H P 2011 02.pdf

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BOILERS FOR PEOPLE WHO KNOW AND CARE

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

45

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

51

What are the future fungible transportation fuels?

57

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

15

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

79

Tuneable diode laser analyzers offer diagnostic benefits R. Jenkins

PLANT SAFETY

85

9

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

11

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

HPIMPACT conference out look

94

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

XX

Australia making crucial GTL decisions

XX

IEA assesses energy policies of U.S.

XX

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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HPIN BRIEF BILLY THINNES, NEWS EDITOR

[email protected]

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 [email protected]

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 [email protected]

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

[email protected]

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.

MODERNIZING Continuous Density

Catalyst Bed Reactor Measurement Maintaining an optimum level in the catalyst bed reactor is critical for efficiency. The non-contact MiniTrac 31 density detector provides accurate and reliable measurement of layers within the reactor while remaining unaffected by product variations, ensuring efficient use of the expensive catalyst without waste. t
Mounts without interruption to the process t
Measures through vessel walls and obstructions t
Multiple density gauges measure across the reactor span for optimized control

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

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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.

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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.

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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: [email protected] Select 81 at www.HydrocarbonProcessing.com/RS

HPINNOVATIONS SELECTED BY HYDROCARBON PROCESSING EDITORS [email protected]

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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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. “Today’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,” said Jim Nyquist, president of Emerson’s PlantWeb solutions group. “These needs expand beyond physically controlling material movement to managing the business information associated with them. That’s why I’m proud that Emerson can now offer our customers this powerful, comprehensive solution.” 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 “Golar Freeze” 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 DUSUP’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) “Golar Freeze”, 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 -250°F (-170°C) without pre-heating the gas or pre-cooling

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HPIN CONSTRUCTION HELEN MECHE, ASSOCIATE EDITOR [email protected]

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 • [email protected] 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

Degradation in heat transfer fluid can cause a multitude of problems from loss of production efficiency to unplanned system shutdown. According to the ASTM D6743 standard test method for thermal stability of organic heat transfer fluids, at 600°F for 500 hours Paratherm GLT Heat Transfer Fluid created 30% less product degradation than a widely used comparable alternative. Additionally, Paratherm GLT Fluid is compatible for top-off with similar synthetics and is near colorless versus other yellowish colored fluids which show signs of impurities that may contribute to degradation. Go to our website or call one of our Immersion Engineering™ team for more details and special services. All it takes is a short conversation with one of our sales engineers to greatly eliminate the risk of degradation in your system. Contact us today.

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Select 156 at www.HydrocarbonProcessing.com/RS 26

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.

®

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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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Select 157 at www.HydrocarbonProcessing.com/RS 28

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

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

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

Perm

Aromatics Complex

RE

320 Mtpy

Barrancabermeja Matanzas El Aromo Cangrejera

Barrancabermeja Matanzas El Aromo Cangrejera

FCC Gasoline Refinery, Heavy Ends Refinery Styrene

RE

bbl 150 bpd 300 bpd 100 Mtpy

Esfahan Ras Laffan Yanbu

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

RE

None None None

EX

63

U 2012 U 2012 P 2013

GTC, Inc Punj Lloyd Ltd Jacobs Engineering SA

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

RE

TO

None bbl Mtpy 50 Mbpd 600 Mtpy

12

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

EX

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

FW

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, [email protected], or visit www.ConstructionBoxscore.com

Select 158 at www.HydrocarbonProcessing.com/RS HYDROCARBON PROCESSING FEBRUARY 2011

I 31

When the right reaction matters ...

The petroleum refining landscape is constantly evolving through changing crude slates, shifts in refined product demands, and the necessity to produce more from existing assets. In the face of these challenges, BASF offers innovative solutions. If you are looking for a catalyst supplier whose technologies and services will enable you to make more of the products you want with enhanced operating flexibility, look no further than BASF. Trust BASF FCC Catalyst Technologies and Services to deliver innovation, value, and performance to your refinery. 䡵

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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.

Drying Technology

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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

UPCOMING NPRA EVENTS: (more information at www.npra.org)

Security Conference March 1–2, 2011 Houston, Texas Environmental Committee Spring Meeting March 8–9, 2011 Washington, DC Annual Meeting March 20–22, 2011 San Antonio, Texas

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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

33

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

R

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

38

Fuel oil demand, million bpd

Sulfur maxium content, %

5

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

18

Thermal processing or slurry phase

16 14

Ebullated bed or slurry-phase

12 10 8

Resid FCC 6

2

0.5

FIG. 5

20

4

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

0

2025

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

1

FIG. 6

10

100 1,000 Metals content, Ni + V ppm

10,000

Resid upgrading technology options as directed by CCR %.

less waste

more profit

increased sustainability When your steam trap population is managed correctly you can reduce steam consumption and emissions, improve condensate return and control of processes, while enjoying lower maintenance costs. We are international steam specialists and many of our customers worldwide are saving millions following a tailored Spirax Sarco audit and implementation. To join them: Contact us via www.spiraxsarco.com/steamtrapsurvey to arrange an initial survey and receive your FREE steam and condensate loop book.

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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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