unit feed dilbit ratios are encountered, it may be desirable to achieve a much higher diluent preflash to maintain a similar optimum diluent slip to the DRU column as in a segregated upgrader/refinery facility. Therefore, a multi-stage configuration is even more appealing for integrated mine-upgrader facilities than for a stand-alone refinery or upgrader.

A higher than expected feed-water content will affect the performance of the preflash section and column overhead system for both preflash configurations. A higher feed-water content will alter the preflash temperatures and may affect the amount of diluent preflashed. The additional steam entering the column overhead system from the preflash section may increase the overhead system pressure, increase the offgas rate (resulting in lower diluent recovery and possible venting to the flare) and significantly increase sour-water production that could accumulate in the overhead drum. These consequences for the preflash section and column overhead system should be evaluated to determine if design adjustments to minimize these impacts are warranted.

Free water issues. Free water that is not removed from a

DRU COLUMN OVERHEAD SYSTEM DESIGN

diluted bitumen feed may cause significant damage to the fired heater and/or to the DRU column due to the heaterâ&#x20AC;&#x2122;s ability to rapidly vaporize the free water. At the very least, if water is unexpectedly present at the heater inlet control valves, it will likely form steam, thus creating two-phase flow and control difficulties with the heater pass control valves. Consequently, a two-stage preflash configuration that removes all feed water in the first-stage flash offers an additional benefit. With this design, should a slug of feed water enter the unit, the second-stage flash will reduce the risk of free water breaking through to the final preheat circuit upstream of the fired heater. However, both single- and two-stage preflash configurations that are designed for a high level of diluent preflash (i.e., hotter preflash temperatures) will operate with a margin above the expected water dew point and will consequently provide some flexibility in removing a higher than expected feed-water content.

The objectives of the overhead system are to condense the DRU column overhead and preflash overheads; supply column reflux; and separate water and any noncondensable gases present due to cracking reactions (thermal decomposition) in the fired heater. Design of the overhead system should mitigate corrosion to maximize equipment service life while providing an operationally reliable design. HP Extended version avaiable online at HydrocarbonProcessing.com. Marco Grande is a principal process engineer with Fluor Canada Ltd., Calgary, Alberta, Canada. His experience is in bitumen/heavy-oil upgrading and downstream refining. He holds a BSc degree in chemical engineering from the University of Alberta. Matthew Gutscher is an engineer in training (EIT) in the process engineering group with Fluor Canada Ltd., Calgary, Alberta, Canada. He has a BSc degree in chemical engineering from the University of Alberta.

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CLEAN FUELS

SPECIALREPORT

Minimize carbon footprint from Claus tail-gas units Reevaluate emissions efficiencies on sulfur-removal operations M. P. HEISEL, ITS Reaktortechnik GmbH, Pullach, Germany; and M. RAMESHNI, Worley Parsons, Monrovia, California

For other energy forms, equivalents must be calculated by more complex methods, as summarized in Table 1. All of these values are calculated rather conservatively. For example, generating electric power in a lignite-fired power plant requires more CO2 than in a gas-power plant and that too does not have more than approximately 40% efficiency. Actually, per kWh electric power, one can assume between 439 g CO2 /kWh and 1,306 g CO2 /kWh (see Fig. 1), which corresponds to 0.22 m³ CO2/kWh to 0.65 m³ CO2/kWh. For our calculation, we assumed 0.26 m³ CO2 /kWh, i.e., a low value. The processes. The basic principle of the Claus process is the 1,400 GHG, grams CO2 equialent/kWh

here are thousands of sulfur recovery units (SRUs) worldwide converting poisonous hydrogen sulfide (H2S) into elemental sulfur (S). A typical two-stage Claus plant achieves 95%–97% recovery. In most cases, secondary tail-gas treating is required for total recoveries from 98% to 99.98%. In the past, authorities required a sulfur recovery rate (SRR) to meet local legislation. Other emissions, notably carbon dioxide (CO2), were of no concern. In view of the global climate change debate and continuously rising energy prices, limiting CO2 emission is becoming important. Various Claus tail-gas treatment options are available, but, differ in terms of carbon footprint, sulfur recovery efficiency, capital expenditure (CAPEX) and operating expenses (OPEX). What is the best? There are three principles of Claus tail-gas treatment: • Recycle processes that convert all residual sulfur species into either H2S or sulfur dioxide (SO2) scrub off this species and recycle it to the front end of the Claus plant • Cyclical catalytic sub dew point (SDP) processes that continue the Claus reaction at temperatures below the SDP and shift the chemical equilibrium to more sulfur formation • Selective oxidation of H2S directly to elemental S. In quantifying relative CO2 emissions, it is surprising how much the carbon footprint can vary between processes despite comparable sulfur recovery efficiencies as presented here.

1,200

Indirect, from life cycle Direct emissions from burning Twin bars indicate range

289

1,000 176

800

113

600 1017

400

790 575

200

362

236

0 Coal

Gas

Hydro

280

48 10

100

Solar PV

Wind

Nuclear

Source: IAEA 2000

FIG. 1

CO2 emission per kWh of electric power.1

Calculation method. Barring sister units, there probably are

not two really identical Claus plants in the world, even though the process principle is very similar. For example, there are different methods of reheat before entering the catalytic reactors, as indirect heating by steam or by inline burners, to name just two alternatives frequently applied. When comparing available processes, a base case must be selected. The calculation method is listed so that every adaptation of the specific case can easily be done. Quantitative comparison requires defining an equivalent unit of CO2 emission for any form of energy expended. This is easiest done via fuel gas, where oxidation of 1 mole of methane (CH4) emits 1 mole of CO2.

To atmosphere W1

MP stream

Feed gas

Oxygen (optional)

BFW

BFW W3

Air

FIG. 2

Sulfur

Air Fuel gas

Typical process flow diagram of a 2-stage Claus plant.

HYDROCARBON PROCESSING FEBRUARY 2011

I 71

SPECIALREPORT

CLEAN FUELS

TABLE 1. Basic data for calculation of CO2 footprint Thermal energy

1 m³/h of CH4 generates 35,200 kJ/h which is 9.78 kWh/h. With this value can be calculated the CO2 emission of thermal sources, e.g., of steam

Electric power

1 kW electric power was assumed to be generated from thermal power with an efficiency of 40% which results in 9.78 x 40% = 3.76 kWh/m³ CO2 or 0.26 m³ CO2/kWh

Requires approximately 0.2 kW/m³ which results then in 0.2 / 3.79 = 0.05 m³ CO2

Instrument air

Compression energy to 10 bar plus 10% for purification: 0.15 kWh/m³ = 0.15/3.79 = 0.06 m³ CO2

Cooling water

Pumping energy up to 20 bar = 0.75 kWh/m³ = 0.2 m³ CO2 /m³ CW

Demin water

Cooling water + 20% = 0.24 m³ CO2 /m³ demineralized water

HP steam

Requires thermal energy of 1,678 kJ/kg steam (45 bar) plus preheat of boiler feed water from ca 105°C to boiling temperature of 256°C = (1,685 + 417) / 35,200 = 0.06 m³ CO2

LP steam

Requires thermal energy of 2,119 kJ/kg steam (4.5 bar) = 2,119/35,200 = 0.06 m³ CO2

Air

TABLE 2. Process data for calculation

Air

Claus capacity Claus feed gas

Direct oxidation

Claus plant

Sulfur FIG. 3

Incinerator

Sulfur

Vent gas

Fuel

Claus sections ½

Direct Incinerator oxidation Selective oxidation reactor Stack

Claus reactor

Reheater Steam Waste-heat boiler

Incinerator

Steam QC

Combustion chamber Condenser S

H2S 0.8–1.5 vol% FrC

S FC

O2 0.5–2 vol% Feed gas Air

HP steam, indirect

Air1, Air2, Air3

Dedicated blowers for each of these units

Air demand analyzer

H2S /SO2 ratio = 6

Temperatures

See Table 3

2 H2S + 1 SO2 Ù 3/x Sx + 2H2O + energy

Claus reaction

x: 2, 4, 6, 8 according to the modifications of sulfur This reaction initially takes place in the Claus furnace, typically accounting for 60%–70% of total conversion. This level is not sufficient to meet environmental standards, and the reaction must proceed further in downstream catalytic stages. A two-stage Claus plant typically achieves 95%–97% sulfur recovery. A typical process flow diagram is shown in Fig. 2. From a carbon footprint perspective, the Claus process is essen-

I FEBRUARY 2011 HydrocarbonProcessing.com

tially a power house, generating steam from oxidation of H2S to elemental S with very little CO2 emission. In the majority of Claus plants, the feed gas has a CO2 content of less than 10 vol%. The incoming CO2 is of course later emitted from the plant. In addition, the fuel gas is consumed to thermally oxidize residual Claus tail-gas sulfur species to SO2. This fuel gas also adds to the CO2 emission. Overall, a Claus plant produces a lot of steam with very little CO2 emission. Actually, H2S is a very potent fuel with zero CO2 footprint of its own. Unfortunately, it has the great disadvantage that its incineration product SO2 is very poisonous. Of course, the heating capacity of the Claus process can be used in an industrial complex, thus reducing fuel requirements and CO2 emissions elsewhere. The two-stage process does not meet current environmental requirements. Therefore, tail-gas treatment processes are added downstream for improved sulfur recovery. There are three types of tail-gas treatment processes—selective direct oxidation, the recycle processes and the SDP—and these will be discussed here. Direct oxidation processes. In a direct oxidation process,

Typical process flow diagram of a direct oxidation process.2

conversion of H2S into elemental S. In a two-stage Claus unit, this is done by oxidation of nominally one-third of the H2S in the feed gas to SO2 and reacting these compounds according to the Claus equation:

See Table 3

Reheat

Block diagram of direct oxidation tail-gas treatment.

Claus furnace

FIG. 4

100 t/d sulfur

Feed composition

the Claus reaction furnace is operated slightly air-deficient so that the tail gas contains mainly H2S that is then directly oxidized to sulfur with supplemental air, as shown in Fig. 4. Tail-gas H2S must typically be limited to 1.5 vol% to avoid catalyst damage from high exotherms. As a matter of practicality, three Claus stages are advisable to temper the impact of real-world fluctuations. To calculate the CO2 footprint from the direct oxidation process, data from Table 2 was applied. With the data listed in Tables 1 and 3, the CO2 footprint can be calculated. Table 4 summarized the results (Editors note: Table 3 is available online at HydrocarbonProcessing.com). The process generates more energy than it consumes. This results in a carbon credit from surplus energy. In the tables, this is indicated by negative CO2 emission numbers. For the other tail-gas treatment processes, the same calculating system for determining the CO2 footprint was applied. However, it is not shown in the same extent of details as in this example.

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SPECIALREPORT

CLEAN FUELS

H2S recycle Claus feed gas

Claus plant

H2S wash

Hydrogenat ion

Sulfur FIG. 5

TABLE 4. Summary calculation of CO2 footprint of Claus unit plus direct oxidation tail–gas treatment

Air

Incinerator

Vent gas

Fuel

Import El. Energy, kW

120

Cooling water, m³/h

H2, std m³/h

335

Fuel, std m³/h CH4

Block diagram of hydrogenating recycle process.

Instrument air, std m³/h N2, std m³/h Demin. water, m³/h

Claus unit offgas

To incinerator Heat recovery

1 2

Reducing gas (opt.) 3

Air or CW

Lean amine from regen. Partly loaded amine to regenerator or another absorber

Water (to utilities or disposal)

Upstream (shown as block “1”), Claus furnace and catalytic Claus sections 1 and 2 shown, Hydrogenation step “2” cooler “3”, quench “4”, amine scrubber “5”, downstream (not shown), Regeneration and incinerator.

FIG. 6

Typical PFD of a hydrogenation tail-gas treatment.2

Recycle processes. Fig. 5 shows a typical hydrogenating recycle process. In such a process, the Claus tail gas is catalytically reduced to convert virtually all sulfur species and sulfur vapor to H2S, which is then absorbed in an amine scrubber. Usually, a tertiary amine selective for H2S is used to limit CO2 co-absorption to approximately 15%. In the regeneration column, a concentrated H2S fraction is stripped off and is recycled to the front end of the Claus plant, as shown in Fig. 6 (Editors note: Figs. 7–9 are available online at HydrocarbonProcessing.com). There are many possible process variations. In particular, the hydrogenation bed is often filled with a low-temperature hydrogenation catalyst now commonly used to reduce preheat energy, thus reducing CO2 emissions by approximately 10%. For the comparison, we chose a conventional catalyst requiring higher inlet temperatures. The calculation method and process data applied are the same as for the direct-oxidation process with only one exception: In the air-demand analyzer (ADA), the H2S/SO2 ratio is 2 here, while it was 6 for direct oxidation. Table 6 summarizes the results of the CO2 footprint calculation. SDP processes. For the SDP process, the catalytic Claus reac-

tion is continued at lower temperatures, which shifts the chemical equilibrium to favor more sulfur formation. The temperature is chosen between the sulfur solidification point at 120°C and the SDP, which, in practice, means an inlet temperature of 125°C–130°C. During operation, the reactor operated at SDP conditions accumulates condensed sulfur which slowly deactivates the catalyst. It therefore has to be regenerated, which is done by taking this reactor out of operation and heating it by an inert gas, such as nitrogen (N2), to vaporize sulfur deposited on the catalyst. 74

I FEBRUARY 2011 HydrocarbonProcessing.com

Equivalent CO2 emission 456

HP steam, 45 bar sat t/h

3.32

220

LP steam, 4.5 bar sat t/h

0.2

HP steam, 45 bar sat t/h

8.48

–562

LP steam, 4.5 bar sat t/h

5.69

–377

Export

SRR,%

98.60

SO2 emission, m³/h

40.9

SO2 emission, kg/h

116.7

CO2-emission total, m³/h

–244

CO2-emission total, kg/h

–479

In a sulfur condenser, the sulfur is recovered and the inert gas recycled to the reactor. While the catalyst regeneration is proceeding, a parallel SDP reactor takes over the task. There are several processes applying this principle—SDP1, SDP2 and SDP3.a,b,c SDP1 was chosen here for the comparison. The others can easily be derived from the SDP1 data. For calculation of the CO2 footprint of the SDP1 process, Table 5 summarizes the data. For the regeneration cycle, the data in Table 5 were assumed. Table 6 lists results from the CO2 footprint calculation. SDP1 produces more energy from the conversion of H2S to elemental S than it consumes. Therefore, the net CO2 emission from the process is negative. Alternative SDP processes. The process principle of SDP4

is a combination of a conventional Claus process with the wellproven sub-dew-point tail-gas treatment, as the SDP1 and SDP2 processes.a,b,d Unlike these older processes, SDP4f combines the Claus furnace with just two catalytic reactors, which are cooled internally. This allows sulfur recovery efficiencies up to 99.85%. Such high values could be achieved in the past only by much more complicated processes, i.e., a complete Claus plant with downstream tail-gas treatment. As the two-reactor process requires less equipment and process steps, it is cheaper and more reliable. Equipment that is not there cannot fail. Fig. 10 is a simplified process flow diagram. The fundamental idea of SDP4 is removing reaction heat of the Claus reaction directly in the catalyst bed rather than in a downstream heat exchanger. This controls the temperature throughout the catalyst bed within a narrow range. The top layer of the catalyst is left without cooling. The feed temperature to this adiabatic section is typically 220°C and reaction heats it up to 320°C—the temperature required for COS and CS2 hydrolysis. The second section downstream in the same reactor is cooled to an outlet temperature of typically 260°C. This combination of adiabatic and cooled reaction reaches conversion rates comparable to a two-stage Claus plant. Downstream then follows a sulfur condenser and then a second identical reactor which, is operated at lower temperatures. This

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CLEAN FUELS

Air

Reheat 9

Claus furnace

TABLE 5. Data for calculation of energy demand for regeneration of the sulfur loaded SDP1 reactor

Fuel

Reheat Incinerator

2 6

Feed gas

11 8

SDP4 stage hot mode

SDP4 stage cold mode

Sulfur condenser 7

Inert gas

Gas flow

250 kmol/h

Temperature in sulfur condenser

125°C

Regeneration temperature

340°C

⌬t in heat exchanger, which has to be covered by fuel

30°C

TABLE 6. Comparison of the CO2 and SO2 footprints of various Claus tail-gas treatment processes Import

Claus 1 Claus 2

SDP1

SDP4

SDP5 SDP6

Equivalent CO2 emission, m3/h kW SDP4 process flow diagram.

FIG. 10

Air Claus feed gas

Hydrogenation

Claus plant

Sulfur

FIG. 11

Thermal incineration

Sulfur

Vent gas

Fuel

Recycle water

Natural gas Contact condenser

Sour water blowdown

Hydrogenation reactor Desuperheater

Steam reheater Air

TGT5 reactor

Reduced tail gas

10% NaOH

LP steam Sulfur condenser

Tail gas to incinerator Sulfur

FIG. 12

TGT5 process flow diagram.

shifts the chemical equilibrium toward more sulfur formation. Actually, the outlet temperature is chosen in the range of 100°C–125°C, i.e., even below the S solidification point. In this operating mode, sulfur recovery rates (SRRs) up to 99.85% have been observed. During the operation below the SDP, the sulfur produced accumulates on the catalyst and deactivates it slowly. Therefore, the catalyst must to be regenerated and that is done by switching it into the position of the first reactor. At high temperatures of up to 320°C, the sulfur is desorbed and the catalyst regenerated. The former first reactor is switched at the same time into the position as the cold second reactor. This procedure is repeated typically once every 24 hours. 76

135

119

H2, m3/h

I FEBRUARY 2011 HydrocarbonProcessing.com

124

297

384

335

323

356

262

Instrument air, std m3/h

N2, std m3/h

HP steam, 45 bar sat, t/h

115

220

156

116

165

LP steam, 4.5 bar sat, t/h

179

HP steam, 45 bar sat, t/h

–721

–562

–626

–864

–590

–579

LP steam, 4.5 bar sat, t/h

–109

–377

–309

–195

–332

–309

SRR, %

99.9

98.6

99.8

97.3

117

224

Demin water, m3/h

SO2 emission, kg/h

SRU tail gas

RGG

140

Export

Block diagram of the TGT5 process.

Combustion air

120

Fuel, std m3/h CH4

Air

Selective oxidation

189

Cooling water, m3/h

Total CO2 emission, kg/h

349.6 –479.0 –577.5 –932.1 –798.1 –554.4

Claus 1 r Hydrogenating (TGT1)g Claus 2 r Direct oxidation (TGT2)h SDP1 r Sub-dew-point 1a SDP4 r Sub-dew-point 4d SDP5 r Hydrogenation/selective oxidation (TGT5)e SDP6 r Catalytic incineration (TGT6)f

Reaction heat in the catalytic converters generates steam. For the CO2 footprint calculation, it was assumed that this steam is condensed in air coolers. This reduces the energy efficiency of the process, but it simplifies operation. Table 6 summarizes the results of the CO2 footprint calculation. SDP4 produces more energy from the conversion of H2S to elemental S than it consumes on the way. Therefore, the net CO2 emission from the process is negative. Hydrogenation/selective process. The TGT5 catalyst is a proprietary low-temperature H2S oxidation and Claus-reaction catalyst.e Reduced tail gas from the TGT5 contact condenser is reheated to 200°C–250°C and combined with a stoichiometric quantity of air in the reactor to produce elemental S that is subsequently condensed. Total recoveries of 98.5%–99.5% are achievable. The reactor inlet is limited to 5 vol% H2S, above which recycle dilution (or inter-bed heat removal) is necessary to limit the exotherm. A simplified process flow diagram is shown in Fig. 12. The result of the CO2 footprint calculation is summarized in the Table 6 overview. The SDP5 process also produces more energy from the conversion of H2S to elemental S than it consumes on the way. Therefore, the net CO2 emission from the process is negative. Catalytic incineration process. For the increasingly rare instances when tail gas treatment is still not required, a new process, TGT6, uses a two-stage catalytic thermal incineration process (patent pending).f A low-temperature hydrogenation catalyst

CLEAN FUELS TABLE. 7. CAPEX for various sulfur recovery processes and their respective SRRs Plant type 2-stage Claus unit plus incinerator (base case)

CAPEX in % of second-stage Claus unit

SPECIALREPORT

To SO2 recovery or stack

SRR, %

100

95–97

SUPERCLAUS (downstream of a 3-stage Claus)

140–160

98.5–99.2

Hydrogenating tail gas treatment, Amine

150–200

> 99.9

SDP1

130–150

99.0–99.4

SDP4

140–160

99.4–99.8

TGT5

130–150

98.5–99.5

TGT6

130

96.5–98

TGT6 oxidation catalyst

Supplemental hydrogen (optional) Claus tail gas

converts virtually all Claus tail-gas sulfur to H2S while capitalizing on the resultant exotherm to initiate thermal oxidation in the subsequent TGT5 stage. Incineration fuel is thus substantially reduced from that required for conventional catalytic incineration. A simplified process flow diagram is shown in Fig. 13. Table 6 summarizes the CO2 footprint calculation results. The TGT6 process also produces more energy from the conversion of H2S to elemental S than it consumes. Also, the net CO2 emission from the process is negative. Comparing technologies. With the data from the described

technologies, we can now compare the respective CO2 footprint quantified. In Table 6, the CO2 contributions of the different steps in the processes are listed. One can easily distinguish the contributions of different forms of energy to the emissions.

Low temperature hydrogenation catalyst

Oxidation air blower

FIG. 13

HP steam

TGT6 process flow diagram.

Michael Heisel PhD, is general manager of ITS Reaktortechnik GmbH. He has more than 30 years of experience in sulfur recovery plant design, startup, validation and troubleshooting.

Mahin Rameshni P.E., is vice president and global manager – Sulfur Technology & Gas Processing for Worley Parsons in Monrovia, California. She has more than 22 years of experience in the design of sulfur recovery and gas processing plants and holds six patents.

Import of utilities. Needed imports include:

Electric power. While TGT2,h SDP1, SDP4 and TGT5 are rather close together, TGT1g requires 50% more power. The reason is mainly that the downstream scrubbing process has a consumption to pump solvent around, which increases power requirements. Hydrogen (H2). Only TGT1g and TGT5 reduce the sulfur species to H2S, and, therefore, they are the only processes to require some H2. With the new low-temperature hydrogenation catalysts, H2 demand may approach zero. Fuel. All processes require fuel to incinerate the offgas. The different requirements result from varying compositions of the tail gases. But, the total fuel consumptions do not vary widely, with the exception of TGT5, which requires 10% less than TGT2, SDP1 and SDP4, while TGT1 needs 20% more due to recycle gas. In some TGT1 installations, the incinerator may be operated in stand-by mode. This reduces fuel consumption. High-pressure (HP) steam. This is required essentially for reheating the process gas to the inlet of the catalytic reactors. The more reactors there are, the more HP steam is required. In that respect, SDP4 needs only 1⁄3 of TGT2 requirements. The HPsteam consumption contributes markedly to the total consumption of all the processes. Low-pressure (LP) steam. All processes need some LP steam to heat sulfur lines. TGT1 needs major LP steam quantities to regenerate the scrubber solvent. But all processes also produce LP steam, so all generate a surplus of steam with the exception of TGT1. HP Extended version avaiable online at HydrocarbonProcessing.com. Select 174 at www.HydrocarbonProcessing.com/RS 77

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GAS PROCESSING DEVELOPMENTS

Avoid these risks concerning combustion control in fired heaters Tuneable diode laser analyzers offer diagnostic benefits R. JENKINS, Servomex, Crowborough, England

ired heaters are integral to hydrocarbon processing (HP). Specifically designed for the reaction of fuel and air to produce extremely high gas temperatures, heaters transfer this energy to potentially flammable process fluids via heat exchangers. They consume large quantities of fuel, produce large quantities of emissions, and are a potential safety hazard to personnel and the plant. However, they are irreplaceable within hydrocarbon processing—so they warrant the highest levels of understanding and care in their operation and control. Recent improvements to reduce NOx emissions require closer process monitoring, as newer burners often operate under narrower process control conditions than older, larger-nozzle-diameter gas burners. Demands have grown on plant operators to improve safety practices, increase plant efficiency and reduce environmental emissions. As a consequence, accurate and reliable instrumentation is required to support the control of the process. Improved technologies are available to control fired-heater combustion with greater accuracy and reliability, but the correct selection and effective use of these technologies require understanding of a complex and delicate process. Principles of effective combustion control in fired heaters. The cornerstone of a well-controlled combustion pro-

cess is optimized air-to-flue ratio and efficient fuel consumption. Before analyzer technologies were developed to measure excess air in the products of combustion, fired heaters were run in conditions of high excess air. Although this meant inefficient and costly fuel consumption, it was the only way to avoid the creation of low-oxygen, fuel-rich conditions that could lead to dangerous explosions. Zirconium oxide technologies that were introduced in the late 1960s allowed engineers to obtain reliable and continuous measurements of excess air, enabling them to reduce the air-to-fuel ratio closer to that of the theoretical stoichiometric combustion mix. Unfortunately, reducing excess air poses a new problem: the nearer the process moves to the tipping point at which incomplete combustion takes place, the potential to move from safe to unsafe operating conditions increases, as well as the speed at which these transitions can happen (Fig. 1). The control and safety systems that run fired heaters must therefore perform an extremely complicated balancing act. It is not enough to just increase excess air levels when incomplete combustion is detected, as the complex interactions of O2 and unburned fuel can lead to flammable mixtures igniting further down from the

burners. Such conditions can lead to a number of negative process control conditions, including excess heat at the process tubes, which causes damage and leaks; carbon deposits on the process tubes, which causes decreased efficiency and heat transfer; and, in extreme cases, potentially dangerous combustion events. However if a process problem is detected either by analytical instruments or other safety devices, it is inadvisable to simply switch off the fuel supply to the burners. Abrupt stops, restarts and light-off conditions are the most common time for furnace incidences to occur. It is safer to bring the process carefully and correctly under control than to fully shut down and restart the process, and this is why comprehensive analysis of the products of combustion, or the lack of them, is vital. Despite the risks, there are measureable rewards for operating fired heaters at low excess-air (LEA) levels. In LEA combustion control, the lowest level of fuel is consumed and the combustion products are cooled the least by unused excess air. The cost benefits of these efficiencies are considerable—just a single percentage saving in fuel can save hundreds of thousands of dollars per year. Controlling air levels just above the point at which incomplete combustion starts also enables the “cleanest burn,” helping plants meet emissions requirements. This, in particular, reduces the emission of NOx , created when unused O2 reacts with nitrogen

CO, combustibles and soot

Fuel-rich NOx

Efﬁciency

Ideal

-3

FIG. 1

3 Excess oxygen, %

Air-rich O2

Example of a gas-fired process; actual excess oxygen levels will vary with heater size, fuel, loading and ambient conditions. HYDROCARBON PROCESSING FEBRUARY 2011

I 79

GAS PROCESSING DEVELOPMENTS from the combustion air, which will be produced even by low NOx burners if they are not run lean (Fig. 2). A competent LEA combustion process—running at approximately 2.5%–5% excess air or 0.5%–1% O2 above the point at which unburned fuel in the form of CO starts to break through— can be maintained and controlled at the most efficient running point. As soon as there is not enough air to allow full fuel combustion, the process will quickly degenerate into an unsafe condition. Pockets of CO and possibly hydrogen and methane can travel through the process, causing localized hot spots as they ignite. These effects begin to manifest at less than 10%–15% excess air or 2%–3% O2 in the flue gas, with burner inefficiencies preventing stoichiometric combustion levels being reached. Excluding extractive techniques used for portable gas analyzers and some highly specialist fixed-gas analyzer applications, there are currently two very different technologies available to measure the level of unused O2 in the fired-heater combustion process. Zirconium oxide cell technologies—commonly known as zirconia—have been established for more than 40 years, but have recently been challenged by the introduction of tuneable diode laser (TDL) analyzers. Both offer distinct advantages and disadvantages in their usage, so it is extremely important to understand their respective qualities to deduce which is most suitable for an application. Neither offers a “one-size-fits-all” solution, but there are notable advantages to be gained by using them as complementary techniques. Zirconium oxide: Optimum techniques for optimum O2 control. Zirconia is a proven technology that measures O2

on a wet basis, enabling the sampling and direct analysis from the hot, wet and often corrosive products of combustion. This avoids added complexities and reliability issues associated with a sample conditioning system. Zirconia analyzers are broadly split into two types: close-coupled extractive analyzers and in-situ analyzers. The most effective and reliable method for using zirconia technology in process control is within a close-coupled extractive analyzer system, where a sampling system and sensor enclosure is installed to the side of the process. This enclosure is heated above the gas dew point and contains the zirconia sensor connected to the process via a sample probe. The enclosure normally contains an aspirator driven by

Convective heat

Zirconia or irconia and combustibles

TDL TECHNOLOGIES: A COMPLEMENTARY TECHNOLOGY TO OPTIMIZE PROCESSES

Radiant heat

TDL methane, carbon monoxide and water

Burner

FIG. 2

compressed air or, occasionally, by nitrogen, which is used to extract the sample from the process. As this type of system can be installed close to the burners, the lag time for analysis—the measurement delay due to sensor response—is minimized, giving operators a comparatively short response time. Individual burner performance can be monitored by installing multiple analyzers across banks of burners; this is especially important in fired heaters where low NOx burners are fitted, as the burners are notoriously difficult to evaluate through visual inspection because the flame is nonluminous. Many systems also offer the option of fitting an additional CO or combustibles catalytic sensor. This offers additional diagnostic benefits for process and burner optimization, including providing early indications that excess-air levels are too low, or that a bank of burners is incorrectly set up, adversely affected by other burners or suffering from nozzle blockage. Flame traps should always be specified when choosing this type of analyzer system to prevent the sensors from becoming a source of ignition back to the process. Care should then be taken to ensure that the flame traps have little effect on measurement lag times. High-flow close-coupled extractive analyzers—analyzers that aspirate over 1 L/min of sample from the process—can suffer from considerable sample lag times, as the pressure drops across flame traps and causes a reduction in sample flow to the zirconia sensor. For added measurement certainty, it is recommended that analyzers are specified where the calibration gases supplied to the instrument can verify the whole system’s performance, inclusive of the probe inlet to the analyzer, sensors and the aspirator outlet. With in-situ analyzers, the zirconia sensor is situated at the end of a probe that is inserted into the hot products of combustion. While relatively simple and cost-effective to install, the sensor is directly affected by the process temperature variations and is limited in absolute operational temperature. The mechanical requirements of higher-temperature operation—effectively making the analyzer operate like a diffusion-based, semi-close-couple extractive analyzer—are complex, with bulky assemblies that incur high installation overheads. Critically, when flame traps are fitted to an in-situ technique, the lag time can be more than one minute in length which many engineers will consider too risky for safe control. Problems can be compounded by probe installation points: if placed too far from the burners to limit process temperature effects on the sensors, then both air ingress into the flue and delays caused by distance from the burners can weaken the ability to control the process efficiently and safely. As a consequence, engineers must have a clear understanding that the processes may be compromised by the potential shortcomings of in-situ techniques, regardless of the initial installation cost benefits they offer.

I FEBRUARY 2011 HydrocarbonProcessing.com

A major development in gas analysis techniques has been the introduction of TDL technologies. Enthusiastically received by engineers and plant operators, a range of different technology integrations are now available from multiple manufacturers. Yet, while TDL offers advantages in measuring multiple gas types, it also has limitations that make its use in fired heaters a complementary technique rather than a complete replacement for other technologies. A typical cross-stack system consists of the laser-emitter module and receiver mounted across the process pipeline or

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GAS PROCESSING DEVELOPMENTS flue stack. The gas concentration information is held in the gas absorption line shape, which is obtained by scanning the laser wavelength over the specific absorption line. The measured signal intensity is detected by a photodiode and then used to determine the gas concentration. There are primarily two cross-stack TDL technologies in use: Direct absorption spectroscopy (DAS) and wavelength-modulated spectroscopy (WMS). DAS is the first-generation technique of TDL absorption spectroscopy, providing measurements from a relatively crude approximation of the area under the absorption curve generated by the laser scan. Today, few analyzer manufacturers use this approach to measurement analysis, as DAS yields a relatively noisy signal, compromising measurement accuracy. DAS is also limited due to the broad absorption line shape, with measurement data contained within wings of the absorption curve; hence a proportion of the absorption data is not scanned and cross-interferences from background gases and environmental fluctuations are difficult to correct. While the disadvantages of the DAS technique is generally not significant in relation to O2 analysis, for all other gases it is limited to measurement accuracy. WMS is a sophisticated evolution of the DAS technique, which takes a measurement of the second harmonic of the absorption curve, to determine the rate of change in the absorption line shape. This yields a very sharp absorption curve with all measurement data contained within the laser scan width, and very defined turning points which are easily computed, allowing an accurate evaluation of the area under the absorption curve. By delivering excellent cross interference rejection, precise temperature and pressure correction and low noise measurements, the greater accuracy and stability given by the WMS measurement means it is consequently the most commonly used TDL measurement technique. TDL-based systems appear an ideal choice for in-situ cross-stack measurements in process and combustion control applications. As there is no physical or mechanical interaction with the process—other than molecular absorption—they offer a highly stable base-line measurement, with a long interval between calibrations and a fast response measurement in hot, wet and dusty process conditions. TDL technologies therefore appear highly attractive on both cost and performance grounds, but the technology has potential disadvantages when compared to zirconia for a measurement. For O2 analysis, TDL can only offer an average path measurement across all burners, while zirconia analyzers can be used to measure a particular section of burners by their ability to sample a single point. TDL is also susceptible to a range of environmental factors that must be compensated for, including path length variation, window purge gas effects, optical interferences, and temperature and pressure changes. For a WMS instrument an error of approximately +/– 5% of reading is normal, while, for a DAS measurement, the error can be considerably higher. There is also no way of accurately calibrating a measurement without removing both the TDL source and detector and fitting a fixed-length calibration cell. Even with the calibration cell fitted, which is usually one meter in length, a true calibration is difficult to achieve accurately, as process path lengths typically vary from 5-m to 20-m long. The instrument must apply correction factors to compensate for the calibration cell path length and process path length differences. Problems can also arise in the fitting of optical windows between both the source and the process and between the detector and the process. These windows must remain clean at all times 82

I FEBRUARY 2011 HydrocarbonProcessing.com

and can only be achieved by purging the dead space with a gas that will not interfere with the measurement. For an O2 measurement, this precludes the use of compressed air, so nitrogen needs to be used as the purge gas. As this is normally consumed at a rate of 20 L/min to 50 Lmin, depending on process-gas velocity, it makes operation prohibitively expensive when compared with zirconia techniques unless the process is too corrosive or dust-laden for a zirconia analyzer to operate reliably. TDL delivers greater advantages in the measurement of CO, with the fast response and specificity of TDL enabling CO breakthrough to be monitored accurately. While it is not generally advisable to use CO breakthrough as part of the process-control loop, it can act as a secondary and complementary measurement to the oxygen measurement, assisting LEA optimization and introducing a further level of process safety-related diagnostics. CO measurement using TDL also avoids the problem of high sulfur levels inhibiting catalytic sensors, while the ability to use compressed air as a purge gas removes the prohibitive costs associated with using TDL for an O2 measurement. But as TDL offers an average path measurement, rather than a point measurement, a catalytic measurement of CO combined within the same analyzer as the zirconia O2 measurement gives greater diagnostic capabilities for burner efficiency. Possibly the most significant application for TDL in firedheater processes lies in the ability to integrate the technology into flameout protection, specifically the measurement of methane in natural-gas burners. If TDL is installed so that a burner flameout can be detected quickly, it enables greater flexibility and response to control and shut down processes. In normal operating conditions, no CO or methane should be present in the process, so moisture analysis using the same TDL is used as a reference peak in the same laser scan cycle to prevent laser drift and loss of laser line lock. Conclusion. In conclusion, zirconia and TDL technologies offer the process engineer the greatest advantage when considered as complementary techniques to control the combustion process, reduce emissions and improve safety in fired heaters. As a general rule, the use of close-coupled extractive zirconia instruments to measure oxygen offers a point measurement that can be related to specific burners and higher levels of inherent accuracy, coupled with true calibration capability. TDL offers a highly robust, average and faster measurement, with less associated maintenance which is ideal for monitoring purposes. While TDL will continue to improve, it is not yet ready to displace the older technologies of zirconia and catalytic sensors within combustion control. Within the short to medium term, it seems more likely that its introduction will trigger a new generation of zirconia and catalytic sensor improvements and analyzer developments. This competition between technologies will ultimately benefit process engineers and operators, as it will help generate new, cost-effective and reliable instrument solutions. HP Rhys Jenkins graduated from Manchester University in 1994 with a BEng in mechanical engineering and joined Servomex in 1995 as a mechanical design engineer within a simultaneous-engineering team. Mr. Jenkins has worked extensively across Servomex’s range of world-leading gas analyzers, being involved in a range of key projects including development of the Fluegas 2700 combustion analyzer, the digital range of SBSW infrared sensors, Servomex’s 5000 architectural platform and the 1900 range of infrared and paramagnetic oxygen portable analyzers. He is now the project manager for Servomex has been most recently instrumental in developing the award-winning SERVOTOUGH Oxy hazardous area paramagnetic gas analyzer.

CALL FOR ABSTRACTS 21–23 June 2011 | Beijing International Conference Center | Beijing, China | www.GulfPub.com/IRPC Hydrocarbon Processing’s International Refining & Petrochemicals Conference China will be held 21–23 June 2011 at the Beijing International Convention Center in Beijing, China. You are invited to submit an abstract to be considered for the proceedings. This two-day conference, co-organized by the China National Petroleum Corporation, the Petroleum Industry Press and Gulf Publishing Company Events, will offer an effective means to market to engineering and operations management in the hydrocarbon processing industry. Topics to be covered include (but are not limited to): • Market trends in petrochemical and refining in the Asia-Pacific region • Transportation fuels for the Asia-Pacific region • Refining / petrochemical integration • Automobile market development in the AsiaPacific region and impact on fuels demand • Biofuels / alternative fuels

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PLANT SAFETY

Circumvent design issues when adding new hydrotreating units Follow these guidelines for substantial capital cost savings with existing flare systems M. H. MARCHETTI, A-Evangelista, S.A., Buenos Aires, Argentina

ue to higher global demand for gasoil and gasoline along with strict environmental regulations, refineries are incorporating new hydrotreating units into their existing facilities. Just in the southern cone of Latin America (Argentina, Chile and Uruguay) at least five hydrotreating units have been projected and/or built in the last five years. These hydrotreating units aim to lower the sulfur content to 20 ppm– 50 ppm on final products. Project attention focuses on these new hydrotreating units, while utilities and other services are evaluated later in the project cycle. Verifying the existing refinery flare systems has to be performed as early as possible during the detail engineering project phase to answer key questions, such as: Would the existing crude distillation unit pressure-relief valve (PSV) open with the new backpressure introduced from the new hydrotreating unit’s PSV? Is the existing flare tall enough that it doesn’t exceed the radiation limits at ground level? Are the emission contaminants changing compared to the previous refinery operations?

Method description and best practice tips. The proposed method-

ology is used as a multi-tier approach to compress project schedules, determine PSV requirements earlier in the project and purchase those PSVs early, if it’s economical; assess alternatives to improve design and save on capital costs without compromising safety. To quickly identify possible problems, relief loads are first calculated using a simple approach. The different concurrent contingency loads can be calculated with the basic material and energy balance engineering data. A conservative enthalpy balance approach can be used. For example, in

a column with a cooling failure, power failure or reflux failure, the energy balance is: F hF + QR = B hB + P hP + V hV + (1) QA + Q1 + L hL where: F = Feed flow hF = Feed enthalpy QR = Reboiler duty B = Bottom liquid flow hB = Bottom liquid enthalpy P = Product flow hP = Product enthalpy V = Vapor flow hV = Vapor enthalpy L = Relief load hL = Relief load enthalpy QA = Air cooler (condenser) duty Q1 = Trim cooler (condenser) duty reboiler = Latent heat of vaporization or, for multicomponent systems, the difference between the vapor and liquid specific enthalpies. The reboiler duty is recalculated for relieving conditions. For an air-cooler contingency (or power loss), QA in relieving conditions would be 20% of operating QA. For cooling water loss, Q1 would be 0. To evaluate a reflux failure, the top tray vapor less the operating vapor to the condenser is a good approximation to calculate L.1–4,7

ance (V1), the relief load is calculated as L = 2,923 kg/hr. • As an approximation, using (Q1 + QA)/ reboiler, the relief load is L = 3,035kg/hr. Once the preliminary relief loads are calculated, the new pressure-relief valves are sized, and the new flare system lines are designed and routed into a new unit subheader. While calculating the concurrent PSV contingency loads, most coming from columns, towers or pressure separators, other process engineers can work on calculating all the single-contingency PSV loads, such as blocked outlet loads, control valve full-open cases, etc. HAZOP analyses and relief scenarios. A hazardous operation (HAZOP)

analysis of the new process enables assessment of the number of PSVs that might be triggered to open in various scenarios. In a new gasoline hydrotreating unit, the number of PSVs involved in a multivalve opening contingency, other than fire, that could impact the existing flare design rating are shown in Table 1. Out of 30 PSVs, only two were involved in concurrent PSV discharge scenarios—a cooling water and general power failure— L V1

Example. With a new gasoline stabilizer

column without an air-cooler condenser (QA = 0), the following quick calculations were considered to estimate the relief load for a loss of cooling in the condenser: • A steady-state simulation model was used (Fig. 2), setting the column pressure as the opening valve pressure and Q1 = 0. The relief load is calculated as L = 3,732 kg/hr. • For normal vapor flow to the condenser from the material and energy bal-

V QA CW Q1 P

QR B

FIG. 1

Material and energy balance in a column.

HYDROCARBON PROCESSING FEBRUARY 2011

I 85

PLANT SAFETY Engineering workflow and guidelines. Fig. 3 represents the workflow of

A steady-state simulation model.

FIG. 2

Single-contingency loads

Multiple-PSV load scenarios

Design new ﬂare PSVs, depressurization valves, exit lines, sub headers and headers (ISBL)

Verify knockout drum (KOD) with new vapor and liquid loads

Perform dynamic simulation of columns, or HIPPS analysis

Tie-in point upstream existing KOD, check Mach. number

Add new KOD tie-in downstream existing KOD

Verify ␳zv 2 and Mach number on existing header downstream the tie-in point

Tie-in point and final disposal design. The tie-in location choice is gen-

Review PSV oriﬁce calculation with calculated back pressure

Perform dispersion and radiation studies

FIG. 3

Flare system rating method workflow.

TABLE 1. Gasoline hydrotreating unit relief scenarios Contingency Number of PSVs involved

Fire

Concurrent other than fire

Single contingency only

and these potentially affect the existing flare header performance. All other contingencies, including fire, were unit-wide scenarios but not plant- or refinery-wide scenarios. The number of plant-wide scenarios that might affect existing flare backpressure, radiation intensity and contaminant 86

I FEBRUARY 2011 HydrocarbonProcessing.com

the flare-system rating method. The various steps are described as follows: • Workflow starts with a parallel evaluation of multiple PSV load contingencies and single or unit-wide contingencies, using a flare-system analyzer model. • New flare network is designed. At this stage in the detailed engineering project, the new units’ isometrics are not available. To complete the flare header design and rating, basic routing of PSV exits are made over the plot plan of the plant or layout of new and existing units. Choosing the tie-in point and knockout drum verification will be discussed in detail later. • The network is designed and rated to project-specific values of ␳·v2 and Mach number. Good engineering practice uses ␳·v2 for gases of less than 150,000 Pa and Mach numbers of 0.3 to 0.7. If these parameters are not met in the existing main header, then a better understanding of the existing relief loads can be achieved through dynamic simulation. Once the hydraulic calculations comply with the design parameters, the PSV orifice calculations for the multi-PSV opening cases are reviewed. Dispersion and radiation studies are performed and, if all studies comply with international and local regulations, the flare-system rating is completed. Unfortunately, flare-system analysis does not always follow a straight path. Sometimes a more detailed analysis and additional problem-solving solutions are required, and these will be discussed further.

dispersion was reduced to two. Only these two scenarios had to be studied further at a plant-wide level. All other new-unit scenarios were studied separately to size the new unit main header, which in this example was determined to be governed by one of the fire cases.

erally made as close to the flare stack as possible, taking into consideration whether the existing knockout drum can handle the worst case vapor and liquid loads. When a PSV has a high setpoint and the volumetric flow for the design case is high, the Mach number at the tie-in point tends to be high as well. In these cases, having a higher backpressure at the tie-in point can reduce the Mach number. For example, moving the tie-in point upstream in the existing flare header helps reduce the Mach number; the consequence is a slight increase in the backpressure. Fig. 4 illustrates an example of a flare system analyzer simulation with a stabilizer PSV that has a high set pressure with its tie-in point in the unit’s 16 in. subheader and in a 30-in. main header. The 30-in. tiein point resulted in high Mach numbers while the resulting Mach numbers using the

PLANT SAFETY 16 in. subheader were lower without excessively elevating the PSV’s exit backpressure. The resulting hydraulic performance for both situations is shown in Fig. 4. The existing knock-out drum rating can be performed in parallel with the flareheader rating and later checked by the final simulation model. The various flare-header scenarios are loaded into the simulation tool, and the PSV sizing and flare calculations are performed. The flare-tip pressure drop can be simulated, using the old design data and extrapolated to new loads, using a Bernoulli Equation approximation:

Quemador 601-L

Nodo 5

1101-16-in.–B

610-F

Tie-in 30-in. header mach 0.8 PSV BP = 2.03 bara

PSV-34022 11.53.000/2.03759 0.445 1101-16-in.–D 1.31911/1.22139 1101-16-in. C 0.360/0.394 16-in. x 30 ft Nodo 6

Nodo 5

1101-16-in.–B

1311-2-in.

PSV-34026/27 14.00500/

FIG. 4

601-L 1.11894/1.10724 0.109/0.110

100-RV-000130-in. AB2A 1.13374/1.12803 0.108/0.108

3400-RV-1122-14-AB2A 2.03759/1.36906 0.445/0.808

PSV-34026/27 14.00500/

v ×ρ + P + ρ × g ×z = K 2

Nodo 7

100-RV-000130-in. AB2A 1.13373/1.12802 0.108/0.108

3400-RV-1122-14-AB2A 2.09626/1.58825 0.430/0.624

Tie-in 16-in. sub-header Mach 0.6 PSV BP=2.09 bara

PSV-34022 11.53.000/2.9626 0.445

Tie-in point diagram.10

TABLE 2. Gasoline hydrotreating unit PSV changes between revisions Rev. A Project’s Month 5 Number of PSVs API orifice

When to use dynamic simulation and relief considerations. The relief

load calculation is a difficult task when rating or designing a flare system. The API 521 standard gives general guidelines on estimating relief loads but leaves the calculation details to the process engineer’s judgment. 1 This is due to the different approaches a process engineer can take to perform relief-load calculations. As previously discussed, typical scenarios to consider for a column are related to reflux, cooling or power loss. A dynamic modeling approach has been used and documented, and it helped the engineers gain additional insight on what happened during a relief event.5 Often, this confirms that traditional methods are conservative, allowing engineers to use reduced relief loads while still focusing on safety. However, dynamic simulation takes time and tight project schedules may make it difficult to use this approach. Dynamic simulation benefits are clear and project teams are encouraged to consider it when the situation requires it. A dynamic simulation (Fig. 5) was performed for the new gasoline stabilizer,

Nodo 7

1311-2-in.

The process engineer can consider the backpressure problems that might arise from these calculations on existing PSVs, especially on the crude unit PSVs that have low pressure settings. For the new units, the project team can select the PSV types, conventional or balanced, and purchase these early if there are cost savings. The radiation intensity methods described in API 521, a simple radiation method, and Brzustowski and Sommer, can be used to determine the radiation intensity based on the worst case heat of combustion calculations.1 Finally, the contaminant dispersion into the atmosphere can be calculated using the US EPA Screen 3 models.9

1101-16-in. C 100-RV-0001-30-in. A Nodo 6 16 in. x 30 ft

Total

Rev. 0 Project’s Month 11 Number of PSVs API orifice

resulting in a relief load of L = 2,200 Kg/ hr. This load represented a 24% reduction of the lowest load estimation using steady state calculations. One way to decide when to use dynamic simulation and when to apply the standard steady-state calculations is to analyze if the contingency being studied impacts the whole flare system, involving multiple units across the plant or refinery. If this contingency is limited to a single unit and does not impact the whole flare system, and if the pressure

drop does not increase substantially, and there are no radiation or dispersion problems, then dynamic calculations can be avoided. Guidelines for hydrotreating unit flare analysis. Specifically for

hydrotreating units, the guidelines to rate and design a flare system comprise the following load calculations and possible solutions, including dynamic simulation, to problems that may be encountered. These guidelines include the usual analysis of HYDROCARBON PROCESSING FEBRUARY 2011

I 87

PLANT SAFETY defined by the World Health Organization and other local regulatory authorities. New sweet-loads evaluation:

FIG. 5

Dynamic relief load calculations using a simulation model.

TABLE 3. Gasoil hydrotreating unit PSV changes between revisions Rev. A Project’s Month 5 Number of PSVs API orifice

Total

K M

relief loads, but also additional consideration of new acid loads, etc. Evaluate existing loads. Determine if, for a plant-wide concurrent contingency (cooling or power loss, etc.), the new relief loads added to existing loads resulted in any of the following effects or conditions being violated: • Substantial backpressure changes on existing PSVs • Radiation intensity at ground level corresponding to API 521 radiation limits • Air contaminant dispersion complying with EPA and local environmental regulations. If any of the verification steps fail, the solution is to change the existing conventional PSVs to a balanced (bellow or pilot) type. If the existing PSVs are a balanced 88

Rev. 0 Project’s Month 11 Number of PSVs API orifice

I FEBRUARY 2011 HydrocarbonProcessing.com

type, then it is advisable to perform a dynamic analysis of the PSVs that participate in that design contingency. This would typically involve PSVs with greater volumetric loads and usually concurrent scenarios involving topping columns, absorbers, stabilizers and FCC’s safety valves. New acid loads. The new hydrotreating units concentrate H2S in the top vapor streams of unit operations. Most of the H2S is extracted in an amine contactor and then sent to the amine and sour-water unit strippers, which then have the flare loads rich in H2S and NH3. If the refinery doesn’t already have a sour-flare system, then the company should consider building one when adding the new hydrotreating unit. Dispersion constraints are key in designing this system with concentration limits for SO2 that are

Hydrotreating unit reactors usually work at high temperatures and when the system is evaluated at opening pressure for a fire relief, the hydrocarbon/H2 mixture usually enters in a critical flow regime. In these cases API 521 recommends using depressuring systems and dry fire calculations. The loads calculated using API dry formulas are very conservative. A more accurate approach is presented by Ouderkirk.8 The new flare-header design for hydrotreating units is often governed by one of these cases: • Depressurization loads • Fire loads • Electrical failure loads (considering that most condensers are air coolers and relief loads for cooling-water failure is minimal compared to an electrical failure). If the multiple concurrent PSV design scenarios do not comply with the conservative API 521 radiation limits or environmental regulations, it is worth calculating the relief loads using dynamic simulation. Most column relief loads can be calculated with a more rigorous model, and the revised loads are used to rate the overall flare system including recalculating the flare main header, the radiation intensity and the dispersion levels. While the rigorous models are being developed, the piping engineers might have also completed the isometrics using the first non-rigorous simulation diameters. By the time the more rigorous load calculations are being done, these final flare simulations can be performed, putting all the pieces of the puzzle together (isometrics, revised multiple-contingencey loads, existing PSV pressures, etc.). This provides the most complete, accurate and rigorous analysis. If radiation intensity, back pressure or contaminant dispersion issues cannot be resolved using the methodology presented, other alternatives may be considered: 1. Perform a high-integrity pressure protection system (HIPPS) project to identify which units control the relief loads, and perform a permutation analysis of the individual relief loads by their probability of occurrence and determine the applicable safety integrity level (SIL). SIL is a measure of the reliability of a safety instrumented system to function as designed. There are three possible discrete integrity levels (SIL 1, SIL 2 and SIL 3) of safety instrumented systems defined in terms of probability of

PLANT SAFETY failure on demand (PFD). SIL 3 has the highest reliability, SIL1 has the lowest. API 521 Fifth Edition allows you to take load credits for the use of HIPPS.1 The benefit of this approach is the avoidance of having to build a complete new flare. The downside is the operational constraints on the degree of turndown or the possibility even having to shutdown a unit to avoid overloading the flare system, and the capital investment needed to enhance the control systems of existing units. 2. Increase existing flare height. The radiation intensity and dispersion concentration at ground level will improve but the support structures may have to be revamped or new structures added. 3. Change the existing main flare header. Sometimes backpressure problems persist in existing PSVs and the only option is to replace portions of the existing network. Obviously, this will require additional capital investment. 4. Add a gas-recovery facility. When a dispersion analysis results in high contaminant concentration, this approach could partially solve the problem, but it also might increase the backpressure on the PSVs and increase capital cost. 5. Change the flare tip. Sometimes, high Mach numbers at the flare tip can be avoided by simply changing the flare tip.

approach presented in this article, as validated by experience on several projects: • Compressed project schedules by performing PSV calculations and flare system calculations in parallel. For the example cited previously, these calculations resulted in achieving a three-month reduction in the project schedule. • Project man-hour savings by performing the appropriate level of modeling as required by the project-specific design. The example cited represented saving 160 engineering man-hours of modeling time. • Early definition of header sizing and the PSVs required. There may be cost savings in procuring these supplies early. • Material capital cost savings in accurate header sizing. • New flare cost savings in performing more accurate dynamic-load calculations when needed. HP

Results obtained by applying this method. The results of applying

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this approach to flare-system analysis in a project involving the addition of two new hydrotreating units to an existing refinery are discussed below. Tables 2 and 3 show the number of PSVs that changed from one type to a different type as the project progressed. This resulted from the simulation model being improved as various engineering tasks were completed, and as the overall design evolved and improved. Even though many load calculations changed and PSV sizes were revised during the project, the unit’s main header diameter, the tie-in point and the knockout-drum calculations remained unchanged between design revisions. This experience demonstrates that some tasks can be performed in parallel. Later in the project cycle all pieces of the flare system can be quickly recalculated using process simulator and flare system analysis software. Benefits of using this method.

LITERATURE CITED ANSI/API Standard 521 (ISO 23251), “Pressurerelieving and Depressuring Systems,” Fifth Edition, January 2007. ANSI/API Standard 520, “Sizing, Selection and Installation of Pressure-Relieving Devices in Refineries. Part I: Sizing and Selection,” Seventh Edition, January 2000.

K. Banjee, N. P. Cheremisinoff and P. N. Cheremisinoff, Flare Gas Systems Pocket Handbook, Gulf Publishing Company, 1985. 4 Kister, H. Z., “Distillation Operation,” MacGraw-Hill, Inc, Chapter 9. 5 Gruber, D., D.-U. Leipnitz, P. Seturaman, M. Alos, J. M. Nougues and M. Brodcorb, “Are there alternatives to an expensive overhaul of a bottlenecked flare system?, Petroleum Technology Quarterly, Q1 2010. 6 Marshall, B., “Improve Flare System Design to Reduce Cost and Enhance Safety,” AspenTech Webinar, November 2009. 7 Crosby, T. Pressure Relief Valve Engineering Handbook, Technical Document, May 1997. 8 Ouderkirk, R., “Rigorously Size Relief Valves for Supercritical Fluids,” CEP Magazine, August 2002. 9 US Environmental Protection Agency, “Guía del usuario del Modelo SCREEN3,” EPA454/ B95-004, September 2000. 10 Simulation performed with Aspen Flare System Analyzer V7.1, Aspen Technology, 2009.

Mayra Marchetti is a process engineer at A. Evangelista S.A. She has 10 years´ work experience in process simulation and industrial projects, with a special focus in relief system design and evaluation studies, revamps and new designs. She graduated as a chemical engineer from Buenos Aires University and holds an MS degree in engineering management from Florida International University.

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Worley Parsons . . . . . . . . . . . . . . . 4 (151) www.info.hotims.com/35900-151

Yokogawa Corp. of America . . . . . 41

(84)

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I 93

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

Inferential control model input selection It is not a secret that I prefer to base inferential models on engineering principles, rather than on regression. Having said that, the use of regression is widespread, and being a consultant in the field, I am often asked about how inferential model performance can be improved. Indeed it can be much improved, if one only took the trouble to consider chemical engineering principles.

TC FC

Naphtha

Example. A classic example of bad input selection is a set of

input variables that contain intensive variables, such as pressures and temperatures, together with extensive variables such as flows. The fluid catalytic cracking (FCC) fractionator (Fig. 1) will serve to illustrate this point. To infer the naphtha 90% point regression practitioners habitually take these regression model inputs: 1. Column top temperature 2. Column top pressure 3. Naphtha product flow. Why naphtha product flow? How can such a blatant violation of process engineering facilitate a successful inference? Answer: There is a correlation of flow against 90% point because at a fixed throughput and severity, increasing the naphtha yield increases the naphtha cutpoint. That following a throughput change the inference would be erroneous is just one example of inferences that correlate but do not predict. Such inferences fail during a transient operation, when they are needed the most. Can this problem be solved by inputting naphtha yield instead of naphtha flow? It is definitely an improvement but still vulnerable to reactor severity or feed quality change. Why is there a need for naphtha flow or yield input to begin with? Process engineering dictates that the naphtha 90% point is a function of column top partial pressure and temperature, with some internal reflux influence on the heavy distillation tail. It takes some engineering calculations to create a partial pressure input, and regression practitioners have become “purists” in the sense that they would not consider any engineering procedure—only straight measurements. Because total pressure is an imprecise input, the use of naphtha yield or flow “improves the fit.” I do not recall seeing a calculated partial pressure anywhere as a regression inferential input. FCC reactors have several significant steam injections, all of which end up in the fractionator. Reactor steam injections are determined by reactor considerations and are not necessarily proportional to the feed. Inputting total pressure in lieu of partial pressure is not a very good idea. Further, the FCC reaction creates a large amount of LPG and gas. At fractionator top conditions, those light components are not miscible and, in terms of their effect on partial pressure, they behave like steam. I would assert that no reasonable inference can be created without partial pressure being one of the inferential inputs. Things go downhill from here. What would you suggest

as inputs for inferring light cycle oil (LCO) 90% point? The regression practitioner would typically use: 94

I FEBRUARY 2011 HydrocarbonProcessing.com

FC Pumpdown

Pumparound

FC TI

LCO

Reactor efﬂuent PI LC

FIG. 1

Classic example of bad input selection—FCC fractionator with total draw trays.

1. LCO draw temperature 2. Column top pressure 3. LCO product flow. Why LCO flow? Again, for the same reason, at steady operation, increasing LCO yield affects the LCO cutpoint. Of course, such an inference is again weak. It can handle neither throughput nor severity changes. And for the side draw, there is another element of uncertainty. LCO yield can be changed in different ways. For example, at steady operation, if naphtha yield changes up and LCO yield down, then the LCO 90% point would actually not move at all. The LCO inference is vulnerable not only to transient throughput and severity but also to normal manipulation of the fractionator top section. Internal reflux in the LCO section affects both the partial pressure and heavy distillation tail. Is it possible to take that into account? The fraction (Fig. 1) has a total draw LCO tray where internal reflux is measured as pump down, so even the purist statistician should accept that. Process engineers spend years studying chemical engineering, then more years performing process calculations on the real plant. Where is all that accumulated knowledge? Please, show the world that a process control engineer is not a statistician. HP The author author isis aa principal principal consultant consultant in in advanced advanced process process control control and and online online The optimization with with Petrocontrol. Petrocontrol. He He specializes specializes in in the the use use of of first-principles first-principles models models optimization for inferential inferential process process control control and and has has developed developed aa number number of of distillation distillation and and reactor reactor for models. Dr. Dr. Friedman’s Friedman’s experience experience spans spans over over 30 30 years years in in the the hydrocarbon hydrocarbon industry, industry, models. working with with Exxon Exxon Research Research and and Engineering, Engineering, KBC KBCAdvanced AdvancedTechnology Technologyand, and since since working 1992 with with Petrocontrol. Petrocontrol. He He holds holds aa BS BS degree degree from from the the Israel Israel Institute Institute of of Technology Technology 1992 (Technion) and and aa PhD PhD from degree from Purdue University. (Technion) Purdue University.

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