Hydrocarbon Processing February 2012

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FEBRUARY 2012

HPIMPACT

SPECIALREPORT

TECHNOLOGY

Bio-based polymers could be the next big thing

CLEAN FUELS

Eliminate cavitation in your piping system

European pipeline performance

Innovative methods optimize clean diesel production

Treat oily waste via centrifuge plants

www.HydrocarbonProcessing.com

Select 55 at www.HydrocarbonProcessing.com/RS

FEBRUARY 2012 • VOL. 91 NO. 2 www.HydrocarbonProcessing.com

SPECIAL REPORT: CLEAN FUELS

41 51 57 61 65 69

Viewpoint Key representatives from the energy industry present their insight on how to achieve balanced energy policy, what is the future for alternative fuels, what part will renewable/biofuels play in the transportation fuel mix, and more

Consider total value when optimizing catalytic cracking units Low rare-earth catalysts balance activity and selectivity against cost S. Ismail

Increase energy efficiency for your refinery Behavioral and organization changes are needed to effectively maximize operating profits Z. Milosevic

Use advanced catalysts to improve xylenes isomerization This refiner wanted to increase ethylbenzene conversion while limiting aromatics losses G. Shouquan and J. Chua

Improve diesel quality through advanced hydroprocessing New upgrading technologies help meet fuel quality specifications C. Peng, X. Huang, T. Liu, R. Zeng, J. Liu and M. Guan

Debottleneck crude-unit preheat exchanger network inefficiencies Simulation models can be effectively used to optimize heat transfer and boost operational performance E. Bright, S. Roy and S. Al-Zahrani

Cover During the 1940s, the focus of the US refining industry shifted to producing quality transportation and aviation fuels needed by the military. The US federal government sponsored several construction projects to increase refining capacity to support war efforts on two different fronts. This expansion program involved the construction of fluid catalytic cracking units (FCCUs)—a process needed to blend 100-octane aviation fuel—along with the building of new isomerization and alkylation units. Over $900 million was invested in refining construction projects from 1943 to 1945. This month’s cover is a photo of the dedication ceremony for the Texas Co.’s two new FCCUs, held on Feb. 29, 1944 (see pg. 11). This Port Arthur, Texas refinery is still in operation and owned under Motiva, a joint venture between Shell Oil and Saudi Aramco. This refinery is completing another major expansion and is scheduled to come onstream in early 2012. It will have a crude distillation capacity of 600,000 bpd and rank among the 20 largest global refineries.

FLUID FLOW

75

Eliminate cavitation in your piping systems New pressure control devices improve fluid flow E. Casado flores

ROTATING EQUIPMENT

79 83

HPIMPACT 19

Bio-based polymers could be next big thing

20

European pipeline performance

Understand multi-stage pumps and sealing options: Part 1 Service life and cost impact what seals to use on your heavy-duty pump L. Gooch

Treat oily waste with decanter centrifuge plants Turning a challenge into an opportunity A. Hertle

DEPARTMENTS 7 HPIN BRIEF • 23 HPIN INNOVATIONS • 29 HPINCONSTRUCTION 38 HPI CONSTRUCTION BOXSCORE UPDATE 86 HPI MARKETPLACE • 89 ADVERTISER INDEX

COLUMNS 9

HPINSIGHT Government, environment and taxes, oh my!

13

HPIN RELIABILITY Selecting steam turbines in a ‘lean’ environment

17

HPINTEGRATION STRATEGIES Standards needed for laboratory system integration

90

HPIN CONTROL How difficult is it to control absorber columns?

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ThyssenKrupp Uhde – Engineering with ideas. The key to our success is the creativity and resourcefulness of our employees. And it is this that keeps turning major challenges into solutions that are not only brilliant and innovative, but often set the standard for the entire engineering sector. Visit us at Frankfurt a.M., June 18 - 22, 2012 Hall 9.1, Stand B4

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HPIN BRIEF BILLY THINNES, TECHNICAL EDITOR

[email protected]

Petroplus Holdings closed three European refineries in January due to credit line difficulties. According to the company, the restart of the refineries is dependent on economic conditions and credit availability. The shuttered refineries are in Antwerp, Belgium; Petit Couronne, France; and Cressier, Switzerland. The refineries have a combined throughput capacity of approximately 667,000 bpd. Meanwhile, the company’s refineries in the UK and Germany are running at half of their combined 330,000-bpd capacity.

Inpex and Total have finalized sales agreements with customers in Japan and Taiwan for their proposed Ichthys gas-export project in northern Australia, according to the country’s resources minister. The agreements to provide Taiwan’s CPC and Japan’s Chubu Electric Power Co. and Toho Co. with liquefied natural gas (LNG) were first announced in June. Inpex and Total have also agreed to sell LNG from the project to another five Japanese utilities and they are close to making a final investment decision on the project’s construction. Inpex said last June that it had agreed to sell to CPC 1.75 million metric tpy of LNG from the project for 15 years, commencing 2017. It also said it had agreed to sell Chubu Electric 490,000 tpy and Toho 280,000 tpy.

LyondellBasell will shut down two polypropylene (PP) lines in Wesseling, Germany, by mid-2012. The lines, with a combined capacity of 90,000 tpy, are among the company’s smallest and oldest PP production units. A company executive said that it has sufficient capacity to meet the needs of customers in Europe from its larger scale facilities. LyondellBasell produces PP at eight sites in Europe, including facilities in Germany, France, Italy, Spain and the United Kingdom.

Enterprise Products Partners has received sufficient transportation commitments to support development of its 1,230-mile Appalachia to Texas pipeline (known as the ATEX Express) that will deliver growing ethane production from the Marcellus/Utica shale areas of Pennsylvania, West Virginia and Ohio to the US Gulf Coast. ATEX Express will have the capacity to transport up to 190,000 bpd from the Appalachian production areas to the partnership’s storage and distribution assets in Texas. The committed shipper transportation rate will range between 14.5 cents per gallon and 15.5 cents per gallon.

Tesoro plans to sell its Hawaii operations, including the 94,000 bpd Kapolei refinery, operations at 32 retail stations and all associated logistical assets. The company’s president said that Hawaii is not aligned with its strategic focus on the Midwest and West Coast. The Kapolei refinery yield is distillate-focused and is complementary to the on-island demand for utility, jet and military fuels. The facility has the necessary logistics to support product movements to and from the US West Coast or Pacific Rim markets. The Hawaii operations are fully integrated and include a hydrocracking refinery, a network of retail stations, a deep draft single point mooring facility for crude and product movements, proprietary pipelines with connections to business hubs and terminal access and barge operations to supply the major outlying islands.

IHS CERA’s 31st annual executive conference rolls into Houston’s Hilton Americas March 5–9. This year’s CERAWeek will focus on energy’s new role in rebuilding the global economy and providing stability in a volatile time for the international political order. Heavy hitting speakers booked for this event include Martin Craighead, CEO of Baker Hughes; Iain Conn, BP’s executive director; James Hackett, chairman of Anadarko Petroleum; and Jeffrey Immelt, CEO of General Electric. HP

■ Accelerating energy innovation A three-year study by a team of researchers based at MIT has now identified a suite of policy and investment strategies that could accelerate innovation in the US, helping the country to meet its growing energy needs. The conclusions are detailed in the new book Unlocking Energy Innovation by Richard Lester, a professor at MIT, and David Hart, a professor at George Mason University. The authors identified four stages through which an innovative technology becomes an established part of the energy infrastructure. Of those, the first stage (the discovery of new technological options) and the final stage (fine-tuning of technologies already in commercial use) are relatively wellmanaged, they said, though both will require more investment. The two middle stages are less wellmanaged. These stages, spanning what is often referred to as “the valley of death,” include the development of prototypes to demonstrate viability in the marketplace and the initial implementation of the first full-scale systems by early adopters in the marketplace. These intermediate stages are costly and pose high investment risks, and a modest carbon price will do little to accelerate them. The book’s analysis of past advances reveals several steps that tend to foster energy innovation: encouraging competition (and always leaving space for new market entrants), making rigorous and timely selections of promising concepts, and matching the scale of the system to the scale of the need. “The current system satisfies none of these,” the authors said. They think that it’s essential to pursue parallel innovation strategies aimed at different timescales: changes over the next decade focused on efficiency improvements, such as building insulation and gas mileage; mid-range efforts to reduce the costs and risks of known low-carbon energy-supply and electricity-storage technologies; and, from about 2050 on, a third wave of technological deployments drawing on fundamentally new developments in fields such as materials and catalysis. HP HYDROCARBON PROCESSING FEBRUARY 2012

I7

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$ENSTONE‡ßß 3UPPORTß-EDIAß¯ß !LWAYSß2ELIABLEß3UPPORT 3AINT 'OBAINß.OR0RO ßWITHßITSß $ENSTONE‡ßANDß$ENSTONE‡ß DELTA0‡ßMEDIA ßISßTHEßUNDISPUTEDß LEADERßINßCATALYSTßBEDßSUPPORTß MEDIAßTECHNOLOGYß.OßMATTERß WHEREßYOUßAREßINßTHEßWORLD ß 3AINT 'OBAINß.OR0ROßISßTHEßONLYßß SUPPLIERßPOSITIONEDßTOßMEETßß YOURßNEEDSßWITHß IMPRESSIVEßPRODUCTß STANDARDS ßMATERIALSß ANDßSERVICEß¯ß UNMATCHEDßINß THEßINDUSTRY 3AINT 'OBAINß .OR0RO´Sß NEWESTß WORLD CLASSß MANUFACTUR INGßFACILITYßINß 'UANGHAN ß #HINAßFURTHERß ßEXPANDSßOURßß GLOBALßPRODUCTIONßß CAPABILITIES ß PROVIDINGßTHEßSAMEß CONSISTENTßUNRIVALEDß QUALITYßANDßSERVICEßOURß CUSTOMERSßHAVEßCOMEßTOßRELYß ONßFROMß$ENSTONE‡ßBEDßSUPPORTß MEDIAßFORßOVERßßYEARSß&ROMß OURßSTRATEGICALLYßPOSITIONEDß WORLDWIDEßMANUFACTURINGßINß 'UANGHAN ß#HINA ßTOß3ODDY $AISY ß4ENNESSEE ßTOß3TEINEFRENZ ß 'ERMANY ßYOUßCANßBEßASSUREDß OFßEXCLUSIVEßPRODUCTßQUALITYßANDß VALUEßFROMßSITE TO SITEßßß #ONTACTßUSßFORßMOREßß INFORMATIONßONßHOWßWEßCANß IMPROVEßYOURßOILßREFININGßANDß PETROCHEMICALßPROCESSINGß APPLICATIONSßWITHßOURßWORLD ß CLASSßMANUFACTURINGßEXPERTISE Select 64 at www.HydrocarbonProcessing.com/RS

HPINSIGHT

Government, environment and taxes, oh my! In this issue of HPInsight, the global hydrocarbon processing industry (HPI) still battles some very familiar and present day challenges, such as economic cycles, feedstock spikes, government over regulation, construction material shortages and more. The times may be different, but the HPI must continue to evolve and innovate to resolve its problems and hurdles.

Headlines from Hydrocarbon Processing, February 2002: For the first time in a decade, total US consumer petroleum product demand declined in 2001. The US consumed about 19.6 million bpd of crude oil, according to the American Petroleum Institute. Demand for most oil products weakened during the year except for gasoline, which showed a 1.4% rise over 2000 levels. Among the causes for the decline were sharply reduced air travel after the September 11 attacks, continued lackluster economy, fuel switching to natural gas, weak demand for petrochemical feedstocks and abnormally warm winter temperatures. Revised EU directive poses plant upgrades. The EU oil refining industry will face new challenges due to revisions to the 1988 Large Combustion Plant directive (88/609/EEC). It will limit the processing of heavy residuals from the refining processes. New guidelines further limit emissions of carbon dioxide, nitrogen oxide and particulates. US process catalyst demand to grow 4.4%/yr. Demand for process catalyst (which excludes environmental applications) is forecast to increase 4.4%/yr to $3.3 billion in 2006. Demand is being driven by the refining sector and continued strength in new polymerization technologies.

Natural gas prices ‘to be up 5%’ in 1992. Natural gas (NG) prices will be about 5% higher in 1992 than 1991 levels, while crude oil prices will face significant instability as the world’s supply picture changes. In 1992, the US energy demand is forecast to grow slightly as the economy strengthens. NG will assume a larger market share of the new energy demand in the industrial and utility sectors. However, a large-scale movement to NG by the transportation sectors is not in the immediate future. NG wellhead prices will hover around $1.45/MMBtu in 1992, up slightly from 1991 prices of $1.38/MMBtu.

Headlines from Hydrocarbon Processing, February 1982: Europe’s refining industry continues stagnation, but there is hope. There is new cracking capacity coming online from 1980 to 1985. Here is how the countries line up for capacity increases, in million tpy (MMtpy): Austria, 1 MMtpy; Belgium, 3.7 MMtpy; Denmark, 1.5 MMtpy; France, 6.7 MMtpy; West Germany, 8.8 MMtpy; Italy, 11.6 MMtpy; the Netherlands, 11.3 MMtpy; Spain, 7.6 MMtpy; and the UK, 10.6 MMtpy, according to Folger & Co., Boston. Sell alcohol as an octane booster, not a fuel. That is Texaco’s approach. The company will redirect its marketing program for alcohol-enhanced motor fuels to emphasize the value of ethanol as an octane improver. Federal and state tax programs will play a key role in alcohol fuel’s future. World styrene consumption forecast to grow. From 1982 to 1990, annual global styrene consumption should average a 5.1% increase. Styrene demand will have double-digit growth

Headlines from Hydrocarbon Processing, February 1992: Key issues identified by refining execs. A survey of US refining executives lists tops concerns for the industry; they include: 1) Clean Air Act (CAA), 2) public intervention in environmental matters, 3) use of more oxygenates, 4) government intervention on CAFE and taxes, 5) safety, and 6) processing heavier crudes. Leading environmental issues were prioritized as: 1) CAA, 2. ROI of capital expenditures, 3) corporate strategies and profitability, 4) alternative fuels, 5) public environmental pressures, 6) government intervention in CAFE and taxes, and 7) use of new catalysts. TAME is a ‘forgotten’ oxygenate. The forgotten oxygenate is tertiary amyl methyl ether (TAME) according to the European Fuel Oxygenates Association. TAME is produced by reacting FCC isoamylenes with methanol. Only a few TAME units are in operation because of octane-component investments and marginal economics for such units.

BP and Petrofina constructed a new catalytic cracking unit with a capacity of 500,000 tpy at the Antwerp Refinery. The new unit enabled this refinery to increase motor spirit production, July 1955. HYDROCARBON PROCESSING FEBRUARY 2012

I9

HPINSIGHT in developing nations such as Algeria, South Africa and Turkey. In contrast, demand consumption by industrial regions of North America and Western Europe are expected to average a 3.9%/ yr increase. In 1981, world styrene capacity was only at 71% of nameplate capacity. New project announcements will keep ahead of future demand growth through 1990.

Headlines from Hydrocarbon Processing, February 1972: Forecast 10% growth for synthetic rubber. Synthetic rubber production in the US and Canada will increase 10% to reach 2.65 million long tons in 1972, according to the International Institute of Synthetic Rubber Producers Inc. Increased production is based on a predicted 6% increase in rubber demand for autos and tires. Styrene-butadiene rubber (SBR) will hold the largest share of synthetic rubber produced and reach an all-time high demand of 1.63 million long tons. Non-US sector leads in petroleum investment. Capital expenditures by the global petroleum industry, at an all-time high of $20.1 billion in 1970, must increase substantially in the future to allow for costs associated in controlling the environment, according to a Chase Manhattan Bank (CMB) report. CMB stressed the need for well-planned capital investments over environmental protection projects. The petroleum industry invested more money in capital projects in 1970 than in any other single year. Nearly $11.9 billion was spent in the “Free Foreign” nations in 1970—an increase of $1.7 billion over 1969. The US industry invested $8.2 billion over the same period. An unattractive investment climate is cited as the reason for less spending on US projects in 1972. New sulfur recovery technology unit startup. With the September 1971 startup of the world’s first IFP sulfur-recovery unit at the Nippon Petroleum Refining Company’s (NPRC’s) Negishis refinery, the company concluded it has proved that atmospheric pollution can be dramatically reduced. In the IFP process, tail gas from a one-, two- and three-reactor Claus unit is catalytically converted in a liquid-phase reactor to yield high-purity liquid sulfur. In Japan, the atmospheric pollution problem became so acute, that Idemitus, Kyokuto Petroleum and Shows Oil decided to construct the IFP sulfur-recovery units in their refineries. Shell Oil completes first orthoxylene unit in the US. The facility is located at Shell’s Houston, Texas, refinery and has an annual

capacity of 200 million lb. The new unit is the second expansion with the construction of a paraxylene unit in 1967. With the new orthoxylene unit, Shell will become an important manufacturer of xylene isomers.

Headlines from Hydrocarbon Processing and Petroleum Refiner, February 1962: Esso reports new HDDV process. Esso R&D has developed a hydrogen-donor-diluent-visbreaking (HDDV) process that involves mild hydrocracking to aid visbreaking operations that are limited by fuel oil quantities. Remedies for road antiknock. New methods for calculating antiknock performance were developed by a joint Ethyl-Standard Oil study on the feasibility of using “road blending numbers” of gasoline components to predict road performance of finished gasoline blends. One method predicts the road octane number when combining particular components with base gasoline. This method could be useful in process planning and refinery control. Polypropylene fiber breakthrough. Motecatini has developed the first dyeable-type polypropylene (PP) fiber for commercial production. The PP fiber can be stock, yard or piece-dyed, alone or in blends with dyestuffs in use by the textile industry. The dyeable fiber in no way alters the PP’s properties, but affords many new applications for PP fibers. New acetic acid process available. The Soviet Union claims to have found an easy, economical solution for using butane for acetic acid manufacturing. A Moscow refinery has successfully used the new process, which liquefies butane at 140°C at 750 psi. A catalyst is added to initiate a violent oxidization reaction that yields acetic acid and substantial quantities of solvents. The new process is claimed to be more cost-efficient than present aceticacid manufacturing technologies. Japan increasing petrochemical production. Japan is planning to expand petrochemical production through 1970. A new forecast claims ethylene capacity to reach 4 billion lb/yr by 1970 and require more naphtha cracking capacity. Propylene capacity will climb to 2.8 billion lb/yr, which will be supported by offgas from refineries and byproducts from naphtha cracking.

Headlines from the Petroleum Refiner, February 1952: Steel for refinery expansions. Additional steel to spur construction of needed refining capacity may be possible in later 1952 based on a recent Petroleum Administration for Defense (PAD) statement. The agency is developing a new refinery expansion program to permit the construction of 475,000 bpy of new refining capacity. The new projects will consume 44% more than the present steel allocation program.

Early construction of an Orthoflow catalytic cracking unit at Atlantic Refining’s Philadelphia, Pennsylvania, refinery, December 1953. 10

I FEBRUARY 2012 HydrocarbonProcessing.com

Shale oil production and refining today. The US Bureau of Mines recently announced that it will build a much larger plant for the production and refining of shale oil. This project, together with the recent dangerous development in Iran, has again moved shale oil into the limelight. The amount of US shale oil is tremendous, and it is estimated to be in excess of 225 billion bbl. Many new pro-

HPINSIGHT cesses are under consideration for recovering shale oil. The ultimate objective in refining shale oil is the production of gasoline and diesel fuels. Refining operations applied experimentally to refine shale oil include crude distillation, visbreaking, recycle cracking, coking and reforming. One of the most promising techniques that maximizes gasoline yield from shale oil is hydrogenation. European synthetic catalyst plant built to meet increasing demand for high-octane gasoline. Growing European demand for high-octane gasoline is reflected in the construction of a new

synthetic catalyst plant in Warrington, Lancashire, England. With a capital cost of $2.8 million, the new facility will manufacture sodium silicate catalysts, using a process developed by The Davison Chemical Corp. The new catalyst unit will supply catalyst to several oil companies including Esso Petroleum Co., Anglo-Iranian Co., Shell Refining & Marketing Co. and Bahrein Petroleum Co. HP

To see the headlines from 1942 to 1922, visit HydrocarbonProcessing.com.

HPI and aviation fuel needs of the 1940s The Allied forces of WWII depended on aviation fuel to conduct their operations on several continents in two very different regions. Consequently, the newer military air force needed much higher octane fuels than in the pre-1940s era to meet their mission goals and to transport soldiers and supplies throughout Europe and the Pacific region. Role of technology. The refining technology of the pre1940s included using alkylation processes for octane goals, and the average refinery blending pool was about 65 octane. However, the new engines for the military air force needed 100 octane. The US government, in cooperation with domestic refining companies, embarked on a massive construction program to expanding the processing capability and to produce more gasoline and diesel along with higher octane aviation fuels for the military. This program involved applying new refining technologies to reach 100 octane for the blending pool. A new process, fluid catalytic cracking (FCC), became the foundation to meet this fuel goal. Several licensing companies joined in the effort. Refining technology leaders participating in the 100-octane program included The M. W. Kellogg (now KBR), Universal Oil Products (UOP, a division of Honeywell) and the Standard Oil Co. The push was to produce aviation- grade alkylate. The program involved construction of catalytic cracking capacity, along with new alkylation and isomerization units.

New catalytic cracking unit constructed at The Texas Co.’s Port Arthur, Texas, refinery. The facility was part of a US government sponsored effort to produce 100 octane aviation fuel for the WWII effort. Approximately 60 catalytic cracking units were constructed at US refineries at a total cost of $900 million over a four-year period, according to the Petroleum Refiner, January 1944.

The core of the program involved the construction of 94 plants that would support the blending of 100-octane aviation gasoline. The cost for the US government sponsored construction program exceeded $900 million. With completion of the program, 60 refineries were equipped with FCC units (FCCUs). This month’s cover is a photo of the dedication ceremony for The Texas Co.’s FCCUs, held Feb. 29, 1944, at Port Arthur, Texas. This refinery installed two FCCUs. The first FCCU came onstream in March 1944, and the second FCCU became operational on April 1944. After startup, both FCCUs began shipping butylene to the Neches Butane Products Co., another project sponsored by the US Petroleum Administration for the War in the Golden Triangle area of Texas. Neches Butane used butylene streams from the surrounding refineries to produce butadiene—a feedstock for the government-sponsored styrene-butadiene rubber (SRB) manufacturing facilities. By the end of 1945, The Texas Co.’s Port Arthur refinery was producing more than 1 million bpd of aviation gasoline. HP BIBLIOGRAPHY “Aviation gasoline plant construction will be completed in 1944,” Petroleum Refiner, January 1944. Gish, E. N. Gish, Texaco’s Port Arthur Works, A legacy of Spindle Top and Sour Lake, www.texacohistory.com “Role of natural gasoline industry in the 100-octane gasoline program,” Petroleum Refiner, May 1943.

Dedication ceremony of The Texas Co.’s two FCCUs on Feb. 29, 1944.

HYDROCARBON PROCESSING FEBRUARY 2012

I 11

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HPIN RELIABILITY HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR [email protected]

Selecting steam turbines in a ‘lean’ environment

Don’t get caught in the ‘lean and mean’ craze. A

perceptive reader may have seen how our answer alludes to the 28,000 Governor adjustment range (3,520 to 5,293)

16,000

39 31 29 28 27 24 23 22

12,000

8,000

4,000

F NP 5 x PF N 4x F NP 3x PF 2xN

1 x NPF ) (44 NOZ

0 0 FIG. 1

F

Mode 54 52 51 50 49 48 46 45 43

20,000

1,000

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NP

24,000

6x

More information needed. The only way one could make a definitive judgment is to: a) Look at the guaranteed efficiencies of the two different offers and keep in mind the overall steam balance of the facility b) Make a decision as to how well trained the operators will be c) Closely examine the respective field and service experience histories of the two different turbine offers. Complying with the basic requirements of a), b) and c) requires considerable diligence, time and effort. The reviewer should add to this a thorough check of the gearbox design and should accept that time is needed to draw up a comprehensive comparison between the two offers. It would even be appropriate to ask if the original inquiry went to the right bidders. It is always prudent to solicit bids from manufacturers that have ample experience with both direct-drive generator turbines and the more complex compound/reheat multi-casing machines. With time permitting, consider including a few bidders who can comment on the very advisability of double-shell machines. A double-shell construction machine prevents inlet steam coming

into direct contact with the outer casing joint. These machines require less attention from the operator. However, during the maintenance cycle, this steam turbine does need very competent maintenance skills. “Cross-compound” machines are probably found on shipboard, but predominantly at inlet pressures slightly lower than 110 bar. Again, substantial inquiring should be done before a decision can be made. As regards items to be reviewed, one might investigate the lubrication system. In a cross-compound machine, the input and output shafts are at different levels, and the lubrication system serves not only the turbine and generator bearings, but also the gearbox. Investigate who makes the gearbox and how the gears are lubricated. Total cost issues. Initial cost, operating cost (efficiency) and long-term reliability expenses are of interest, and the total must be considered as part of the life-cycle cost. All are of equal concern and, without making a final judgment one way or the other, many different options should be explored before reaching a conclusion. Although one should make good use of vendor input and defer to their demonstrated experience, expect double-shell machines to cost more money and cross-compound machines to require more than the average maintenance commitment. And the “simple” machine would also stay in the running until all the data are reviewed.

Frequency, – HZ

We received a nice compliment recently from a reader in South America. He wrote: “I am a mechanical engineer working on power plant designs at a major corporation and admire your work as a writer of turbomachinery books. Your texts are much respected and I usually refer to them to find answers to my equipment questions.” He then added, “I am writing you because I could not find all the answers in your steam turbine text.1 My aim is to clear up some doubts related to steam turbine technical specifications. More specifically, the corporation is developing a combined-cycle power plant project that includes an 86-MW condensing-type steam turbine with one reheat entry. The HP inlet steam is at 110 bar and 540°C and the reheat is being designed for 24 bar. We are communicating with several respected steam-turbine manufacturers and some of them are proposing a ‘standard-type’ machine. In other words, they offer a turbine with a single casing and a single rotor direct-coupled to the generator. But there are also some manufacturers that propose a “cross-compound-type” machine, a turbine with two casings and two rotors. In one offer, the HP rotor is coupled to the generator by gearbox and the IP/ LP casing is direct-coupled to the generator. Personally, I am not comfortable with the ‘cross-compound’ machine. Accordingly, I would like to know your opinion about this machine. Is this solution technically feasible? Are there many operating and maintenance (O&M) problems?” I drafted an answer agreeing that the recent Bloch-Singh steam-turbine book gives little guidance on the matter.1 It does, of course, describe similar machines. However, the book may have added to the reader’s confusion by mentioning not only cross-compound double-casing machines, but also double-shell steam turbines.

Axial rocking 5 x running First axial speed First tangential

4,000 2,000 3,000 Turbine speed, rpm

5,000

6,000

Campbell or interference diagram for a partial steam turbine stage. HYDROCARBON PROCESSING FEBRUARY 2012

I 13

HPIN RELIABILITY subject of suitability analyses or pre-purchase selection work that needs to be done. We were reminded of the pitfalls of “lean and mean” when another facility experienced several extreme failures on smaller two-stage back-pressure mechanical drive steam turbines. For several years, these turbines had been driving refrigeration compressors without incidents. Then, about two years ago, the refrigeration gas composition was changed to accommodate new (and well-justified) environmental concerns. The new gas conditions mandated a speed change for the steam turbine drivers, and multiple catastrophic blade failures have occurred since then. It seems that the equipment owner was unaware of the need to look at the vibration modes of the blades for these steam turbines. A Campbell diagram, or interference diagram (Fig. 1) is used to indicate what speeds to avoid and to safeguard blade life in a particular stage. Because almost all blade failures are caused by vibratory stresses, many reliability-conscious purchasers are requesting Campbell diagrams with turbine quotes or orders. A Campbell diagram is a graph with turbine speed (r/min) plotted on the horizontal axis and the frequency, in cycles/sec, plotted on the vertical axis. Also drawn in are the blade frequencies and the stage-exciting frequencies. When a blade frequency and an exciting frequency coincide or intersect, it is called resonance. Stress magnitudes are greatly amplified at resonance. Over the past few years, the mindless interpretations given to “lean and mean” thinking have often led to costly oversights. No time or budget is allocated to understanding what happens when steam turbine speeds are re-set for operations away from the original governor adjustment range. The result has been a

much higher probability of steam-turbine-blade failures. Consider this comment a plea to know if and when it is proper to be lean or green, or whatever. Evaluating interference diagrams and steam turbine blade stresses is a mandatory task that can never be overlooked in a modern plant Likewise, let your specifications reflect attention to seemingly small issues; include such items as keeping lube oil from exiting the bearing housing, or steam leakage from entering into a bearing housing. Review how best-of-class companies have systematically solved these problems by using advanced bearing protector seals (see HPIn Reliability, August 2010) or by scrupulously avoiding outdated or risk-prone old-style components (see HPIn Reliability, October 2007 and HPIn Reliability, May 2009). Include details on field erection requirements in your specification; HPIn Reliability, February 2008 commented on these. Avoid carbon seal rings in steam turbines (HPIn Reliability, April 2008) and use only the most advantageous seal configurations in turbine-support pumps (HPIn Reliability, January 2009). These are just some of the items that can allow you to achieve lowest possible cost of ownership. HP 1

LITERATURE CITED Bloch, H. P. and M. P. Singh, Steam Turbines: Design, Applications and Re-Rating, 2nd Ed., McGraw-Hill, New York, New York, 2009.

The author is Hydrocarbon Processing’s Reliability/Equipment Editor. A practicing consulting engineer with 50 years of applicable experience, he advises process plants worldwide on failure analysis, reliability improvement and maintenance costavoidance topics.

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Custom Support Grids Johnson Screens Shaped Support Grid

The new Johnson Screens patented Shaped Support Grid matches the contour of the vessel head. The innovative design creates increased volume for catalyst or molecular sieve in the vessel, provides uniform ÀRZDFURVVWKH entire vessel cross section, allows a low cost bed support and eliminates the need for costly beams and support ledges.

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Linde has built a history of proven results with over 250 synthesis gas plants and 2,800 air separation plants installed worldwide. As a world class supplier of synthesis gas and air separation plants, Linde Engineering and its subsidiary, Selas Fluid, provide single source responsibility for engineering, procurement and construction of complete synthesis gas and air separation plants. Synthesis Gas Plants: • Hydrogen • Carbon monoxide • H2/CO synthesis gas • Ammonia • Methanol • Synthetic natural gas

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HPINTEGRATION STRATEGIES PAULA HOLLYWOOD, CONTRIBUTING EDITOR [email protected]

Standards needed for laboratory system integration Industries across the board are coping with relentless pressure to reduce costs while simultaneously improving product quality. The hydrocarbon processing industry (HPI) has an additional challenge in achieving higher product quality as a result of the heavier raw materials available for processing. Heavier crude feedstock from sources such as the Canadian tar sands have high sulfur content, thus making them more complex and expensive to refine. This heavier feedstock is in direct contrast to requirements for low-sulfur products dictated by ever-more-stringent regulatory requirements. In this environment, a well-designed quality management system (QMS), which includes a robust laboratory information management system (LIMS) that facilitates ISO 17025:2005 accreditation is critical to ensuring product quality and customer satisfaction. LIMS is vital to quality management. Inspection systems that perform product sampling and chemical analyses are expensive; yet, they can be easily justified. Reprocessing or scrapping product wastes time, money and resources. Furthermore, off-spec product can lead to unhappy customers or worse, product recalls that can damage the manufacturer’s corporate image. Conversely, product quality over and above that required by contractual obligations incurs additional costs for which manufacturers are not compensated, and this impacts margins and profitability. A comprehensive QMS with an integrated LIMS can help reduce product variability and improve operational performance. In the HPI, lower-grade feedstock may dictate higher in-process sampling and analysis rates to prevent defects during the manufacturing process. When integrated with manufacturing execution system (MES) and enterprise resource planning (ERP) systems, production and other departments can access quality-related information generated by the LIMS to help ensure that products meet defined specifications and demonstrate compliance with regulatory, product and safety standards. An LIMS, such as Sample Manager 10 from Thermo Fisher Scientific, adds value to quality assurance (QA)/quality control (QC) systems with full traceability functionality and it serves as a repository for documents and reports as evidence of compliance. An LIMS can provide vital information at the front end of the manufacturing cycle. Identifying off-spec raw materials upon inspection can provide the needed heads-up to tune the production process to yield acceptable final product(s). It can demonstrate that a sample was handled appropriately and that the analysis was done by a properly trained, qualified technician. It can act as a repository for laboratory equipment and maintenance histories or analytical method validation, as well as the corporate quality manual. LIMS data can also be useful in determining the appropriate corrective action for off-spec product and to evaluate the performance of the quality system. Upon final QA quality and contamination checks, it can quickly release shipments.

If a non-compliant lot was inadvertently shipped, fast efficient flow of information will ensure that a recall can be quickly implemented. Without traceability records from an LIMS, it would be nearly impossible to accomplish product recalls in a timely and controlled manner. Integrated LIMS enhances QC. In the manufacturing environment, analytical measurements define the “who, what, when, where and how” of a manufacturing process. As the backbone of the laboratory, an LIMS provides quantitative and qualitative information about chemical processes for enhanced QC. The wealth of analytical measurements provided places increased importance on integrating this information into higher-level enterprise application platforms. To improve response to operational issues, managers look to technology to connect plant floor and business systems, like ERP, product information management system (PIMS) and MES, making it critical that analytical information are presented to the viewer in the context of their role, responsibility and authority. For real-time quality management, information visibility is the driver behind the demand for better integration of laboratory-generated information throughout the enterprise. Laboratory ISO 17025 compliance demonstrates commitment to quality. Due to fluctuations in raw materials, HPI laboratories are becoming almost like third-party service laboratories. As such, these labs must assure compliance of product(s) to specifications, making laboratory accreditation with standards such ISO 17025:2005 no longer just nice to have, but a necessity to ensure conformance and customer satisfaction. Compliance with as ISO 17025 demonstrates a commitment to quality, and provides customers the assurance that the laboratory’s management and technical requirements adhere to globally accepted best practices. ISO 17025 requires a complete history of each piece of equipment including checks and calibrations performed prior to being placed in service as well as detailed records of all calibrations, repairs, maintenance and performance checks over the serviced life of the device. A clear advantage for final product manufacturers is that utilizing certified ISO 17025 laboratories as subcontractors fulfills all the requirements as applicable to calibration and testing activities of an ISO 9001 quality management system. This enables the manufacturer to recognize the sub-contractor as ISO 9001 certified for any work done within the ISO 17025 scope. Quality audits of an accredited subcontractor are not required. HPI manufacturers can use the statements of work provided by an LIMS to ensure that customer requests match the delivery of samples to the lab, along with and the delivery of results back to the customer. HP The author has nearly 30 years’ experience in the areas of sales and product marketing in industrial field instruments that utilize a vast array of technologies including magnetic, Coriolis, radar, electrochemistry, capacitance and ultrasonic.

HYDROCARBON PROCESSING FEBRUARY 2012

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low rare earth loves high performance BASF’s Rare Earth ALternative (REAL) solutions target the needs of today’s Fluid Catalytic Cracking (FCC) catalyst market. Through a world-class combination of technology, technical service, procurement expertise, and investments in manufacturing and R&D, BASF delivers performance and value to customers looking for options to reduce rare earth costs. At BASF, we create chemistry.

Realize the value of BASF innovation. Visit www.catalysts.basf.com/real Select 96 at www.HydrocarbonProcessing.com/RS

HPIMPACT BILLY THINNES, TECHNICAL EDITOR

[email protected]

250,000 LDPE PET LLDPE HDPE PP

200,000 150,000 100,000 50,000 0

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Biofuels and bio-based chemicals have been promoted as a potential solution for dependence on petroleum. They also have favorable greenhouse gas emissions compared to fossil fuels and petrochemicals because any carbon sourced from biomass can be directly traced to atmospheric CO2 via photosynthesis. Plus, the increased emphasis on lifecycle analysis for both economic and ecological factors has caused industry players to become familiar with the details of bio-feedstocks. The drumbeat for biofuels has thundered for some time now, but new analysis is showing that bio-based polymers could become the next big thing. Global commodity polymer demand grew from 2000–2007. After a slight dip in recent years due to the economic downturn, consumption is expected to continue to grow for the next ten years (Fig. 1), providing an opportunity for bio-based polymers to enter the market and make a splash. This idea is put forth and explored in a new report from Nexant called, “Plants to plastics: Can nature compete in commodity polymers?” Many producers, especially in high cost locations, have been looking for lower cost feedstocks in places like the Middle East, or are considering alternative feedstocks such as bio-based sources. With virtually all Middle East ethane allocations already apportioned for petrochemical projects, a portion of the next wave of new ethylene may well be from bio-based sources that can emerge from strong agricultural-based economies such as Brazil, the US or India.

As illustrated in Fig. 2, there are many conventional routes to polymers that can be integrated with bio-based feedstocks to either supplement or replace current petrochemical feedstocks. The report from Nexant compares technology, economics and potential markets for polymers produced via renewable sources versus petrochemical sources. Bio-ethanol dehydration to ethylene is a 40-year-old commercial technology available for license from companies in Sweden and the US. Bio-based “green propylene” and other “green” commodity polymers most often can be made by adapting conventional petrochemical routes like metathesis. Metathesis is a common process to react butylenes with ethylene to make propylene. Bio-propylene has a few alternative routes, including: Global commodity polymers demand, thousand tons

Bio-based polymers could be next big thing

FIG. 1

Global commodity polymers demand from 2000–2020.

Conventional petrochemical routes

Renewable feedstocks Lignocellulosic Lipids Wood Vegetable oils* Grasses Fats Corn stover Greases Straws Jatropha MSW Pre-treatment

Sugars Grains/Starches Sugarcane* Corn* Beets Wheat Sorghum Grain sorghum Cassava

Refinery Lipids

PDH

Propane Ethane

Ethanol

Steam cracker

Thermochemical (gasification, pyrolysis, catalysis)

Propylene

FCC

Isooctene

Ethylene

+O2 Propane Pyrolysis w/zeolite BTX

Butadiene

Rubber, ABS, etc.

PVC

Glycerine

Ethylene oxide

PDH Propylene

+H2O Ethylene glycol

PX PP

FIG. 2

BTX

Transesterification

Isobutanol Isobutylene

Ethylene

Naphtha

biomass

Hydrolysis

Fermentation (yeasts, bacteria, fungi)

Crude oil

Natural gas

Algae

PE

PX +O2 PTA PET

Potential green integration into the polymer value chain.

HYDROCARBON PROCESSING FEBRUARY 2012

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HPIMPACT • Bio-butanol dehydration to butylenes metathesized with bio-ethylene • Bio-ethylene dimerization to butylenes metathesized with bio-ethylene to make bio-propylene • Bio-based propane dehydrogenation • Fermentation to propanol followed by dehydration. The three leading commodity polymers in the market (all grades of polyethylene, polypropylene and polyvinyl chloride) are highly relevant to large volume applications, and can all potentially be made by bio-based routes. That is, finished bio-polymers can potentially be made that will be indistinguishable from the best-performing conventional polymers, but with carbon content completely sourced from green plants or biomass. The report also examines bio-based polyethylene terephthalate, which can be produced by adapting conventional petrochemical routes. Bio-based terephthalic acid can be made from paraxylene via the benzene, toluene and xylene process from renewable feedstocks. Also of note is bio-based mono ethylene glycol, which can be produced via conventional ethylene-oxide routes using bio-ethylene. The next 10 years could see bio-based polymers having a major impact on downstream polymer production (or not). Only time will tell.

European pipeline performance European oil industry group CONCAWE has collected 40 years of spillage data on European cross-country oil pipelines with particular regard to spillages volume, cleanup and recovery, envi40 White products Hot

1,400 1,200

25

1,000

20

800

15

600

10

400

5 0

200 0

Average gross volume spilled, m3

Total Crude

Hot pipelines inventory, km

30

250

1,600

1971 1973 1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 2009

Cold and total pipelines inventory, thousand km

35

ronmental consequences and causes of the incidents. The results have been published in annual reports since 1971. CONCAWE recently issued a report that covers the performance of these pipelines in 2010 and provides a full historical perspective since 1971. The performance over the whole 40-year period is analyzed in various ways, including gross and net spillage volumes. Spillage causes are grouped into five main categories: mechanical failure, operational, corrosion, natural hazard and third party. Data for the CONCAWE annual survey comes from 77 companies and agencies operating oil pipelines in Europe. For 2010, data was received from 69 operators representing over 160 pipeline systems and a combined length of 34,645 km (Fig. 3), slightly less than the 2009 inventory. There were minor corrections to the reported data. Nine operators did not report, but CONCAWE believes none of them suffered a spill in 2010. Nevertheless, they are not included in the statistics. The reported volume transported in 2010 was just under 800 million m3 of crude oil and refined products, about 10% less than in 2009. Four spillage incidents were reported in 2010, corresponding to 0.12 spillages per 1,000 km of line, well below both the 5-year average of 0.25 and the long-term running average of 0.52, which has been steadily decreasing over the years from a value of 1.2 in the mid-1970s (Fig. 4). There were no reported fires, fatalities or injuries connected with these spills. The gross spillage volume was low at 336 m3 (Fig. 5). This is 10 m3 per 1,000 km of pipeline compared to the long-term average of 78 m3 per 1,000 km of pipeline.

200 150 100 50 0 Mechanical Operational

FIG. 3

CONCAWE oil pipeline inventory and main service categories from 1971–2010.

Corrosion

Natural

3rd party

The 40-year average gross spillage volume listed per event by cause.

FIG. 5

25

15 10

0

1971 1973 1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 2009

5

FIG. 4

20

The 40-year trend for the annual number of spillages for all pipelines.

I FEBRUARY 2012 HydrocarbonProcessing.com

6,000 5,000

Yearly Running average 5-year moving average

4,000 3,000 2,000 1,000 0 1971 1973 1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 2007 2009

Spillages/yr

20

7,000 Gross spillage volume, m3

Yearly Running average 5-year moving average

FIG. 6

Gross spillage volume from 1971–2010.

HPIMPACT

100

1.0

80

0.8

60

0.6

40

0.4

20

0.2

Spills per year per thousand km

by 2010 only 4.4% was 10 years old or less and 50% was over 40 years old. However, this has not led to an increase in spillages. Overall, there is no evidence that the aging of the pipeline system implies a greater risk of spillage. The development and use of new techniques, such as internal inspection with intelligence pigs, hold out the prospect that pipelines can continue reliable operations for the foreseeable future. HP Cold pipelines spillage frequencies by cause, %

CONCAWE reports that essentially all the spilled volume was recovered or safely disposed. Two of the spills accounted for about 95% of the gross spill volume. Over the long term, less than 20% of the spillages are responsible for about 80% of the gross volume spilled (Fig. 6). Pipelines carrying hot oils such as fuel oil have in the past suffered from external corrosion due to design and construction problems. Most have been shut down or switched to cold service (Fig. 7), so that the great majority of pipelines now carry unheated petroleum products and crude oil. Only 159 km of hot oil pipelines are reported to be in service today. The last reported spill from a hot oil pipeline was in 2002. Of the four reported incidents in 2010, two were related to mechanical failures, one was caused by external corrosion, and one was the result of third party activities. Over the long term, third party activities remain the main cause of spillage incidents, although the number of events has progressively decreased over the years. Mechanical failure is the second largest cause of spillage. After great progress during the first 20 years, the frequency of mechanical failures has been on an upward trend over the last decade. In-line inspections were at a record high in 2010. A total of 89 sections covering a total of 12,300 km (45% more than in 2009) were inspected by at least one type of intelligence pipeline inspection gauge (pig). Most inspection programs involved the running of more than one type of pig in the same section, so that the total actual length inspected was less at 7,178 km (21% of the inventory). Most pipeline systems were built in the 1960s and 1970s. Whereas, in 1971, 70% of the inventory was 10 years old or less,

0.0

0 1971- 1976- 1981- 1986- 1991- 1996- 2001- 20061975 1980 1985 1990 1995 2000 2005 2010 3rd party Natural

FIG. 7

Corrosion Operational

Mechanical All causes

Cold pipelines spillage by cause.

LUE CR E AT I O N VA ALUE REATION

YOU CAN RELY ON US.™™

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EBARA CORPORATION

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HPINNOVATIONS SELECTED BY HYDROCARBON PROCESSING EDITORS [email protected]

AESSEAL wins big at IMechE awards The UK-based mechanical seals manufacturer was nominated for seven out of nine categories at the Institution of Mechanical Engineers (IMechE) Manufacturing Excellence 2011 awards, and was voted Overall Winner. It also won the IMechE Customer Focus award. AESSEAL has grown at an average rate of 20% per year since opening in 1979, and it is now the world’s fourth-largest mechanical seal manufacturer, with more than 70 sites worldwide. The firm’s watermanagement technology also saves industry over 25 billion gal of clean water per year. Total sales are expected to rise from around £128 million (MM) in 2011 to £150 MM in 2012 and to £200 MM by 2015. The company offers a wide product range, including cartridge mechanical seals, gas seals, component seals and bearing protection. AESSEAL has also emerged as a product leader, crossing into new but complementary sectors such as seal support, health care contract management of host equipment, and refurbishment services for rotating equipment. AESSEAL’s logistical and operational efficiencies are evident in its ability to deliver much of its product range with a lead time of two days. The firm is investing in a new product life-cycle management system for 2012, which it hopes will give it even greater control over its production processes. Additionally, the company has invested heavily in its customer support teams both in the UK and abroad, and has established a global network of subsidiaries rather than relying extensively on agents. This approach gives it global coherence in customer service. Jonathan Wilkinson, CEO of AESSEAL, explained, “The company’s purpose has always been clear: to deliver such exceptional service that our customers need never consider an alternate means of supply. Delivering on that promise is difficult, but the business has been designed to achieve it.”

devices based on its H1 Interoperability Test Kit (ITK) Version 6.0. Emerson Process Management and Yokogawa supplied the registered H1 (31.25 kilobits/second) devices, which were tested for their functionality and conformity with the Foundation function block and transducer block specifications. Emerson’s registered devices include the TopWorx D2-FF Discrete Valve Controller, which combines analog/digital position sensing and monitoring with Foundation fieldbus communications and pilot valve output drivers for on/off applications; and the Rosemount Analytical 1066 pH Transmitter, which measures pH and ORP/ Redox, and provides comprehensive sensor, transmitter and calibration diagnostics to the bus via field diagnostics. Yokogawa’s registered devices are enhanced pressure transmitters featuring innovations in multi-sensing technology that makes use of a single-crystal silicon resonant sensor. They also support AR, IS, SC, IT and PID function blocks; NE107 field diagnostics; and software download function. All H1 ITK 6.0-tested devices support the latest advancements in field diagnostics per the NAMUR NE107 recommendation, which builds upon the existing diagnostic capabilities of Foundation fieldbus equipment. At the same time, it adds a greater degree of organization so that field instruments can represent their diagnostics in a more consistent way. For example, the use of NE 107 field diagnostic capabilities allows noncritical diagnostics to be routed to a maintenance station for future work, while critical diagnostics can be routed to operations with specific recommendations on how to resolve an instrumentation issue. This and other advanced ITK 6.0 features are fully configurable to provide flexibility in user applications. A complete list of registered Foundation fieldbus products is available in the Fieldbus Foundation’s registered catalog at www.fieldbus.org/registered.

Select 1 at www.HydrocarbonProcessing.com/RS

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Fieldbus introduces devices for H1 ITK 6.0

Sinopec picks new technology for catalyst research

The Fieldbus Foundation recently registered the first Foundation fieldbus

The Chinese oil firm’s Research Institute of Petroleum Processing (RIPP) recently

selected parallel reactor technology from hte—the high throughput experimentation company—to enhance its research and development (R&D) efficiency in oil refining. The X2000-series catalyst testing system from hte is optimized for clean gasoline production. The parallel reactor system was scheduled to be delivered to Sinopec RIPP in Beijing, China at the end of 2011. RIPP’s decision to choose hte’s technology was based on its favorable performance in a pre-validation study of hte’s reactor systems. The X2000-series parallel reactor system offers stable control of all key process parameters, which means that 16 catalysts can be tested simultaneously under the same or variable conditions over extended periods of time. Small-scale testing reduces the amount of feed and catalyst required, while the quality of the data is comparable to pilot plant data. The tailored unit features an analytical suite for real-time, full-product analysis, which will allow Sinopec RIPP to reduce the time to market for new catalyst solutions. Select 3 at www.HydrocarbonProcessing.com/RS

FIG. 1

Award-winning AESSEAL offers a wide range of products.

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 2012

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HPINNOVATIONS New flowmeters measure CNG mass flow Endress+Hauser’s Coriolis CNG mass flowmeters measure direct mass or corrected volume flow of compressed natural gas with 0.5% accuracy. The series has been approved by six US and international standards organizations for custody transfer of compressed natural gas (CNG) and for fueling vehicles with CNG, and by five standards organizations for use in hazardous areas. Available in three common sizes from 3 ⁄8 in. to 1 in., the CNG mass flowmeter measures mass flow up to 330 lb/min (150 kg/min) at fluid temperatures up to 257°F (125°C) and pressures up to 5,080 psi (350 bar). The instrument measures direct mass or corrected volume flow with 0.5% accuracy to meet custody standards. It also outputs temperature and density. As the

Coriolis flowmeter is a balanced, two-tube design, it is insensitive to pipeline vibrations and can be installed without taking inlet or outlet runs into consideration. When used for custody transfer, the flowmeter is verified onsite using reference measurements approved by the local authority for legal metrology controls. The flowmeter must be locked for custody-transfer measurements and sealed by authorized personnel, but it can easily be converted back to normal measurements. The transmitter housing is powdercoated aluminium, the sensor housing is acid- and alkali-resistant stainless steel, and all process connections are stainless steel. A multi-colored LED on the transmitter housing indicates the status of the instrument and the process conditions—such as creepage, system working/not working, custody-transfer mode started and explicit Modbus messages. Four configuration methods are available for this product. Endress+Hauser’s FieldCare software can be used for onsite configuration, verification and diagnostics. The instrument can also be configured via a highway addressable remote transducer (HART), manually via the local display, or with a plug-in electrically erasable programmable read-only memory (EEPROM). Select 4 at www.HydrocarbonProcessing.com/RS

Dresser-Rand receives Norwegian technology grant

24

FIG. 2

CNG flowmeter measures direct mass or volume flow.

FIG. 3

New barcode scanner is ideal for hazardous areas.

I FEBRUARY 2012 HydrocarbonProcessing.com

Dresser-Rand, a global supplier of rotating equipment solutions to the oil, gas, petrochemical and process industries, has been awarded 4 million (MM) NOK ($684,000 USD) in public grant funding by Innovation Norway (IN). The grant will be used to support testing for a new, environmentally friendly turbine-generator set known as the Dresser-Rand KG2-3G unit. KG2 gas turbines for power generation have a 99.3% start reliability, full-load throw-on capacity, and minimal maintenance requirements. Dresser-Rand KG2 gas turbines are ideal for standby and continuous power supply for onshore and offshore applications. The KG2-3G unit comes with an acoustic enclosure for onshore installation and is suitable for a variety of applications, including biofuel systems. The KG2 generator set has been specifically designed to meet requirements for power from 1 MW to 10 MW at single and multiple units. More than 900 units have been delivered for standby, industrial, and oil and gas applications worldwide.

The unit will be installed at the WINGAS Transport GmbH site in Greifswald, Germany, where the North Stream pipeline comes into Europe from Russia. WINGAS will provide natural gas for the field test in exchange for the heat and power produced by the KG2-3G turbine. The electric power will be exported, and the exhaust heat will be used to heat pipeline gas coming out of the Baltic Sea. The equipment was scheduled for delivery in January 2012, and the test is planned for up to 8,000 hours of field operation. IN, a development funding arm of the Norwegian government that supports environmental initiatives, awarded DresserRand the funding because the KG2-3G turbine is expected to drastically reduce fuel consumption, decrease CO2 emissions by 35%, and decrease NOX and CO emissions by 80% compared to the rating of the KG23E turbine. Select 5 at www.HydrocarbonProcessing.com/RS

Barcode reader available for hazardous areas Pepperl+Fuchs recently introduced the PowerScan Barcode Reader System for Zone 1 and Division 1 hazardous areas. The wireless PowerScan M system for Zone 1 locations consists of a transmitter and base station, with power provided by a charger located in the safe area. The wired PowerScan D system for Division 1 and Zone 1 locations consists of a barcode reader connected via a junction box to the host PC, which can be located up to 150 meters (m) away in the safe area. With PowerScan, all common, onedimensional barcode families can be captured, and patented technology effectively scans damaged and difficult-to-read barcodes. The rugged housing ensures full functionality, even after being dropped from a height of 2 m. PowerScan features a targeting guide that helps the user achieve successful readings when codes are located in close proximity to one another. Three green LEDs located on the top and back of the barcode reader are visible from any angle to visually confirm that the code has been successfully read. Successful readings are also confirmed with an audible tone, and the result can be read in the display. PowerScan can be used as a stand-alone solution, or in combination with VisuNet industrial operator work stations or TERMEX operator terminals. Select 6 at www.HydrocarbonProcessing.com/RS

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Decades of experience in the oil and gas industry, leading technical expertise, and our own product development and production facilities are the solid foundation for a wide range of high-performance products and services. We offer comprehensive solutions for the entire life cycle of a plant and along the entire oil and gas value chain. The basis is our global engineering and project manage-

ment expertise as well as extensive experience in turnkey projects. Siemens’ early involvement in the concept phase results in the best possible technical solutions and limits project risks. And packages for entire functionalities reduce interface conflicts to help optimize a plant’s CAPEX and OPEX.

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HPINNOVATIONS Safety Manager FDU caters to small operations Honeywell recently introduced its new Safety Manager field device unit (FDU), which allows process manufacturers to more easily implement small, stand-alone safety applications in their facilities. The offering combines Honeywell Process Solutions’ widely used Safety Manager platform and Remote Universal Safe input/output into a single, space-friendly unit that meets standards IEC61508 and IEC61511 for safety integrity level three (SIL-3) out of the box. The module’s small size makes it ideal for plants that need to quickly implement integrated safety measures for applications such as burner or boiler management systems. This is critical due to increasingly stringent safety regulations and compliance standards, which often require manufacturers to upgrade or even replace existing safety equipment. For example, an outdated, noncompliant panel in a boiler management system could be replaced with the FDU in the limited space close to the boiler. Additionally, the FDU has a low installation cost since it requires fewer engineering hours at initial implementation and remains

cost-effective over the course of its life cycle. Also, because it arrives SIL-3-certified, the system requires no extra engineering cost to achieve higher certification levels, which reduces associated capital expenditures and the need to certify a system after its arrival. Select 7 at www.HydrocarbonProcessing.com/RS

Biobutanol technology refined for commercial activities Butamax Advanced Biofuels recently announced agreement on commercialization principles with Highwater Ethanol, the first entrant to the Butamax Early Adopters Group. Butamax’s business model is to offer current ethanol producers proprietary biobutanol technology to permit improved biofuels growth and plant profitability. The Early Adopters Group includes founding member Highwater Ethanol, a leading ethanol producer based in the US state of Minnesota. The ICM-designed facility was constructed by Fagen with a nameplate capacity of 50 MM gal/year. In November 2010, Butamax announced the addition of a technology laboratory in Paulinia, Brazil to accelerate process development efforts for producing biobuta-

nol from sugar cane. In addition, the Butamax technology demonstration facility in Hull, England is producing biobutanol to support the design of commercial facilities. Biobutanol is a high-performing, dropin biofuel that can be blended at higher concentrations than ethanol without the need for infrastructure changes. At 16% volume, biobutanol delivers twice the renewable energy content of 10% ethanol blends. It is compatible with current automotive vehicles, retail stations and fuel distribution pipelines. The favorable blending properties of biobutanol help reduce a refiner’s cost of producing gasoline and also provide an attractive route to Renewable Fuel Standard 2 compliance in the US. Select 8 at www.HydrocarbonProcessing.com/RS

FIG. 4

Highwater Ethanol LLC facility in Minnesota.

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separation loves undivided attention The reliability of the gas separation unit is essential for the successful performance of the whole plant. Our customers can rely on our undivided attention to ensure continuous smooth operation. Under its new OASE® brand, BASF provides gas treatment solutions consisting of technology, services and products. We at BASF combine the experience of more than 40 years and about 300 distinct references with the latest innovations to provide you with your unique solution. So if our undivided attention results in your optimal gas separation and a smile on your face, it’s because at BASF we create chemistry. www.basf.com/oase-gastreatment

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45678

HPIN CONSTRUCTION HELEN MECHE, ASSOCIATE EDITOR [email protected]

North America Sundrop Fuels, Inc., plans to construct and operate its first production facility on about 1,200 acres of land that it has purchased near Alexandria, Louisiana. The inaugural plant will use sustainable forest waste combined with hydrogen from clean-burning natural gas to produce up to 50 million gpy of what is said to be the world’s first ready-to-use, renewable “green gasoline.” Located in Rapides Parish a few miles outside of Alexandria, the Sundrop Fuels’ advanced biofuels plant will cost approximately $450 to $500 million to build. Toyo Engineering Canada Ltd. a Canadian subsidiary of Toyo Engineering Corp., has a contract with North West Redwater Partnership (NWR), a joint venture between North West Upgrading Inc. and Canadian Natural Resources Ltd., to provide engineering design specification (EDS) work for a heavy-oil upgrading and refining complex in Sturgeon County, Alberta. This EDS work is scheduled to be completed in August 2012. The NWR project’s target is to build a heavy-oil upgrading and refining complex in three phases with a total capacity of 150,000 bpsd. This complex will process bitumen extracted from oil sands to produce naphtha, diesel oil and other petroleum products. The project is divided into several units, and Toyo Engineering Canada Ltd. will provide engineering services for a sulfur-recovery unit, a light-ends recovery unit, a sour water-stripper unit and an amine-treatment unit. Kinder Morgan Energy Partners, L.P., will build, own and operate a petroleum condensate processing facility near its Galena Park terminal on the Houston Ship Channel in Texas. With an initial throughput of 25,000 bpd and a design that provides for future expansions of up to 100,000 bpd, the approximately $130 million project will split condensate into its various components, such as light and heavy naphthas, kerosine and gasoil. A major oil industry customer is underwriting, through a fee structure, the initial throughput of the facility.

The pipeline, which will transport crude/condensate from the Eagle Ford shale in south Texas to the Houston Ship Channel, will consist of almost 70 miles of new-build construction and 113 miles of converted natural gas pipeline. Construction on the pipeline has begun and Kinder Morgan expects it to be in service in the second quarter of 2012. Tesoro Corp. intends to invest approximately $180 million on a capital project at the Salt Lake City, Utah, refinery that will expand crude-oil throughput capacity by 7%. The project will allow the company to increase throughput of transportationadvantaged black-wax and yellow-wax crude oil to 21,000 bpd, an increase of over 100%. The project also includes capital for conversion unit upgrades designed to drive a nearly 3% increase in the refinery’s clean product yield. Based on present estimates, the project has a payback period of less than two years and is expected to be completed in two stages in 2013 and 2014, subject to required permitting. DKRW Advanced Fuels LLC’s wholly owned subsidiary, Medicine Bow Fuel & Power LLC (MBFP), has a contract with Vitol Inc., whereby Vitol would purchase 100% of the gasoline produced from MBFP’s industrial gasification and liquefaction facility located near Medicine Bow, Wyoming. The contract is one of the first major commercial agreements in the US for the sale of liquid transport fuels made from coal. MBFP plans to sequester the CO2 that is captured from the facility by selling the CO 2 for enhanced oil recovery (EOR). MBFP has a contract with a subsidiary of Denbury Resources Inc. to purchase the CO2 for use in its EOR operations. DKRW Advanced Fuels is completing final development on the project and expects to complete financing activities and ramp up construction on the facility in 2012. Chevron Phillips Chemical Co. LP has completed several key feasibility study elements announced earlier this year and plans to pursue a project to construct a worldscale ethane cracker and ethylene derivatives facilities in the US Gulf Coast region.

Chevron Phillips Chemical’s existing Cedar Bayou facility in Baytown, Texas, would be the location of the new ethylene unit. The company has executed agreements with Shaw Energy and Chemicals to design a 1.5 million-metric-tpy (3.3 billion-lb/yr) ethane cracker using proprietary Shaw technology. Chevron Phillips Chemical’s proprietary technologies would be used for the construction of two new polyethylene facilities, each with a capacity of 500,000 metric tpy. The new polyethylene units would be located either at the Cedar Bayou facility or a site nearby the Chevron Phillips Chemical Sweeny facility in Old Ocean, Texas. A final site selection decision for these units is anticipated during the first quarter of 2012. The estimated completion date for the project is 2017. PBF Holding Co. LLC and Delaware City Refining Co. LLC (PBF) have received conditional approval from PBF’s board of directors for the construction of the PBF Clean Fuels Project. The $1 billion project consists of a mild hydrocracker and hydrogen plant that will be built at PBF’s Delaware City refinery. The construction period will last approximately three years and, when completed, will process streams from both the Delaware City refinery and PBF’s Paulsboro, New Jersey, refinery.

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: Lee Nichols P.O. Box 2608, Houston, Texas 77252-2608 713-525-4626 • [email protected] HYDROCARBON PROCESSING FEBRUARY 2012

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HPIN CONSTRUCTION The mild hydrocracker will reduce the sulfur content by 99% in approximately 65,000 bpd of distillate production from 2,000 ppm of sulfur to less than 15 ppm of sulfur, resulting in a reduction of over 6,500 tpy of sulfur-dioxide emissions. In addition, the mild hydrocracker will enable the refinery to process a heavier crude slate while producing a greater volume of clean transportation fuels with an emphasis on increasing distillate production.

Linde in North America is investing in a new air-separation plant in Lewisville, Arkansas. Linde will build a 470-tpd plant that will produce liquid nitrogen and oxygen to meet rapidly growing demand in Arkansas, Louisiana and Texas. Construction is scheduled to begin in the second quarter of 2012. The plant is expected to begin operating by the fourth quarter of 2013. The plant, which will be designed and constructed by Linde’s Engineering Divi-

Clean Fuels To meet the requirements of today’s dynamic and competitive business environment, we supply innovative, cost-effective, and safe solutions for our customers. www.worleyparsons.com

WorleyParsons is a leader in designing solutions to meet clean fuels regulations that now face refiners around the world, including government mandates on sulphur, aromatic, and oxygen content of fuels. We have extensive experience with the two major types of clean fuels projects: reformulated gasoline and ultra low sulphur diesel (ULSD), and our refinery services are backed by over 60 years of global experience in grass roots, revamp, and expansion projects. refi[email protected] Select 155 at www.HydrocarbonProcessing.com/RS 30

sion, will use the least amount of electricity possible in order to produce the gases.

South America Toyo Engineering Corp., in consortium with Y&V Ingeniería y Construcción, C.A., has a project management consultant (PMC) contract for the heavy-oil upgrading project of Petróleos de Venezuela, S.A. (PDVSA) at its Puerto La Cruz refinery in the state of Anzoátegui. The project includes an atmospheric-distillation unit, a vacuum-distillation unit, a slurry hydrocracker (HDH Plus) unit, a sequential hydroprocessing (SHP) unit, sulfurrecovery unit and a hydrogen-production unit, along with offsite and utility units. This project aims to increase the refinery’s processing capacity by maximizing the use of the extra-heavy oil produced in the Orinoco oil belt to satisfy the energy demands of Venezuela’s domestic market and exports overseas. This is said to be an epoch-making project since the project’s main unit is the first commercialization of a heavy-oil upgrading technology developed by PDVSA’s research and development center, PDVSA Intevep. The consortium will, jointly with PDVSA’s project team, perform PMC services to manage and control several contractors engaged in the project up to its startup. Project duration is estimated to be 52 months. Braskem and PetroPerú have joined forces to analyze the technical and economic feasibility of a petrochemical project in Peru. Both companies aim to study the possibility of implanting units for the integrated production of 1.2 million tpy of ethylene and polyethylene using ethane from the natural gas reserves in the Las Malvinas region. If feasibility is confirmed, and assuming successful definitive agreement negotiation and approval by the shareholders of both companies, the undertaking will be part of the so-called Integrated Southern Project. This project includes the construction of the Southern Andean Gas Pipeline by Kuntur and of a modern petrochemical complex in the south of Peru, which will reportedly be a landmark in the country’s industrialization process. WorleyParsons has a contract for the project management consultancy of the Refinería del Pacífico refining and petrochemical complex, a project with an

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HPIN CONSTRUCTION approximate total installed cost of $12 billion. The complex is located in the province of Manabí, Ecuador, and is a joint venture between PetroEcuador and PDVSA Ecuador S. A. The refinery will have a crude processing capacity of 300,000 bpd. During Phase I of the project, WorleyParsons will provide an integrated project management team (IPMT) located in Houston, Texas. The IPMT will provide oversight of the project’s front-end engineering and design (FEED) and assist the client in selecting the engineering, procurement and construction (EPC) contractors. In Phase II the IPMT will provide oversight of the EPC contractors and will be responsible for construction management of early activities at the Manabí site. The project is scheduled to be completed by December 2015. The estimated reimbursable contract value to WorleyParsons for Phase I and Phase II is anticipated to be in excess of $200 million.

Europe Lummus Technology, a CB&I company, has been awarded a contract by CJSC Vostochnaya Neftechimicheskaya (VNHK), a subsidiary of OJSC Rosneft, for the license and basic engineering of a naphtha steam-cracking unit and a butadieneand benzene-extraction unit for VNHK’s new petrochemical complex in Russia. The steam-cracking unit, which will reportedly be the world’s largest, is designed to produce more than 1.4 million metric tpy of ethylene and more than 600,000 metric tpy of propylene, using the latest advances in the Lummus SRT-VII heater technology. The butadiene unit is designed to produce 230,000 metric tpy of benzene and approximately 200,000 metric tpy of butadiene. It will use Lummus/BASF butadiene-extraction technology. Jacobs Engineering Group Inc. has a framework contract from Gassnova SF for its CO2 Capture Mongstad (CCM) Project at the Mongstad refinery site in Norway. Jacobs will provide engineering and technical assistance services to support the installation of a large-scale carbon-dioxide (CO2) capture plant for a combined heat and power (CHP) plant at the refinery. The CHP plant is integrated with the refinery and includes fuel gas/electricity exchange with the Troll gas field in the Norwegian sector of the North Sea. The CCM Project, which is in an early development stage, is funded by the Nor32

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wegian State and being undertaken by a joint venture between Gassnova SF and Statoil ASA. Alfa Laval has won an order for compact heat exchangers from a refinery in Russia. The compact heat exchangers will be used in the refinery distillation process where crude oil is preheated in different steps. They will reuse heat from the process for preheating the crude oil, resulting in a very energy-efficient solution. The order is worth approximately SEK 70 million. Delivery is scheduled for 2012.

Middle East The State of Qatar’s Minister of Energy and Industry, Dr. Mohammed bin Saleh Al-Sada, and Shell’s CEO, Peter Voser, have signed an agreement to develop a world-scale petrochemicals complex in Ras Laffan Industrial City, Qatar. This agreement follows the conclusion of a joint feasibility study conducted by the partners, Qatar Petroleum and Shell. The scope under consideration includes a world-scale steam cracker, with feedstock coming from natural gas projects in Qatar; a mono-ethylene glycol plant of up to 1.5 million tpy using Shell’s proprietary Only MEG Advantaged (OMEGA) technology; 300 kiloton/yr of linear alpha olefins using Shell’s proprietary Shell Higher Olefin Process (SHOP); and another olefin derivative. The complex will produce cost-competitive petrochemical products to be marketed primarily into Asian growth markets. Qatar Petroleum will have an 80% equity interest in the project and Shell will have 20%. The Saudi Arabian Fertilizer Co. (SAFCO), a manufacturing affiliate of Saudi Basic Industries Corp. (SABIC), has awarded SAIPEM a turnkey contract for the engineering design, supply and construction of the SAFCO-5 fertilizer plant. The new plant will reportedly be one of the world’s largest urea plants built at a cost of SR 2 billion with a capacity of 1.1 million tpy of urea. It is expected to start commercial production in the third quarter of 2014. The construction schedule is 26 months beginning from December 2011. The project will convert 850,000 metric ton of CO2 (green-house gas), that is presently vented to the atmosphere, into urea. This will qualify SAFCO to apply for global Clean Development Mechanism (CDM) certification and enable it to gain credits for these emission cuts.

The Shaw Group Inc. has a contract with the South Refineries Co., which is part of the Republic of Iraq’s Ministry of Oil, to provide a feasibility study for the rehabilitation of its 140,000-bpd refinery in Basra, Iraq. The study will assess the refinery’s condition and estimate the engineering, equipment supply and construction services required to improve its operation. The study is funded by the US Trade and Development Agency (USTDA) through a grant to the South Refineries Co. This is the first grant the agency has provided directly to an Iraqi grantee, marking the USTDA’s support of Iraq’s long-term economic development. In Iraq, Shaw is conducting feasibility studies and front-end engineering and design (FEED) for two grassroots 150,000bpd refineries near the cities of Maissan and Kirkuk, for the Republic of Iraq’s Ministry of Oil. The FEED work includes all process units, offsite facilities and utilities for both refineries. Through a fluidized catalyticcracking (FCC) alliance, Shaw, and its partner, Axens, are providing a process design package for a 30,000-bpd residual fluidized catalytic-cracking (RFCC) unit at Midland Refineries Co.’s refinery in Daura. MAN Diesel & Turbo has signed one 6-year enterprise framework agreement for the supply of new compression equipment for Shell locations worldwide and another 5-year framework agreement for the supply of aftermarket parts and services for existing rotating equipment. The agreement for new compression units covers a wide range of centrifugal compressors for sweet- and sour-gas services that will be used in both onshore and offshore applications. MAN Diesel & Turbo and Shell have enjoyed close business relationships for many decades and have cooperated in major up- and downstream projects around the globe, including the world´s largest gasto-liquid (GTL) project in Qatar.

Asia-Pacific The Linde Group is set to build and operate a new hydrogen plant in the Jilin Chemical Industrial Park (JCIP) in northeast China. The company will be investing around €42 million in the first phase of this new project. The hydrogen plant is expected onstream by the end of 2013, supplying several companies in the Jilin chemical complex with high-purity hydrogen. This park is home to

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HPIN CONSTRUCTION production facilities run by Evonik Industries and Jishen, a joint venture between the PetroChina Jilin Beifang Chemical Group and the Jilin Shenhua Group. The new hydrogen plant will use steam methane reforming (SMR) to produce 25,000 Nm3h of hydrogen. It will be built by Linde’s Engineering Division and operated by its Gases Division. In addition, Linde will set up a subsidiary, Linde Gases Jilin, to focus on further expanding the

gas supply infrastructure in and around the JCIP chemical complex. Jishen, Evonik Industries and Huntsman are investing around €390 million in total to construct a chemical hub in Jilin that will produce high-pressure propylene oxide (HPPO). Evonik is building a 230-kiloton/yr hydrogen peroxide plant to supply Jishen’s 300-kiloton/yr HPPO plant. Jishen will then supply the HPPO to Huntsman for its polyol plant.

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Jacobs Engineering Group Inc. has received a contract from Shell India Markets Private Ltd. to establish an integrated organization with Shell Projects & Technology for its project design office in Bangalore, India. Contract duration is 5 years with provision for a further extension. The Integrated Project Design Organization expects to deliver a full range of engineering and design services for onshore upstream (oil and gas) and downstream major capital projects, mainly in the Middle Eastern and Far Eastern regions. The new organization aims to blend the strong technical and engineering design capability held by Shell and Jacobs, while optimizing the best work processes and tools of both companies.

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LG Chem has chosen Burckhardt Compression to deliver one hyper compressor as a secondary compressor and one process gas compressor as a booster/primary compressor for its low-density polyethylene (LDPE) ethylene-vinyl acetate (EVA) plant in Daesan, Korea. After a thorough evaluation phase, LG Chem selected Burckhardt Compression, thanks to the proven technology and numerous references to LDPE plants with similar or larger capacities. For LG Chem, it is essential to have a single point of contact for both compressors since both compressors are installed in the main production line and are interdependent. Burckhardt Compression bears the overall responsibility for the package, that is, for compressing ethylene gas over the whole compression range. The compressors are scheduled for delivery in December 2012.

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UOP LLC, a Honeywell company, will provide key technology to Zhejiang Shaoxing Sanjin Petrochemical Co., Ltd., to produce propylene in China. The new propane dehydrogenation unit will use Honeywell’s UOP C3 Oleflex process technology to produce 450,000 metric tpy of propylene. The unit is expected to start up in 2013 at Zhejiang’s facility in Shaoxing City, Zhejiang Province, China. In addition to technology licensing, Honeywell’s UOP will also provide engineering design, catalysts, adsorbents, equipment, staff training and technical service for the project. Since the technology was commercialized in 1990, Honeywell’s UOP has commissioned nine C3 Oleflex units for on-

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 85 at www.HydrocarbonProcessing.com/RS

HPIN CONSTRUCTION purpose propylene production, with the tenth unit scheduled to start up in 2012 in Russia. Earlier this year, Honeywell’s UOP announced four similar projects in China, as well as one in Abu Dhabi. In June, SAMSON India opened its new production facilities in Ranjangaon in the Maharashtra district. About €3.5 million was invested in the 18,000-m² facilities to ensure an optimum supply for the fast-growing Indian market. During the opening ceremony, Mr. Hans-Erich Grimm, head of SAMSON AG’s Sales Division, pointed out that six chemical and petrochemical sites will be established in India thanks to the support of the Indian Government in the next few years: “A total of $250,000 million will be invested in these sites. We expect a huge demand for our products and services in India.” Essar Oil Ltd., a subsidiary of Essar Energy, has successfully commissioned a new isomerization (ISOM) unit at its Vadinar refinery. The 0.7 million-metrictpy ISOM unit is a key component of the

refinery’s Phase I expansion, which will increase its capacity to 18 million metric tpy. Reported to be among the largest ISOM units in the world, the commissioning of this unit was completed in just 32 days (as against an industry average of 50–55 days), without compromising on safety. The ISOM unit (Penex-DIH) is licensed by UOP, a Honeywell company. It is the first expansion unit to be fully commissioned, and, as such, it is now ready to start commercial production. Using naphtha as its primary feed, the ISOM unit will help produce Euro IV-grade gasoline with a high-octane rating and almost zero sulfur content. This will enable Essar Oil to produce high-grade gasoline that has wide acceptance both in the domestic and international markets. The Vadinar refinery expansion project is very close to completion. Mechanical completion has been achieved for 27 new units and utilities. Mechanical completion of the pending units—a delayed-coker unit (DCU), a vacuum-gasoil hydrotreater (VGO-HT) and a new sulfur-recovery unit (SRU)—is expected by the end of the

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month. Startup activity has commenced for all of the new expansion units that have been mechanically completed, and they will be commissioned in a phased manner. Increased refinery throughput of 18 million metric tpy will begin in the first quarter of 2012. Asahi Kasei Chemicals has decided to construct a second plant in Singapore to produce solution-polymerized styrenebutadiene rubber (S-SBR), with a capacity of 50,000 tpy. The new plant will be located adjacent to an S-SBR plant of the same capacity that is presently under construction. Construction began in June 2011, and startup is scheduled for May 2013. With S-SBR demand expected to increase further, Asahi Kasei Chemicals decided to advance plans for a second plant in Singapore to meet customer needs and ensure stable supply. Uzbekistan GTL LLC has awarded Technip an extension of the existing reimbursable services contract for the front-end engineering design (FEED) of a gas-toliquids (GTL) plant located 40 km south of Qarshi in Uzbekistan. This plant will be based on Sasol’s GTL technology, and will have a capacity of 1.4 million metric tpy, similar in capacity to the Oryx GTL facility in Qatar implemented by Technip, with the following product slate: GTL, diesel, kerosine, naphtha and liquid petroleum gas. Bechtel International Inc. has selected Honeywell to design and implement automation and safety solutions for a new multi-train liquefied natural gas (LNG) facility under construction as part of the Australia Pacific LNG project in Queensland. The project—a joint venture between Origin Energy, ConocoPhillips and Sinopec—will create a long-term industry utilizing Australia Pacific LNG’s coal-seam gas (CSG) resources in the Surat and Bowen basins. Bechtel selected Honeywell Process Solutions to provide vital integrated control and safety systems (ICSS) at the new facility, which is designed to convert CSG to LNG. The project will produce CSG for commercial markets both locally and overseas, and it already supplies gas to power stations in Queensland, major industrial customers, and homes and businesses in southeast Queensland. HP

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HPI CONSTRUCTION BOXSCORE UPDATE Company

City

Project

Ex Capacity Unit

NNPC NNPC NNPC NNPC

Bayelsa Kogi Koko/Delta State Lagos

Refinery Refinery TO Petrochemical Complex Refinery

300 bpd 150 bpd None 300 bpd

CNOOC Oil & Petrochem CNOOC Sinochem TBC Bharat Oman Refineries Hyundai Oilbank Co., Ltd. SK Energy Chinese Petroleum Corp NSRP

Huizhou Huizhou Quanzhou Undisclosed Bina Daesan Incheon Kaohsiung Refinery Nghi Son EZ

Lube Hydroprocessing Refinery Hydrotreater, Resid Alkylation, Sulf Acid Diesel, HDS Hydrotreater, Resid Hydrocracker Lube Hydroprocessing Hydrotreater, Resid

9 440 48 11.5 36 66 40 6 105

Mbpd bpd Mbpd bpsd Mbpd Mbpd Mbpd Mbpd Mbpd

North West Upgrading OPTI Canada Inc Fort Hills Energy Irving Oil Ltd

Edmonton Fort McMurray/Long Lake Sturgeon Lake Saint John/Eider Rock

Hydrocrack, Resid Hydrocracker (2) Hydrotreater Hydrotreater

29 54 120 80

Mbpd Mbpd bpd Mbpd

BASF INA Total SARAS SpA Mazeikiu Nafta Statoil Glimar Rosneft Sasol/Petronas/Uzbekneftegaz

Antwerp Sisak Gonfreville Sarroch Mazeikiai/Juodeikiai Mongstad Gorlice Tuapse Ustyurt

Sulfuric Acid Hydrocracker Lube Hydroprocessing Hydrocracker, Mild RE Hydrocracker Carbon Dioxide Capture Hydrocracker Hydrotreater, Diesel 2 GTL

420 tpy 20 Mbpd 8 Mbpd None 35 Mbpd None 5 Mbpd 82 Mbpd 1.4 MMtpy

Rio de Janeiro Paramaribo Pointe-a-Pierre

Water Treatment Hydrocracker Alkylation, Sulf Acid

Basra/Al Basrah Kirkuk Maissan Sohar Al Jubail

Refinery Refinery Refinery Hydrocracker Hydrocracker (2)

Cost Status Yr Cmpl Licensor

Engineering

Constructor

AFRICA Nigeria Nigeria Nigeria Nigeria

2800 23000

P P P P

2016 2016 2016 2015

C C U E C C A H U

2011 2012 2013 2014 2011 2011 2016

U H U H

2013

C H H U H E U U F

2012

800

U U U

2014 2013 2012

470

S F F E U

2012 2016 2016 2015 2012

U U U

2015 2015 2013

2800

ASIA/PACIFIC China China China China India South Korea South Korea Taiwan Vietnam

EX

6.6

6200

2013

CLG WorleyParsons CLG MECS|Stratco|Bayer|DuPont CLG CLG CLG CLG CLG

CLG

CLG CLG CLG CLG CLG

CLG CLG CLG CLG

CLG Fluor|CLG CLG CLG

KBR

CLG CLG Shell Global CLG Jacobs CLG CLG

CLG CLG FW CLG Jacobs

Lummus Technology

CLG

SKEC

CANADA Alberta Alberta Alberta New Brunswick

2015

EUROPE Belgium Croatia France Italy Lithuania Norway Poland Russian Federation Uzbekistan

90 817

2013 2012 2014 2014

FW

CLG Technip|Samsung Eng

LATIN AMERICA Brazi Surinam Trinidad

Petrobras Staatsolie Petrotrin

2000 m3/hr 10 Mbpd 10000 bpd

CLG MECS|Stratco|DuPont

Toyo Engineering Corp. CB&I Lummus|Saipem Aker Solutions|Saipem Bechtel|Techint\Lummus Techint\Lummus

MIDDLE EAST Iraq Iraq Iraq Oman Saudi Arabia

SRC Iraq Ministry of Oil SRC Orpic Saudi Aramco\Total JV

RE

140 150 150 96.8 61

bpd Mbpd Mbpd bpd Mbpd

Shaw Shaw Shaw CB&I CLG

UNITED STATES Delaware Delaware Texas

Delaware City Refining Co LLC Delaware City Delaware City Refining Co LLC Delaware City Chevron Phillips Chemical Baytown

Hydrocracker Hydrogen Ethylene

65 bpd None 1.5 Mtpy

100 100

Shaw

PBF Holding PBF Holding Shaw

HPI MARKET DATA

2012

YOUR GUIDE TO PROFITABLE PLANNING IN 2012 AND BEYOND

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I FEBRUARY 2012 HydrocarbonProcessing.com

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HPI VIEWPOINT The high cost of overregulation The US does not need to choose between a healthy environment and a healthy economy, it can have both Charles T. Drevna is the president of the American Fuel and Petrochemical Manufacturers (AFPM), 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 AFPM’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 AFPM, 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, Pennsylvania. 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, Pennsylvania. He received his BA degree in chemistry from Washington and Jefferson College and performed graduate work at Carnegie-Mellon University.

Just about everyone favors protecting the environment, but few have done as much as the members of the American Fuel and Petrochemicals Manufacturers (AFPM) to improve the US’ air and water quality. Members of AFPM (formerly the National Petrochemical and Refiners Association, or NPRA) are strongly committed to environmental protection. We have an outstanding record of compliance with the Clean Air Act, and have invested hundreds of billions of dollars to dramatically reduce emissions as measured by the US Environmental Protection Agency. As a result of our emissions reductions and reductions by other industries, the US’ air today is cleaner than it has been in generations. EPA data shows that total emissions of the six principal air pollutants in the US have dropped by 57% since 1980 and ozone levels have decreased by 30%. These reductions occurred even as industrial output has increased. And the EPA expects there will be continued reductions in the years ahead under regulations already in place. Today, US refiners manufacture the cleanest fuels in the world and emissions are lower than anywhere else. Our products and facilities are cleaner than those in any other nation. Our invest-

ments have resulted in significant cuts in sulfur levels in gasoline, reducing them by 90% just since 2004. Between 1996 and 2005, refiners cut emissions of chemicals listed under the Toxic Release Inventory by 36% and reduced emissions classified as hazardous air pollutants by 50%. The comparable reductions by chemical manufacturers in the same time period are 61% under the Toxic Release Inventory and 64% of hazardous air pollutants. Despite the great progress that has been made, we are concerned that the EPA and other government agencies have moved from reasonable regulation to overregulation that makes unrealistic and often conflicting demands on fuel and petrochemical manufacturers. These demands frequently have little or no significant environmental benefit but cost millions, and even billions, of dollars to meet, increasing energy costs for US consumers. One example is the proposed rule by the EPA to further reduce sulfur levels in gasoline. EPA is proceeding with what is known as a Tier 3 rulemaking as part of its general authority to regulate fuels under the Clean Air Act. The rule could lead to significant domestic fuel supply reductions, higher petroleum product imports, increased consumer costs, increased refinery emissions, the closure of US refineries that would leave their workers unemployed, and reduced energy security. Another example of overregulation involves gasoline containing 15% ethanol, or E15. EPA decided to allow E15 to be sold into the marketplace for use in cars and light trucks produced in model year 2007 and later, and then for model year 2001 and later. In addition to being what we consider a violation of law, these decisions hold the potential to create significant problems in the marketplace, including misfueling and engine damage. The impact of overregulation is clear to see. A Department of Energy report issued in 2011 found that refining margins have been continuously decreasing over the past four years. The report also concluded that the compounded burden of federal regulations was a significant factor in the closure of 66 petroleum refineries in the US in the past 20 years. Just since 2008, the recession and refinery closures have led to 3,000 lost jobs at US refineries. A handful of refineries are threatened with closure in the near future if they cannot be sold. Although some of the lost supply from shuttered refineries has been made up through capacity expansions at other facilities, the rate of new capacity coming online is decreasing due to financial pressures and the threat of overseas competition. Those lost American jobs aren’t simply disappearing, they are moving overseas to foreign competitors not strangled by burdensome environmental and other business overregulation. Foreign industries emit greenhouse gases (GHG) into the common atmosphere that every nation on Earth shares. GHG emissions produced in China have the same impact on our environment as emissions generated in the United States. Simply shifting emissions from the US to other nations has absolutely no environmental benefit, but great economic cost here at home. HYDROCARBON PROCESSING FEBRUARY 2012

I 41

HPI VIEWPOINT Sadly, today’s environment of overregulation serves only to strengthen foreign competitors eager to replace US manufacturers and workers. It will continue to weaken the US economy, make the US more reliant on nations in unstable parts of the world for vital fuels and petrochemicals, and endanger our national security. The US does not need to choose between a healthy environment and a healthy economy that provides more jobs for our citizens. We can have both. We are not calling for a repeal of existing environmental regulations that have led to major improvements in our environment and that will lead to continuing environmental improvement without further change.

We are calling for reasonableness and common sense. It is unreasonable to say that the US will spend billions of federal tax dollars to subsidize inefficient and unpopular new energy sources, deprive many thousands of workers of their jobs, and severely damage the US’ economic and national security in the overzealous pursuit of small emissions reductions that have little or no significant environmental benefit. Instead of serving the US people, such environmental extremism does far more harm than good. Our government needs to use objective analysis to determine when the costs of overregulation exceed the benefits, and to act in the best overall interest of people in the US. HP

The promise and reality of energy independence John Hofmeister, upon retirement from Shell Oil Co. in July 2008, founded and heads the not-for-profit [(501(c)(3) pending)], nationwide membership association, Citizens for Affordable Energy. This Washington, DC-registered, public policy education firm will exist to promote sound US energy security solutions for the nation, including a range of affordable energy supplies, efficiency improvements, essential infrastructure, sustainable environmental policies and public education on energy issues. Mr. Hofmeister was named president of Houston-based Shell Oil Co. in March 2005, heading the US Country Leadership Team, which included the leaders of all Shell businesses operating in the US. He became president after serving as group human resource director of the Shell Group, based in The Hague, The Netherlands. As Shell president, Mr. Hofmeister launched an extensive outreach program, unprecedented in the energy industry, to discuss critical global energy challenges. The program included an 18-month, 50-city tour across the country during which Mr. Hofmeister led 250 other Shell leaders to meet with more than 15,000 business, community and civic leaders, policymakers and academics to discuss what must be done to ensure affordable, available energy for the future. A business leader who has participated in the inner workings of multiple industries for over 35 years, Mr. Hofmeister has also held key leadership positions in General Electric, Nortel and AlliedSignal (now Honeywell International). He serves as the chairman of the National Urban League and is a member of the US Department of Energy’s Hydrogen and Fuel Cell Technical Advisory Committee. He also serves on the boards of the Foreign Policy Association, Strategic Partners, LLC; and the Center for Houston’s Future. Mr. Hofmeister is a Fellow of the National Academy of Human Resources. He is also a past chairman and serves as a director of the Greater Houston Partnership. Mr. Hofmeister earned bachelor’s and master’s degrees in political science from Kansas State University. He is the author of Why We Hate the Oil Companies: Straight Talk from an Energy Insider, Palgrave Macmillan, 2010.

Energy policy in the US has been hopelessly adrift for the past four decades, at least since President Richard Nixon declared “energy independence … in seven years” on the back end of the first Arab oil embargo that created interminable gasoline lines across the country. He launched the “energy independence” mantra that every president since has proclaimed. Nineteen successive US congresses have likewise committed to energy independence. No president or congress has succeeded in getting the country close to that goal. In 1973, the 42

I FEBRUARY 2012 HydrocarbonProcessing.com

US imported a third of its daily consumption of crude oil. In 2010, the number was closer to two thirds. New era. Now, at the beginning of the second decade of the

21st century, this nation is on a path to an energy abyss, brownouts, black-outs and gas lines before 2020 if we continue as we are. In addition, the cost of energy, fuel for transportation and electricity per kilowatt hour will depress our disposable income, and limit purchasing power and economic growth for a decade. The process has already begun. Consider that 2011 will go into the history books reporting the highest ever liquid-fuel costs in this nation’s history. The current administration, meanwhile, refuses to expand traditional energy resources, and special interests attempt to curtail new investments in traditional energy infrastructure and operations. The lackluster 2012-2017 offshore proposed leasing plan from the US Department of the Interior, continuing ongoing access prohibitions, is a good example of staying on the path we’re on, leading to ever higher priced crude oil. The political leadership of the nation, through its inaction, incompetence, arrogance or lack of interest in citizens’ well-being is knowingly—and I would suggest avariciously on the part of some— gutting the national security, economy and quality of life of US citizens for short-term political advantage. Sadly, it’s not new. It’s worse now than ever before because the US energy system is old, and new century global competition for energy resources is unprecedented. Finding the optimum solutions. The solutions to our

future energy needs are not that difficult to articulate. Citizens for Affordable Energy, the nonpartisan, education-based not for profit, which by the way accepts no funding from energy producers, describes the solutions via Four Mores: • First, we need more energy from all sources, including coal, oil, natural gas, nuclear, bio-fuels, wind, solar, geothermal, hydropower and hydrogen—an energy carrier. • Second, we need more efficiency in the production and use of energy through technology and innovation, which is conservation. • Third, we need more environmental protection to protect our land, water and air for future generations. • Fourth, we need more infrastructure to bring energy from where it is produced to where it is consumed. These foundational principles of a national energy security strategy are straightforward. Why can’t we implement them? Unfortunately, there are obvious reasons. US citizens lack sufficient awareness and knowledge of the precarious state of our

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HPI VIEWPOINT present energy system to appreciate how vulnerable this nation is, or they would, otherwise, be demanding such solutions now. The energy industry is not responsible for the nation’s energy security policy, and it has figured out how to make money the way things are, so why change? The governance of energy by our federal government is broken, dysfunctional and unfixable in its current form. And state and local governments are not responsible for the nation’s energy future. The system is broken. The federal government has three fundamental problems: • No. 1. Political time priorities trump energy time priorities 100% of the time. Two-year political cycles determine our energy future, predicated on the best tactical requirements for winning the next election. Energy time, meanwhile, requires decades to plan, construct, commission and operate, and it demands predictable investment and consistent regulatory regimes. Government ignores energy time, so little or nothing happens. It’s why our fleet of coal plants, 50% of supply, averages more than 40 years of age, and our nuclear fleet, 20% of supply, averages over 30 years of age, with no plans for refreshing or rebuilding either. • No. 2. The perverse partisanship that infects the leadership and most of the membership of the Democratic and Republican parties cripples the legislative, executive and judicial branches of our government. The two-party system, career politicians and life-time judges appointed by partisans ensure the continuity and sustained perversity of partisan outcomes, which precludes government from serving the needs of the people over the needs of the party. Citizens have tolerated this reality, which means that, until they get involved in the electoral process, the status quo continues. • No. 3. Government has grown too large and complex to govern energy and the environment in any coherent or comprehensible manner. Thirteen executive branch agencies

govern energy and the environment, along with the White House. Twenty-six standing committees and sub-committees govern both in the House and Senate. More than 800 federal judges decide energy and environmental policy, when required, from their respective benches. Because there is so much governance, government can’t govern. And the status quo continues. We have a choice. Either we can continue as is until we slide into the energy abyss and then figure out what’s next. Or, we can take the initiative to do two things: 1) educate the public on the issues and solutions for our energy future and 2) change the governance of energy and the environment into a structure that will work. Citizens for Affordable Energy has committed itself to the former. We’ll do everything that we can, and we welcome your help. We desperately also need new governance. A new independent regulatory agency, the Federal Energy Resources Board, established by an act of Congress, is the governance we need. With four essential authorities, the four mores as described earlier: • More energy from all sources • More technology for efficiency • More environmental protection for land, water and air, aligned with more supply • More infrastructure, so we can provide our future energy. Drawing lessons from the Federal Reserve Act, an independent board of governors selected for their knowledge and expertise— with terms of 14 years, like the Federal Reserve, and empowered to serve the needs of the nation and our society, not the needs of a political party—can create the short (0 to 10 years), medium (10 to 25 years) and long-term (25 to 50 years) plan that the nation needs. Anything short of transformational change in governance will fail. The sooner this change happens, the better. If we wait, we suffer. But, it’s still available to pull us out of the energy abyss that our political leaders are driving us into. HP

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

The dynamics of energy markets are increasingly determined by the emerging economies, particularly those in Asia. The World Energy Outlook 2011 (WEO-2011) projects that, over the next 44

I FEBRUARY 2012 HydrocarbonProcessing.com

25 years, 90% of the projected growth in global energy demand will come from non-Organization of Economic Cooperation and Development (non-OECD) economies, with China alone accounting for more than 30%. Transport is one of the major global consumers of energy, and, therefore, it has an important role in the global energy policy going forward. Cheap and reliable supplies of transportation fuels are the very lifeblood of our globalized economy. The WEO-2011 reckons that non-OECD car markets will expand substantially as economic growth pushes up demand for personal mobility and freight. Car sales in these markets are expected to exceed those in the OECD nations by 2020. The global passenger vehicle fleet is set to double, reaching almost 1.7 billion by 2035. Mobility drives fuel demand. Vehicle numbers and ownership in the developing countries of Asia, China and India, in particular, have powered ahead. The recent economic slowdown notwithstanding, the underlying momentum supports the rising level of motorization in parallel with higher affluence and living standards. Industry research suggested that, come 2030, automobile holdings in China could surge to about 233 million

HPI VIEWPOINT

Sources for fuels. Energy for automotive transport is domi-

nated by petroleum, as it is widely available, relatively inexpensive and it is the source from which easily transportable liquid fuels of high-energy density, such as gasoline and diesel, are made from. Unless there are significant breakthroughs in technology and cost structure, passenger vehicle technology is expected to remain dependent on petroleum fuels and internal combustion engines for the foreseeable future.2 To the extent that gasoline and diesel are the predominant fuels in use at present, they are widely criticized to be the main culprits of the air pollution problem. Supporters of alternative fuels have argued and concluded—or simply assumed—that they are necessarily “cleaner” than petroleum-based fuels and more environmentally sustainable. Indeed, much of the hype surrounding alternative fuels has centered on the promise that they will one day replace regular gasoline and diesel. We cannot see the substitution happening in the foreseeable future. The immediate reality is that oil remains the world’s most vital source of energy and it will remain so for the next few decades, even under the most optimistic of assumptions about the pace of development and deployment of alternative technology. The WEO-2011 expects fossil fuels (coal, oil and natural gas) to contribute about 90% of the increase in primary energy consumption in Asia from 2004–2030. Therefore, hydrocarbons will continue to play an important role as energy sources. The immediate future for transport fuel is still petroleumbased. Gasoline and diesel fuels are the lowest-cost option to the consumer, as the production and supply infrastructure is already well established, mature and available on a large scale. What this means is that alternative fuels and cleaner conventional fuels will have to coexist. A successful clean-fuel strategy must include both cleaner petroleum-derived fuels, as well as alternative fuels. Asia needs cleaner petroleum-based fuels. ALTERNATIVE FUELS IN ASIA

Alternative automotive fuels currently under development in Asia cover an entire spectrum: biofuels, liquefied petroleum gas (LPG), compressed natural gas (CNG), hydrogen, alcohol fuels, electricity, gas-to-liquids (GTLs), biomass-to-liquids (BTLs),

methanol-to-gasoline (MTG) and solar.3 The penetration of these technologies is still in the early stages, with biofuels (mainly bioethanol gasoline) arguably making the most headway. The key drivers for alternative automotive fuels in Asia vary from country to country. The most common motivation is to reduce dependency on foreign oil (increased energy security), to combat climate change and to encourage environmental sustainability. Biofuels in Asia. Advocates maintain that biofuels can help reduce dependency on oil imports and lower greenhouse gas (GHG) emissions, and revitalize rural landscapes in both developed and developing countries. A 2009 report by USAID on the benefits and risks of biofuels in Asia estimated that total biofuels production in the region will have jumped more than five-fold from 2004 levels—from just over 2 billion liters to almost 12 billion liters in 2008. Despite this accelerated growth, biofuels only accounted for 3% of the region’s transport fuel mix. The report pointed out that “even at this scale, it is evident that biofuels incur significant trade-offs and economic and environmental risks.” Critics of biofuels argue that they compete with food crops for land, water and agrichemicals, do not deliver cost-effective carbon emissions reductions, demand a disproportionate amount of subsidies and incentives, and negatively impact biodiversity. Others highlighted concerns over lower energy content, net negative energy balance, potentially increased emissions in volatile organic compounds (VOCs) and nitrogen oxide (NOx ), and vehicle performance issues. The USAID report purported that large-scale production of biofuels is unlikely to make a significant contribution to Asia’s future transport energy demand. By 2030, biofuels are expected to account for an estimated 3%–14% of the total transport fuel mix in China, India, Indonesia, the Philippines, Thailand and Vietnam. This projection is predicated on the premise that these countries will rapidly expand cultivation of efficient first-generation biofuel crops on under-utilized land while promoting second-generation “cellulosic ethanol” using agricultural residues. Countries in Asia that have biofuels—both bio-gasoline and bio-diesel—programs and targets in place include Thailand, China, India, the Philippines, South Korea and Vietnam. Thailand arguably has made the most progress with ethanol gasoline, while the rest of the countries continue to struggle to achieve

NG vehicle population, million unit

vehicles, although the ratio of China’s automobile holdings per capita in 2030 is forecast to remain only about 14%—a figure still lower than the average in developed countries (55% in 2004). In short, China is projected to have tremendous motorization growth potential even after 2030.1 The impact of such explosive growth in the vehicle population in Asia is multi-faceted. One recurring theme is air pollution issues. Governments in Asia have been battling this problem for years. Various studies have shown that both transportation fuels and motor vehicles are major contributors to the degradation of air quality. The fact that Asia is home to the world’s fastest-growing automotive vehicle population compounds this challenge. Major pollutant source. Automotive transportation has been identified as the largest source of particulate pollution in most cities where the vehicle pool tends to be concentrated; in some cases, up to 90% of pollution in a city comes from vehicle emissions. Cutting vehicle emissions is one of the most urgent priorities in Asia’s efforts to improve air quality. Cleaner conventional fuels and vehicle pollution control technologies are essential components of an effective clean air strategy.

6 Asia Pacific Europe North America Latin America Africa

5 4 3 2 1 0

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Source: ANGV

FIG. 1

Natural gas vehicle population by regions—2000 to 2009.

HYDROCARBON PROCESSING FEBRUARY 2012

I 45

HPI VIEWPOINT meaningful success as they deal with resource limitations, especially in feedstock sufficiency. Non-biofuel alternative fuels in Asia. Various usage

trials and programs involving nonbiofuel alternative fuels are currently underway across the region. Among them, CNG and auto-LPG have captured the most attention. Nonliquid fuel options such as hybrid, electric and hydrogen/fuel cell vehicles are also being explored. Asia Pacific is home to the world’s largest natural gas vehicles (NGV) market and is the second largest in auto-LPG vehicles. Based on December 2009 data, India is the world’s fifth largest NGV market while China is seventh. South Korea is the largest auto-LPG vehicle market globally, while Japan and Thailand are fourth and ninth respectively, as shown in Fig. 1 and Table 1.5 India’s NGV industry leverages the extensive natural gas pipelines laid across western India to distribute CNG. Other states tap into the LPG distribution network to supply autoLPG. The government is also targeting 1 million hydrogen vehicles by 2020, having approved the addition of a maximum 20% hydrogen to CNG. India is the only country in the world that has approved the use of hythane, a mixture of hydrogen and methane. While China runs the seventh largest NGV fleet in the world, CNG and auto-LPG each accounts for less than 5% of the total natural gas and LPG consumption. China is the only country worldwide considering methanol fuels, given its sizable coal industry, which provides the resources to convert coal to liquid alternatives such as methanol in gasoline and dimethyl ether (DME) as auto fuel. China now allows M15 (15% methanol) gasoline in selected provinces on a trial basis. The government also plans to devote substantial resources to develop electric vehicles. Thirteen cities, supported by government subsidies, will be pilot markets for 1,000 new energy vehicles by 2012. Japan’s emphasis is on next-generation vehicles—mostly hybrid cars. The government-driven switch from gasoline-powered autoTABLE 1. Ranking of NGV population as percentage of total vehicles as of December 2009 Ranking

Country

1

Pakistan

2

Argentina

3

Iran

4

Brazil

5

India

6

Italy

7

China

8

Colombia

9

Ukraine

10

Bangladesh

11

Thailand

12

Bolivia

13

Egypt

14

US

15

Armenia

Source: IANGV

46

I FEBRUARY 2012 HydrocarbonProcessing.com

mobiles to next-generation vehicles is based on the premise of reducing dependence on oil and GHGs. The focus is on innovation of engines (battery and fuel cell) and innovation of fuels in the form of biofuels (bio-ETBE). The official 2020 target is 50% new vehicle sales to be next-generation vehicles. At present, about 10% of the country’s vehicle fleet is hybrid cars. OUTLOOK FOR ALTERNATIVE FUELS IN ASIA

Alternative fuels do offer promise in an energy-intensive world. However, they clearly come with challenges. Countries in Asia still have some ways to go before the large-scale adoption of these fuels can be realized. Reliability of feedstock, cost efficiencies and large-scale application are the key obstacles that most, if not all, alternative fuels face. Prohibitively expensive to produce, alternative fuels can only be sustained, at this point, by extensive fiscal subsidies. This is a particularly sensitive issue in Asia where fuel-market subsidies are prevalent. Subsidized-fuel markets limit the scope for higher prices, which make alternative fuels nonviable economically. This, in turn, constrains investments, thus limiting production volume. In Asia’s context, this is a vicious cycle that is hard to break. Alternative vehicle technologies are emerging that use oil much more efficiently or not at all, such as electric vehicles. But it will take time and concerted policy and industry action for them to become commercially viable and penetrate markets. In addition Asian consumers are not ready to embrace alternative fuels, both economically and psychologically speaking. A quantum shift in consumer mindsets, preferences and behavior is required before a consumer market with critical mass will emerge. While alternative fuels are not yet mature, they do have a role to play in this energy-hungry world. This is inevitable in light of the urgency to combat climate change and the need to satisfy the ever-growing energy needs globally in the face of limited resources. Volatile and persistently high oil prices, along with the need and political will to diversify energy sources and potential environmental benefits will continue to feed interest in alternative fuels. The way forward. As far as automotive fuels are concerned,

cleaner petroleum-based fuels are the way to go. Governments will continue to tighten legislation governing (conventional) fuel quality and vehicle emissions to arrest the decline in air quality. Besides a progressive reduction in sulfur, refiners would also be required to cut benzene, aromatics and olefins levels in gasoline. The intensifying policy focus on reducing carbon dioxide and GHGs while raising vehicle efficiency will also add pressure on refiners to produce a product that meets the strictest demands. Actual experience in the US, the EU and Japan indicates that the refining process technology is mature and accessible. There is a cache of experience in the installation and integration of new processes within existing refineries. Experience with the production, blending, distribution and quality monitoring of cleaner fuels and tools to optimize refining operations are also available. Implications for hydrocarbons. The world will continue to face tremendous pressure to develop a radically different energy and power mix. The global energy landscape is moving from the oil age to the age of diversity in fuels. The era of cheap oil is over; the rules of the energy game are changing. While many people hope for an immediate shift in our energy mix, Robert Bryce, senior fellow at the Manhattan Institute and

HPI VIEWPOINT author of Power Hungry: The Myths of Green Energy and the Fuels of the Future, argues that the vast scale of global energy demand, along with the limits of alternative sources, will prevent such a change from happening for decades to come. Global energy consumption has increased by 27% over the past decade alone. Put another way, global energy use now totals about 29% of Saudi Arabia’s daily oil production, and hydrocarbons account for nearly 90% of that total. It is a matter of basic physics and simple math that hydrocarbons will continue to feed the world’s immense appetite for energy.6 HP

LITERATURE CITED For the purpose of this article, only on-road automotive fuels will be discussed. 2 Komiyami, R., “Asia Energy Outlook to 2030: Impacts of energy outlook in China and India on the world,” The Institute of Energy Economics, Japan, EDMC. 3 “Transport technologies and policy scenarios to 2050,” World Energy Council 2007. 4 For the purpose of this discussion, “alternative fuels” is defined to be automotive fuels not derived from crude oil. 5 IANGV (www.iangv.org), 2009 statistics. 6 World LP Gas Association, 2008 statistics. 7 http://www.energyopportunities.tv/Cleaner-Energy/The-Bryce-Challenge 1

Clean fuel challenges for refiners Douglas N. Kelly, PE, is KBR’s vice president of refining technology. He is responsible for the refining licensing, engineering and proprietary equipment business within the KBR Technology business unit. Mr. Kelly joined KBR in 2010. He started his career at Shell Oil Co. Prior to his current position, he held a variety of leadership positions with Zero Emission Energy Plants, Invensys and Aspen Technology. He represents KBR as an associate member on the board of the AFPM (formerly NPRA). He holds a BS degree in chemical engineering from The University of Oklahoma and has more than 25 years of refining and petrochemical experience.

With the increased global focus on the environment, there is a great deal of talk about clean fuels today. Clean fuel issues and challenges show up on the news, in politicians’ speeches and debates, and from keynote speakers at industry conferences. Clean fuels is a common topic in magazines, on the Internet and on television. So, it is no surprise that the term “clean fuels” has come to mean different things to people around the world. For the refining industry, “clean fuels” primarily refers to reducing contaminants and volatile components in transportation fuels to meet increasingly stringent fuel-product quality specifications. Refiners must meet these challenges while delivering desired financial results to their shareholders. The refining industry is struggling because meeting the challenge requires capital investment, and it comes at the same time that world crude quality is degrading. Result: Refiners are being forced to decide to invest the capital necessary to meet the new clean fuel regulations—a tough decision in its own right—or to make the tougher decision to shutdown or sell one or more of their refining assets. The question is: How will operating companies best address these challenges, especially with the added complexity that not all regions have the same challenges, standards and requirements? Regional challenges. The implementation of more stringent fuel specifications differs significantly in various parts of the world: Europe has led the way with clean fuel regulations, and refiners have responded either by implementing the required refining technologies to meet these challenges, or by shutting down or selling refineries to another company that is willing to make the investment. European refiners must comply with national regulations and European Union (EU) directives such

as Euro 5 diesel. The challenge that they face today is continuing to produce low-sulfur, clean transportation fuels with emerging Renewable Energy Directive targets and regulated carbon dioxide limits. Asia Pacific. The challenge for Asian refiners is to meet fast growing demand while complying with new emissions and fuel quality regulations and directives. Each country has its own challenges with unique regulations that are largely modeled after the EU plan. However, while in the Western World, clean fuels production is often a leading issue, in Asia, it is usually on par with many other national issues that divert attention and funding. As a result, Asia’s initiatives are moving to compliance at a more measured pace. Middle East. In the Middle East, ultra-sophisticated and complex refineries are being built to meet growing energy demand for the region, and to help meet the growing demand in Asia Pacific. Transportation-fuel quality is becoming a higher priority in the Middle East due to increasingly stringent regulations within the region and tighter regulations for fuel products that are exported to other regions. Latin America. It is no surprise that clean-fuel regulations are being rolled out slowly over time in Latin/South America. Each country has its own set of regulations. Many countries, led by Brazil, have the additional complexity of high ethanol and other biofuels blending requirements in transportation fuels. North America. In the US, there are so many sophisticated fuel regulations that refiners are extremely challenged by the task of keeping track of all requirements that must be honored. There are numerous regulatory bodies that manage the multiple fuels programs at both the national and state levels. Similar to Europe, US refiners are struggling with driving profitability, while meeting the new regulations and supporting long-term renewable content and carbon emissions limits and goals. Technology and innovation. How do refiners respond

to the clean fuel challenges? The quick answer is the same way that they have always responded to industry challenges—by looking to new technology and innovation to provide practical solutions to meet the market demands and to create value for their shareholders. Refining technology is typically provided by three types of companies: 1) those whose only business is technology, 2) those who are operating companies that also have technology businesses, and 3) those who are engineering companies that also have technology businesses. While each type of company has its advantages, alliances HYDROCARBON PROCESSING FEBRUARY 2012

I 47

HPI VIEWPOINT ■ Each refinery is unique. There are

many different scenarios, configurations, issues and constraints that must be considered to determine the best and most cost-effective approach to meeting clean-fuel regulations. between different types of companies provide refiners with additional advantages. For example, alliances between engineering and operating companies that have technology offer unique and valuable experience to help refiners overcome challenges and evaluate options. They bring together different perspectives that provide innovative ideas that address challenges in the most economically attractive way. To address the clean-fuel challenges, refiners are partnering with refining technology suppliers to provide innovative technology options to help: • Meet clean fuel standards • Improve reliability and efficiency • Provide operational and crude handling flexibility • Evaluate options and support economic decisions. Significant improvements have been made by technology companies in hydroprocessing technology and catalyst to address these challenges. This is only part of the solution. Bundling these technologies with other adjacent technologies is often what makes

48

I FEBRUARY 2012 HydrocarbonProcessing.com

a project meet the economic hurdles necessary to support shareholder-value creation. Each refinery is unique! There are many different scenarios, configurations, issues and constraints that must be considered to determine the best and most cost-effective approach to meeting clean-fuel regulations. Refiners who have spare hydrocracking and/or hydrotreating capacity and can use existing vessels and equipment to meet the new environmental specifications are rare. However, new developments in technology and catalyst occasionally make it possible to address these challenges with no more than equipment revamps as a low-cost option. Other refiners have determined that their best option is to add new parallel hydroprocessing units to meet the required specifications. One European refinery had to overcome several challenges to produce low-sulfur Euro IV diesel to meet regulations and significantly increase capacity. In addition to the clean fuel challenge, the bottoms capacity of the vacuum tower was limiting. The optimum solution was to add a second crude vacuum column, a supercritical solvent deasphalting unit and a parallel hydrocracker. While this option was more capital intensive, it provided the refinery with increased flexibility to handle more challenging crudes and meet increasingly more stringent limits. The future. Whatever your current refining situation, the constraints on the refining industry are not getting any easier. As regulations increase and crude quality decreases, refiners will need innovative ideas and new developments from technology providers to profitably meet the challenges ahead. HP

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CLEAN FUELS

SPECIALREPORT

Consider total value when optimizing catalytic cracking units Low rare-earth catalysts balance activity and selectivity against cost S. ISMAIL, BASF Corp., Iselin, New Jersey

Technological differences. While all catalyst companies

can offer catalyst products with lower RE levels, the refiner should equally look for options that balance lower RE levels with increasing activity, so that conversion is sustained at a constant catalyst addition rate from a higher zeolite content as represented by an active and selective total surface area. This can be achieved by using in-situ technology, which is particularly well-suited for this application. The in-situ process begins with a catalyst sized microsphere. The ensuing step consists of growing the zeolite crystal within the microsphere. The zeolite in-situ process serves two functions: 1) it provides the active and selective area, and 2) it provides the strength imparted to the microsphere. This technology is distinct from other catalyst technologies. With incorporated technology, a single particle is formed consisting of an admixture of clay, zeolite and binder. The incorporated 45 40 35 30 25 20 15 10 5 0

FIG. 1

0.5

1.0

1.5

2.0

2.5 3.0 RE, wt%

3.5

4.0

4.5

100 90 80 70 60 50 40 30 20 10 0

Cumulative percent of samples at RE wt% level

RE supply—demand balance. The supply/demand balance of the global RE market became disconnected when China, which produces 95% of the world’s supply of REs, severely cut its export quotas in July 2010. China is not expected to change its position, despite the World Trade Organization’s warning that reluctance to share its RE supplies constitutes a violation of the global trade rules. At first glance, export quotas for the second half of 2011 indicated a significant increase over the 2010 numbers. However, on closer examination, the new quotas reveal that nothing has changed; the new figures merely include ferrous alloys. These were not part of the quota in 2010. Market expectations are that price volatility will continue until new suppliers enter the market and reestablish the supply/demand balance. In a recent research note issued by Goldman Sachs, prices are likely to rise in the short term, over the next 18 months, and then soften in the 2013 to 2015 period.1 This softening of RE prices will most likely be due to additional capac-

ity coming online from non-Chinese sources that are expected to significantly shift the supply picture in the future. During the interim period, until RE prices once again normalize, members of the refining industry are looking for ways to address the increase in catalyst costs within their current budgetary constraints. Instinctively, the drive is to opt for lower REcatalyst formulations to offset the costs of the raw materials. While this action can have an immediate and successful impact on the operating budget, it may not be the best decision for the long term. A total solution should encompass both the profitability of yield slate against the operating expense, which includes total catalyst costs. Understanding the constraints of a specific FCC unit is critical in making the optimal economic decision. Suppliers have proactively worked with their customers to examine how low-RE catalytic options can fit the needs of specific users.

Number of sample counts

R

are earths are incorporated in the fluid catalytic cracking (FCC) manufacturing recipe to achieve higher catalyst activity and to improve hydrothermal stability. Rare earths (REs) achieved these goals by enhancing catalytic activity and preventing loss of acid sites during normal unit operations. To address the specific needs of each FCC unit, catalyst manufacturers have traditionally formulated catalysts with various RE levels that allow for optimal unit performance. The level of REs in a specific catalyst formulation depends on the operational severity and product objectives for the specific FCC unit. As gasoline demand increased, refiners requested higher RE levels of their catalyst formulation. RE levels gradually increased over time, and at the end of 2010, the average was 3%, with several refineries running in excess of the average. Fig. 1 shows 2010 historical data for Ecat samples analyzed by for REO. The data reflect all of the samples that were received and analyzed in the fourth quarter of 2010 before the RE price spike occurred. Although operational demands have not changed within the industry, current RE market conditions have put pressure on catalyst manufacturers, along with refiners, to reassess the role of REs in the FCC industry. When looking at the catalytic options, it is critical to look at the total value, and not just the cost, of REs. Catalyst suppliers have actively helped their customers analyze their operations and determine when a drop in RE levels is beneficial. As will be discussed in this article, the cost/benefits and possible performance deficits of this option should be clearly understood before making a change.

Distribution of RE in FCC catalyst samples.

HYDROCARBON PROCESSING FEBRUARY 2012

I 51

SPECIALREPORT

CLEAN FUELS

catalyst technique is inherently limited to an upper level of zeolite content, and it cannot increase surface area without seriously compromising the strength to withstand breakage in the FCC unit. The decision to change catalyst or reformulate catalyst is not a trivial one. Simply reducing RE levels of the catalyst without a comprehensive study can result in severe yield penalties and, possibly, force the refinery to cut feedrates to the FCC unit. All such consequences are economically prohibitive. Helping refiners evaluate the effect of RE levels on key catalytic variables can reduce the uncertainty of change and facilitate the decision to move to a reformulation of their FCC catalyst when appropriate. The specifics of this change in formulation and the impact of REO levels on conversion, as well as the effect of fresh catalyst surface area and addition rate, will be examined in this article. How RE affects FCC catalyst performance. When con-

sidering a move to reduce the RE component in the catalyst, it is critical to grasp the performance shifts and economic impact of such a change. The economic impact comprises two aspects. It is a function of total catalyst cost and the value created from a given catalyst formulation. Reducing the RE level will have an immediate cost saving. But this calculation alone will not give the true profit generation picture if the margin benefits from the yield slate are not included. To illustrate the impact of such changes on key catalytic performance indicators, a proprietary FCC simulation model was used to study the effects of RE levels, catalyst addition rates and fresh surface area for FCC units operating with these feedstocks: TABLE 1. Feed and equilibrium catalyst properties for Base Cases Refinery

A

API

B

C

D

26.3

22

22.1

20.1

Concarbon, wt%

0.3

0.3

0.9

4.5

Sulfur, wt%

0.5

0.7

0.5

0.4

0.03

0.05

0.04

0.04

Basic N2, wt%

% 1,000 °F+

15

20

7

4

< 10

< 10

10

20

Activity REO, wt%

180

152

116

130

75

73

72

72

3

3

3

3

Refinery

A

B

Full burn

Full burn

Rx outlet temperature, °F Regen. bed temp, °F

C

D

Partial burn Partial burn

996

997

995

977

1,326

1,291

1,287

1,319

5.3

7.1

7.7

8.7

81.9

75.4

70.3

74.1

10.0

LPG, vol%

28.8

27.4

29.1

24.4

75

9.5

Gasoline, vol%

65.3

58.9

53.6

60.7

74

9.0

LCO, vol%

11.5

17.1

20.9

15.7

6.7

7.5

8.7

10.2

73

8.5

72

8.0

71

7.5

70 0.0 FIG. 2

0.5

1.0

1.5 2.0 RE, wt%

2.5

3.0

C/O

FCC bottoms

Conversion, %

Mode of operation

Conversion, vol% 76

52

the FCC simulation model was run by holding all variables constant with the exception of the RE levels of the catalyst. The result is a fairly smooth logarithmic curve with increasing conversion and lower bottoms yields with increasing RE levels in the catalysts, as shown in Fig. 2. As the RE levels decrease, the conversion of feed to higher valued products will drop.

TABLE 2. Operating conditions and yields

Ecat properties TSA, m2/g

Unit performance as RE is reduced. In the first instance,

Restoring conversions with catalyst additions. There are two catalytic approaches to reduce RE levels in the fresh catalyst and, at the same time, restore the unit to conversion levels of the Base Case (old RE level):

Distillation % 650 °F–

• Hydrotreated vacuum gasoil (VGO)—Refinery A • Standard VGO—Refinery B • Moderate resid—Refinery C • Heavy resid—Refinery D The selected feed types can provide an analysis that covers the whole range of feed diets (types) used in FCC operations. The Base Case for all cases was 3% RE in the catalyst. As seen from Fig. 1, this was the average level of REs used in 155 FCC units. For each operation, the RE level was changed to model these scenarios: • Impact of REO level on conversion, at constant catalyst addition rates and unit conditions • Impact of fresh catalyst addition rate, to restore Base Case conversion at constant unit conditions • Effect of increasing fresh catalyst surface area, at constant catalyst addition rates and unit conditions. This approach was adopted because the first negative impact from RE reductions is a decrease in catalyst activity. The second and third bullet points were methods to recover the loss in activity through either increased catalyst additions or through choosing catalyst with a higher intrinsic activity that is achieved through increased surface area. Table 1 summarizes the Base Case for the feed types and Ecat properties. Table 2 provides the operating conditions and yields of the four scenarios.

7.0 3.5

Conversion and bottoms changes with changing RE levels in catalyst at constant catalyst additions and constant TSA area at constant operating conditions.

I FEBRUARY 2012 HydrocarbonProcessing.com

Bottoms, vol%

TABLE 3. Increasing the catalyst fresh surface area to reduce RE for equal conversion at contact addition rates Case

3% RE

TSA, m2/gm 2.5% RE 2% RE 1.5% RE

A

350

370

410

B

325

344

380

406

C

312

330

365

390

D

265

291

318

358

1% RE

399

CLEAN FUELS

Constraints. As was discussed previously, this article only addresses generic options. Refiners and catalyst users should talk to their suppliers to achieve a carefully calibrated decision based on intimate knowledge of operations needs and timing. When conversion is restored to the Base Case at lower RE levels, the unit necessarily produces a larger amount of LPG and less gasoline. This

is fundamentally due to the chemistry of the process. RE exchanged on the zeolite will increase the hydrogen-transfer reaction, which will push the increased conversion toward paraffins and aromatics at the cost of reducing cycle oil naphthenes and olefins. The source of the naphthenes, which supply the hydrogen for the hydrogen transfer to take place, is usually in the light cycle oil (LCO) boiling range: LCO naphthenes + gasoline olefins t LCO aromatics + gasoline paraffins

Required for constant additional conversion, %

The aromaticity of the gasoline does not change much. But, in most cases, it will increase the aromaticity of the LCO stream, thus lowering its cetane number. By reducing RE in the catalyst, the resulting gasoline will have a higher level of olefins, some of which will over-crack, yielding more LPG. Regarding the LCO quality, lowering the RE content improves the quality of the LCO; the LCO’s cetane number will increase marginally from a low base. Increasing the paraffinicity of LCO will also slightly increase its API gravity. From Fig. 4, when the RE is reduced from 3 wt% to 1 wt%, then the gasoline decreases monotonically from 58.85 vol% to 57.7 vol%. Concomitantly, the LPG make increases from 27.4 vol% at 3 wt% RE and rises to 29.1 vol% at an RE level of 1 wt% in the catalyst. This may not be an issue for some refineries that 180 A

170

B

C

D

160 150 140 130 120 110 100 0.0

FIG. 3

0.5

1.0

1.5 2.0 RE, wt%

2.5

3.0

3.5

Increasing catalyst addition rate can restore conversion to the Base Case.

59.0

29.2 29.0

58.8

28.8 58.6

28.6 28.4

58.4

28.2 58.2

28.0

LPG, vol%

Gasoline, vol%

Case A. The refiner can increase catalyst additions at lower RE levels. Case B. The refiner can increase the activity via higher zeolite content as represented by total surface area (TSA) of the catalyst. In Case A, it is quite possible and often economically viable to increase catalyst additions to restore the conversion to the Base Case levels. Fig. 3 illustrates how catalyst rates can restore the unit to the Base Case conversion. As can be seen from the trend, when the desired decrease in RE is low to moderate (3 wt% RE to 2.5 wt% RE or 2 wt% RE), the objective can be achieved fairly easily. For Refineries B, C and D, this will require about 10% more catalyst at an RE level of 2% as compared to the Base Case of 3% RE, while Refinery A will require a higher level of fresh catalyst, as this refinery operates at a higher severity. However, the product slate for the same conversion may be different, and the refiners will need to check whether there may be constraints that will prevent the refinery from taking a particular action. In Case B, catalysts with a higher surface area (providing higher activity) furnish the flexibility to lower RE content of the catalyst and they can maintain performance and conversion at equal catalyst addition rates. The in-situ technology allows increasing the TSA to a greater extent. The application of this technology depends largely on the starting point of the TSA being used by the refinery. From Table 3, it can be seen, that, if the refiner operating at a lower surface area, such as D, then it has a larger range of opportunity to reduce RE content than that of a refiner operating with a blend like A. To further understand this example, let us consider: Refiner B using a catalyst with 3% RE, 325 m2/g fresh TSA, and a daily consumption of 2 tpd of catalyst. The refinery would like to lower catalyst costs by reformulating the catalyst to a 1.5 wt% RE. Assuming that the refinery can handle higher levels of liquefied petroleum gas (LPG) in the wet-gas compressor and gasconcentration system, there are three possible routes a refinery can follow to reduce RE in the catalyst while maintaining present conversion levels: Case 1. Increase catalyst additions containing lower RE levels (exchanged on the zeolite). If we look at Fig. 3, then the catalyst quantity for this simulation is 20% higher. Therefore, the refinery can maintain conversion by increasing catalyst usage from 2 tpd to 2.4 tpd but at a low RE level, which is 50% lower than the Base Case. Case 2. Reformulate the catalyst by keeping the total catalyst addition rate the same but increasing the fresh TSA. In this case, from Table 3, it can be achieved by increasing the TSA from 325 m2/g to 406 m2/g. Case 3. Use a combination of Cases 1 and 2. The refinery could increase catalyst additions by 10% (2.2 tpd) and increase TSA of the catalyst from 325 m2/g to 350 m2/g. This idealized example is to illustrate a means to address the problem. Of course, individual needs may be different and they must be considered when making a decision. In either case, it is possible to combine the technology options of Cases A and B to meet a specific refiner’s FCC requirement.

SPECIALREPORT

27.8

58.0

27.6 57.8 57.6 0.0 FIG. 4

27.4 0.5

1.0

1.5 2.0 RE, wt%

2.5

3.0

27.2 3.5

Gasoline make (vol%) vs. RE level of the FCC catalyst against LPG production (vol%). HYDROCARBON PROCESSING FEBRUARY 2012

I 53

SPECIALREPORT

CLEAN FUELS

can handle higher LPG loading in the wet-gas compressor, but, for others, it may be an issue. In addition, as shown in Fig. 5, the reduction in RE also drives an increase in the research octane number (RON) of the product. Economics. To contextualize the impact of the (continuing) rise in the price of RE materials, an analysis was done to show the effects of lowering RE levels in catalyst formulation while holding catalyst addition and surface area constant. The analysis was done by considering two sets of economic values, as shown below in Table 4.2 For the olefins maximization, the objective is to increase light olefins such as propylene and butylenes. These can be seen by comparing the prices between the olefins and gasoline mode of

TABLE 4. Economic values Stream

Olefin maximization mode

Gasoline maximization mode

C2+ltr, $/BFOE

$28.19

$28.19

C3=, $/bbl

$94.90

$62.09

C3, $/bbl

$55.68

$55.68

=,

C4 $/bbl

$102.49

$82.78

iC4, $/bbl

$73.42

$73.42

nC4, $/bbl

$62.09

$62.09

Gasoline, $/bbl

$92.64

$101.69

LCO, $/bbl

$107.32

$107.32

HCO, $/bbl

$82.00

$82.00

Feed cost, $/bbl

$98.55

$98.55

operation. Using the prices in Table 4 for each mode of operation, and using Eq. 1 for calculating the value created, several conclusions were reached. As expected, the maximum olefins mode occurs at the lowest RE levels, and the maximum gasoline product occurs at the highest RE levels. These can be seen in Figs. 6 and 7, respectively. Eq. 1 was used for the net contribution after total catalyst cost: {[ (Product prices in $/bbl)i  (vol%) i } – (Feed costing, $/bbl)]  Feedrate, bbl/day} – [(Catalyst cost in $/ton]  tpd As an alternate cost saving measure, break-even calculations are shown in Tables 5 and 6. Refiners have two levers that can be actuated to achieve lower cost options for meeting their catalyst needs. In the first case, a demonstration is shown where refiners are able to trim or even substantially reduce the RE levels in their catalyst depending on their needs and objectives. In this example, it can be seen that the savings realized by lowering the RE levels can be substantial. If a refinery using 5 tpd were able to meet its objective by reducing RE levels from 3% to 2%, the savings would be about $1.5 million/yr based on the catalyst cost of $5,000/ton. The savings would be even greater if the catalyst cost is lower than the assumed price. Correspondingly, the savings would be lower if the catalyst cost is higher than $5,000/ton. TABLE 5. Constant conversion achieved by lower RE with increased catalyst addition Base Case (3%) RE 2.5% RE 2% RE 1.5% RE 1% RE

RE, wt% Catalyst consumption, %/day

58.8 Yield, vol%

58.6 58.4 58.2 58.0 57.8 57.6 0.0

1.0

1.5 2.0 RE, wt%

2.5

3.0

Savings, $/bbl

Contribution margin, $/bbl after total catalyst cost

7.00 6.95 6.90 6.85 6.80 6.75

FIG. 6

54

1.00

1.50 2.00 RE, wt%

2.50

3.00

3.50

Continuous increase in value created by operating at lower RE levels during olefins maximization mode.

I FEBRUARY 2012 HydrocarbonProcessing.com

109

123

7

9

23

0.08

0.18

0.3

0.38

Base Case (3%) RE 2.5% RE

RE

2% RE

1.5% RE

TSA, m2/g

325

344

380

406

Catalyst consumption, %/day

100

100

100

100

19

55

81

0.11

0.22

0.32

Savings, $/bbl

7.05

0.50

107

4

Delta surface area, m2/g

Gasoline make (vol%) vs. RE level of the FCC catalyst against LPG production (vol%).

6.70 0.00

104

TABLE 6. Calculation based on constant conversion with increasing TSA

Margin after total catalyst cost, $/bbl

FIG. 5

0.5

95.5 95.4 95.3 95.2 95.1 95.0 94.9 94.8 94.7 94.6 3.5

RON

59.0

100

Addition (%) catalyst over Base Case, tpd

7.00 6.90 6.80 6.70 6.60 6.50 6.40 0.00

FIG. 7

0.50

1.00

1.50 2.00 RE, wt%

2.50

3.00

3.50

Continuous increase in value created with increasing RE levels during maximum gasoline mode of operation.

CLEAN FUELS In a similar way, our analysis indicates that, in addition to supplementing activity by increasing catalyst addition, an increase in activity can be achieved by increasing the TSA of the catalyst. When these two options are applied, a greater range of flexibility is achieved. The benefits of increased TSA can be seen in Table 6. In this case, the break-even cost ranges from $224 m2/g to $155 m2/g. The actual cost of catalyst is a small fraction of this amount and, therefore, the savings using this approach are even higher than supplemental catalyst addition rates. Post audit. As part of the comprehensive technical service

provided to customers, some catalyst suppliers do provide a post-audit service. The objective of the post audit is to confirm the performance of the reformulation and to assess whether there is scope for further fine-tuning. Of course, should the refinery’s objective have changed significantly, the post audit can also help develop new strategies to help the refinery aim at targeting its new priorities. Table 7 is an example of a post audit for a European refinery that changed its catalyst formulation from an RE of 2.8% to 1.8%. The refinery kept its catalyst addition at the same level but used a reformulated higher TSA catalyst. After the refinery assessed the performance and felt comfortable with this new reformulation, it looked at other options to further cut its RE levels. As can be seen in Table 7, the post audit was done after a full inventory changeover. By comparing the projected and actual yield patterns from the unit, it can be seen that the accuracy of the modeling tool kit is very good. TABLE 7. Post audit results 2.8% RE, 360 TSA Projected

1.8% RE, 360 TSA Actual

Feedrate, tph

Base

Base

Feed specfic gravity, @ 60/60

Base

Base

Catalyst circulation rate, t/min

18.8

20.5

Regen. 1 bed temp, °C

711

697

Fresh cat. makeup, tpd

2.15

2.2

73.8

73.4

Hydrogen

0.09

0.08

Hydrogen sulfide

0.17

0.15

Methane

1.56

1.54

Ethane

1.14

1.11

Ethylene

1.32

1.32

Propane

1.84

1.76

Propylene

7.32

7.65

n-Butane

0.95

0.95

Isobutane

3.71

3.78

Total butenes

7.57

7.82

Riser/reactor operation

SPECIALREPORT

Technical service. The standard service of some suppliers follows an inclusive product selection approach to match the ideal product based on input from sales, service, manufacturing and marketing. In this approach, each catalyst offer is customized to meet the objectives of the refiner, taking into consideration the constraints of the specific user whether, they are operational or economic. As a follow up with continued after sales technical support, regular technical support services (TSSs) should be made available. Such reports provide the refinery management with an ongoing systematic evaluation of their FCC operating conditions, together with the impact of the catalyst to support the strategic direction of the FCC management. The major objective is to ensure that the catalyst formulation fits into the refinery strategic decision of optimizing its profitability on an ongoing basis. This is done to support the refinery with an optimum catalyst recipe to meet the changing needs of the refinery within its operating unit, market and logistical constraints. Fig. 8 shows a quick summary of information flow for the TSS. Action plan. In the context of the high RE price environment,

refiners can apply methods to reduce operating costs associated with fresh catalyst purchase and to minimize the risk of a catalyst reformulation. The process of extracting maximum benefit comes into being by the interplay of information between customer and supplier through communication, understanding, tools and products. Suppliers have managed this process at the front end through heavy investments in R&D, production process and equipment to bring about best in class products.

Regeneration operation

Conversion Fresh feed conversion (as cut), wt% Product yields, wt%

C5 to 221°C gasoline

42.95

42.08

LCO, 221°C to 350°C

13.79

14.41

Slurry, 350°C

12.53

12.18

Coke

5.19

5.17 Select 160 at www.HydrocarbonProcessing.com/RS

SPECIALREPORT

CLEAN FUELS

timely meetings are held with the refiner, accompanied by detailed reports to keep Catalyst the refinery fully apprised of the unit operCatalyst manufacturer utilizes Catalyst Catalyst manufacturer ation, economics impacts and constraint State of the art manufacturer manufacturer publishes a tools for comparison checks for analyzes positions. This is to minimize surprises for quarterly report and simulation accuracy and Refinery provides Ecat data with finding to the FCC management. consistency of data FCC simulation models operating data Fines analysis ensure operations Mass balance closure Scrubber water Comprehensive After the total inventory has been turned and profitability Heat balance benchmarking samples targets are on over, a post audit is completed to confirm H2 balance Heat balance Feed analysis track H2 balance the projections. The post audit also gives the refinery the opportunity to decide if Information flow to support refinery operations to create maximum value. FIG. 8 there is still further scope for improvement. Through state-of-the-art technology and a partnering approach, the catalyst supplier The process begins with the catalyst supplier fully understandis able to combine the benefits of selecting the optimal proding the needs of the refinery to reduce operating costs, as well as uct, expertise and global experience to ensure continued value being fully versed regarding the operating objectives and concreation for its customers. For the customers, this approach straints of the unit. This information is presented to the product helps them make highly informed, high-quality decisions to selection team to select one or more products for a given set of support the refinery’s plan by minimizing risk and surprises, and operating conditions. Once the catalyst is selected, the product to increase profitability. HP is evaluated in a proprietary FCC simulation model against the LITERATURE CITED customer’s operating capabilities and constraints. The information 1 “Rare Earth Supply Peaking, To surplus by 2013,” Goldman, published by gathered from simulation programs are then compared against a Dow Jones (Sydney), May 4, 2011. benchmark database to ensure the practical potential reality of 2 The table was based on CMAI estimates and then modified with internal the selection, which the account manager then fully discloses to documents for estimating the FCC economics. CMAI reports are supplied by the customer. Chemical Market Associates. Following the decision made by the refinery, the execution of the process moves into the next phase. A heightened level of the Solly Ismail is a technical service modeling specialist with BASF Refining Catalysts, technical support is initiated, where real operational data from working with the BASF Refining Catalysts Sales organization. He holds an MS degree from Lehigh University, Pennsylvania, and an MBA from the University of South Africa. the refinery is analyzed for consistency and accuracy. Regular and Operating data Process check Process analysis Optimizing operation

Final report

INTRODUCING INTRODU

PEOPLE PERSPECTIVES:

An Oil & Gas Workforce Report and Outlook A In today’s competitive it’s more important than ever to separate your etitive work environment, enviro company from the pack when it comes to recruiting and retaining top talent. Gulf Research surveyed nearly 900 global oil and gas professionals to measure job satisfaction, motivation, morale, compensation and future plans in this one-of-a-kind workforce outlook. This exclusive report features: • A breakdown of the current global and US oil and gas workforce by labor type (local or imported), contractor status, gender, age and ethnicity • An employment forecast by various survey and analyst indicators: budget, construction, drilling and development, and workforce age • Current attitudes on job satisfaction and security, morale and motivation, future plans, safety and the industry as a whole • Existing workforce compensation – current global and US compensation analysis and forecasted changes in compensation • Hiring dynamics relating to the availability of potential workers and competition for existing and future workforce

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Purchase this report today to: • Gain a deeper understanding of employee attitudes, beliefs and needs • Establish workforce benchmarks and determine how your company measures up against the industry as a whole • Recognize global trends and discover how to attract and retain the brightest employees by developing a superior work environment Author: Jill Tennant | No. of pages: 70 | Price: $1,495 | Pdf format

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Published by Gulf Research, a collaboration between Gulf Publishing Company and Gelb Consulting Group, Inc., in January 2012.

56

I FEBRUARY 2012 HydrocarbonProcessing.com

CLEAN FUELS

SPECIALREPORT

Increase energy efficiency for your refinery Behavioral and organization changes are needed to effectively maximize operating profits Z. MILOSEVIC, KBC Process Technology Ltd., Walton on the Thames, Surrey, UK

A

s the margins remain low, the importance of reducing the operating costs, improving margins and maximizing the use of the existing assets remains a high priority for refiners globally. Energy efficiency is in focus, both as a cost issue and as environmental concern. This importance has also been recognized by new standardization in the area of Energy Management (ISO 50001, to be implemented by end 2010) and Energy Management Systems (BS EN 16001, implemented in 2009). However, while many refinery engineers and operators have ideas about how to improve the energy efficiency of a site, these ideas very often fail to mature or be implemented. What is most undesirable to any refiner in the present market environment is that the good ideas and desirable projects are not put into practice. Refineries can and do focus very effectively on operational excellence, maintenance or safety, but they rarely create an energy-focused organization. This occurs due to various reasons, including lack of organization, equipment (instrumentation), or tools and skills that are required for project identification and effective implementation. Conversely, some refiners show remarkable vigor and ability to implement such projects. What is their secret? Which organizational factors affect the implementability of good ideas, and which can be quickly adjusted and amended to achieve good implementability?

Project challenges. The obstacles to

effective project implementability usually fall into three categories: • Technical—Lack of instrumentation, measurements, accurate data or controllability.

• Skills-related—a shortage of skills and tools. • Behavioral and organizational. It has been often noticed that even in the absence of the first two roadblocks, and with only the third challenge (behavioral or organizational) present, project implementation is slow. The lack of required organizational and behavioral features cancels the effects of skills and technical effort. If so, a complete revamp of a refiner’s practices is often required, encapsulated into what is called the creation of an “energy focused organization.” This article will discuss behavioral and organizational factor, what is needed to create an energy-focused organization, and how the transition can be effectively made.

• Energy policy. It includes existence, clarity, completeness and adherence to the organization structure. • Organizational structure. It is the position and role of the site energy coordinator and the energy team, their responsibilities, authority, and senior management support. • Motivation. Must be present at all levels. • Information systems. This includes adequacy of measurements, targets, reporting • Marketing of energy efficiency. How is energy efficiency promoted both internally and externally for the company? • Investment. Such projects require building the case for investment and creating budget availability.

ENERGY-FOCUSED ORGANIZATION

Energy policy. This is the refiner’s public statement of commitment. It is the vision, and, as such, it forms the foundation of a successful energy management program. It is formally written, clearly and succinctly, and contains measurable objectives in improving the energy performance, including any other goals such as environmental protection. The policy is tailored for the particular organization. It is approved and issued by its chief executive, and involves the key members of the senior management team. A well-written policy is understandable to both employees and the public. It is realistic. It includes the skills and abilities of all management and employees. The policy is communicated to all staff, so that everyone is encouraged to get involved. The policy will ideally state the chain of command, define the responsibilities and provide authority for implementing the energy program.

Refiners have been talking about “profit-oriented organization” and “operational-excellence-focused refining.” However, energy effectiveness has become a factor of such a vital importance that a new term, “energy focused,” has been added. An organization may have all of the tools and knowledge necessary to be a world-class energy performer, but without a clear energy strategy, along with motivated and informed personnel and an organization that supports energy initiatives, the end result will be less than desired. An energy-focused organization is crucial for ensuring the implementation of the identified improvement opportunities and for sustaining good operational efficiency. The term “energy-focused organization” defines the organizational structure and procedures that support good energy management. That structure and those procedures are usually contained in six areas:

Organizational structure. The effec-

tiveness of the organizational structure HYDROCARBON PROCESSING FEBRUARY 2012

I 57

SPECIALREPORT

CLEAN FUELS

revolves around the office of the site energy coordinator, and the coordinator’s competencies and authority. The energy coordinator is the key player, who leads the energy management program, and communicates and reports to the senior management. The energy coordinator is responsible for: • Developing and promoting of the corporate energy policy and energy-efficiency plan • Motivating the staff to improve the energy efficiency • Assuring accountability and commitment from the organization • Ensuring that the necessary means are in place to achieve the goals in terms of systems, resources and training • Identifying and evaluating areas for improvement. The members of the energy team should include representatives from operations, utilities, maintenance, planning, facilities and environment. They help the leader to integrate the program and to measure and track the energy-performance data. Motivation. It is typical for engineers

and operators to be conservative, to try to remain within their comfort zones, and to adhere to the established practices. Motivation “induces people to act voluntarily in a certain way and then to persist in the face of difficulty.” Motivation needs to be extended to all players—senior managers, heads of departments and operators. Different motiva-

tional factors apply to different organizational levels: • Senior managers are motivated by incentives to reduce costs and improve profitability. • Heads of departments are the budget holders and are responsible for the energy cost. Their motivation can be in the use of under-spending and setting budgets for the succeeding year. • Operators need to be trained and their performance monitored by the use of key indicators and energy metrics. Internal competition (tracking sheets, scorecards, etc.), recognition (highlight and reward accomplishments), financial bonuses and prizes, and environmental responsibility are all valid drivers for improved motivation, especially if they work in conjunction with well-introduced performance standards. Information systems. An energy management information system measures, targets and reports the energy consumption. Effective measurement extends to consumption of all utilities (electricity, fuel, steam and water,) documenting consumption and creating the historical database. Setting realistic, achievable and, yet, aggressive targets is one of the main features of an effective energy-efficiency program. The targets take the form of key-performance indicators (KPIs) and energy influencing variables (EIVs), which have to be defined for each of the selected users. They are set

TABLE 1. Energy policy needs according to ISO 50001 • Defines and documents the scope and boundaries of the energy management system • Is appropriate to the nature and scale of, and impact on, the organization’s energy use • Includes a commitment to continual improvement in energy performance • Includes a commitment to ensure the availability of information and of all necessary resources to achieve objectives and targets • Includes a commitment to comply with all applicable legal and other requirements • Provides the framework for setting and reviewing energy objectives and targets • supports the purchase of energy efficient products and services • Is documented, communicated and understood within the organization • Is regularly reviewed and updated

Energy strategy

Work process mapping

Job performance profiling

Awareness program design

Organizational alignment FIG. 1

58

Organization alignment to ensure improved energy-efficiency programs.

I FEBRUARY 2012 HydrocarbonProcessing.com

Rollout

with much care by a team of specialists at each organizational level. The energy performance reports should be tailored for different levels within the organization and written in an easy-to-read format. They would typically summarize the targets, compare the targets and actual operation, and show lost opportunities due to sub-optimal operation in monetary units. It is often found that, by just installing the information system, the energy performance does improve. Marketing. An energy-focused organization promotes its energy management both internally, throughout the organization, and to the outside world. The “marketing” of its energy program is the responsibility of the energy team. To be effective marketers of internal policy, the team members must gain the confidence and commitment from key personnel. They will encourage debate and suggestions on the ways to improve energy efficiency and to promote the energy-reduction program outside the organization. They will be responsible for personnel training. As always, to be effective in marketing, the energy team members will need to do their homework and find who will be involved in the program and what the needs of the people involved are. They will also endeavor to learn the other energy managers actions and to become very familiar with the type of energy-saving measures that are available, along with the benefits and the costs from such programs. Investment. Within the fixed budgets, the energy-efficiency projects will compete against other projects in a refinery. Some refiners differentiate positively in favor of energy projects, on the grounds that the energy project, once installed “sits there and makes money,” as opposed to yield-related projects, where the profitability depends on ever-changing relative product pricing. In either case, the energy team needs to build a strong case for investment. This consists of the assurance of a) the correct selection of projects, b) the accurate calculation of the benefits and c) the accurate estimate of the project costs. Many engineers and operators will know how to save energy and can propose meaningful projects. The trick, however, is in the organization’s ability to agree on and prioritize those ideas. From dozens or hundreds of ideas to propose, only those ideas that are undoubtedly the best and the most worthy of implementation will be used to create a

CLEAN FUELS road map of projects that are targeted for energy performance for the site. HOW TO CREATE AN ENERGYFOCUSED ORGANIZATION

An energy-focused organization will have most of the mentioned six areas of concern well addressed, including: • The energy policy and the related action plan will exist. It will be regularly reviewed, and will have the commitment from top management. • The energy management will be fully integrated into the management structure. • There will be formal and informal channels of communication at all levels to motivate staff in energy conservation. • A comprehensive information and management system will exist with proper monitoring, target setting and reporting. • The value of energy efficiency will be continually promoted within the organization and outside of it. • Positive discrimination in favor of energy projects will be secured. These organizational features are not produced overnight. It may take a long time for pacesetters in energy efficiency to create and sharpen their energy focus. While it is difficult to generalize, it is likely that the process of creating an energy focused organization will start with proper organizational alignment, which means aligning the refinery management team with the energy strategy and the overall business goals, as shown in Fig. 1. The activities shown are defined as:

defining how energy projects are included in investment budgets. • Performance support tools. These tools identify training needs and developing human performance management processes and support elements. • Training programs. Job profiles. Such profiles define the roles and responsibilities of the key members for the energy team, including an outline of the required competencies and measurement criteria. This may require introduction of new positions. But energy focus should also be included in the roles and responsibilities of existing operations and technical staff.

SPECIALREPORT

marking the organizational structure and energy management practices, and identifying performance gaps. Many refineries will find that, while sufficient expertise and technical knowledge exist, the lack of adequate organization, motivation and implementation ability or implementation culture prevent them from actually improving their energy performance. The order and methods of addressing and reducing these gaps will differ from site to site, but most refiners will find that training will be required at all levels, followed by re-organization, with sufficient authority given to the site energy coordinator, and implementation of an energy management system. HP

Awareness program design. This

program includes developing leaflets, campaigns, information and training needs. THE WAY FORWARD

Assuming that energy effectiveness will remain a strong industry driver for years to come, creating an “energy-focused organization” will become an unavoidable task and an essential part of good refinery management. The process will start with bench-

Dr. Zoran Milosevic is a senior staff consultant with KBC Process Technology Ltd., and an internationally renowned authority on energy optimization and profit improvement of oil refineries and petrochemical plants. He is best known through his work on profit improvement and energy conservation. He has over 40 published papers and articles on energy efficiency, refinery/petrochemicals profitability improvement, and energy economics. Dr. Milosevic has given numerous training courses on energy economics, refinery energy efficiency and pinch technology.

Develop an energy strategy. This

involves setting strategic goals, developing a vision statement and identifying how the organization will support the main internal clients for energy (energy efficiency “owners.”) • Work process mapping. Writing the working processes and practices associated with economically optimizing the energy performance of the plant should be reviewed and defined. It should cover: • Energy reporting structure. It defines how energy performance is reported and monitored throughout the organization. • Operational practices. These practices define key performance indicators and energy influencing variables, packed into an Energy Management System. • Improvement identification practices. These practices define the appropriate procedures and resources for identifying and evaluating opportunities, and for Select 162 at www.HydrocarbonProcessing.com/RS

59

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CLEAN FUELS

SPECIALREPORT

Use advanced catalysts to improve xylenes isomerization This refiner wanted to increase ethylbenzene conversion while limiting aromatics losses G. SHOUQUAN, Sinopec Zhenhai Refinery & Chemical Co., Zhenhai, China; and J. CHUA, Zeolyst International, Singapore

S

inopec Zhenhai Refinery and Chemical Co. (ZRCC) started up a 450,000-tpy paraxylene (PX) complex in August 2003. The complex was originally designed to use a locally produced xylene isomerization catalyst. The performance of xylene isomerization catalyst during the first cycle began to deteriorate rapidly after the regeneration in March 2007. The ethylbenzene (EB) conversion rate dropped from 25 wt% before regeneration to 22 wt%, and the PX/xylene ratio in the product also dropped from 22.7% to 22% and directly led to a 0.4 wt% reduction of PX concentration in the PX adsorption unit feed. As a result, the PX production dropped by 50 tpd of PX; the C8 aromatics loss was higher than 4%, which is very high. Temperature and pressure increases in the reaction system were increasing significantly faster than before regeneration, with the rate of temperature increase jumping from 0.5°C /month to 2°C/month. As the isomerization catalyst performance deteriorated rapidly, ZRCC had planned to replace the xylene catalyst during a scheduled maintenance turnaround in 2008.

Xylene isomerization process. The xylene isomerization reaction of the EB reforming type catalyst is designed to isomerize aromatics present with PX in an amount often less than 1% in the reactor feed into four xylene isomers—PX, metaxylene (MX), orthoxylene (OX) and EB—close to equilibrium, at a defined temperature and pressure with the presence of a catalyst. The objective is to reduce the EB content and to increase xylene concentration of the feed for the PX adsorption unit. The higher xylene content to the adsorption unit increases the PX product yield and minimizes recycling and energy consumption. For the isomerization reaction, higher EB conversion rate and PX concentration in the product will bring the C8 aromatics closer to equilibrium. At the same time, the C8 aromatics loss will be higher. This shows that, within a certain range, the activity and selectivity are in an inverse relationship. Therefore, careful consideration should be given to the activity and selectivity while operating with this catalyst. Table 1 lists the guaranteed values of the catalyst performance parameters.

CATALYST SELECTION

After discussions with a number of catalyst technology owners (foreign and domestic) and conducting a catalyst technical evaluation among them, ZRCC selected the latest generation of a xylene isomerization catalyst. The new first-generation xylene isomerization catalyst was initially commercialized in 2001, and it has now been applied in more than 11 units outside of China. In June 2006, the Sinopec Yangzi branch applied the first-generation catalyst successfully in its aromatics plant with outstanding results. The newer generation catalyst is developed based on the concept of the first-generation catalyst with an improved manufacturing process. Processing benefits from the new catalyst system included high activity, high EB conversion rate, high PX/xylene ratio in the product, low C8 aromatics losses and long cycle life. In addition, this catalyst is very robust and can perform well in different operating conditions. It is in operation at three operating units in Taiwan and outside of China.

INDUSTRIAL APPLICATION OF ZRCC PX COMPLEX

ZRCC’s PX isomerization unit has a designed throughput of 267 tons/hr. In the design, an extra C8 naphthenes recycle column was added downstream of the deheptanizer to reduce the circulation path of the C8 naphthenes. Fig. 1 is a simplified flow diagram of the ZRCC’s isomerization unit.

High-pressure separator

Raffinate

Naphthenes recycle column Xylene isom reactor

Deheptanizer E-7

CATALYST PARAMETERS

This catalyst is jointly developed and uses a proprietary carrier. Upon delivery, ZRCC sampled and analyzed the catalyst. The results showed that the catalyst had a loss of ignition of 0.77 wt% at 420°C and a specific surface area of 267 m2/ g, with no particles smaller than 30 mesh.

Fuel gas

To xylene splitter

FIG. 1

Simplified flow diagram of ZRCC’s PX isomerization unit.

HYDROCARBON PROCESSING FEBRUARY 2012

I 61

SPECIALREPORT

CLEAN FUELS

Catalyst loading. ZRCC’s isomerization reactor is a radial-

Pretreatment of catalyst before feed. Industrially

flow reactor. Based on the calculation, centerpipe modification in the original reactor was required to fully optimize the catalyst performance. This was done by removing the original seal and slump-catalyst layer and covering the top of the catalyst with a proprietary material that could withstand high temperatures. This top cap was followed with a layer of ceramic balls. Pretreatment of the reactor. The spent catalyst did not undergo carbon burning before unloading. Thus, the reactor needed a pre-treatment step to remove the residual hydrocarbons. In the pre-treatment process, the carbon dioxide (CO2 ) level was monitored every hour. When the CO2 level in the reaction system was reduced to less than 0.2% and the water content to less than 1,800 ppm, the carbon-burning treatment was considered complete. Reactor catalyst loading. After the carbon-burning treatment of the reactor, the catalyst was densely loaded using a proprietary dense-loading technology. The total actual catalyst loading was 84.96 tons.

produced catalysts will absorb moisture during manufacturing, transportation and loading. To ensure the activity of fresh catalyst, a drying process is done before introducing feed to the catalyst bed. The drying process requires heating the catalyst using nitrogen with an oxygen content of 1 mol% to 3 mol% at 10 barg. As new insulation materials were installed in the furnace during the downtime, to dry the insulation materials, the heating rate was very slow at first, and temperature was kept constant. When the temperature reached 200°C, after which the reactor inlet temperature was increased to 400°C at a rate of 25°C/hr and kept constant for two hours. Water was detected at 230°C and, at 260°C, the maximum water content was about 1,800 ppm, but no free water was detected at the low points of the system. Catalyst reduction and passivation. After drying the catalyst was completed, the oxygen in the system was fully displaced by nitrogen. The pressure was then gradually raised with hydrogen to reduce the catalyst. During the reduction, four hours after the inlet temperature reached 420°C, water began discharging at low points of the system. The temperature was kept constant until the amount discharged started to decline. In total, 150.2 kg of water was collected during the reduction process; it is equivalent to 0.18 wt% of the water content of the fresh catalyst. Catalyst sulfiding. Platinum, in a reduced state of the fresh catalyst, has a too high activity, which can lead to side reactions such as extensive cracking and/or temperature runaway in the case of direct feed to the reactor. All side reactions impact the catalyst’s long-term performance and service life. For that reason, catalyst pre-sulfiding is done before introducing feed in the catalyst bed. A total of over 100 kg of DMDS sulfiding agent was injected into the system in two steps through a specific device onsite. It was hard to detect hydrogen sulfide (H2S) due to monitoring a large range of tubes, and no H2S was detected at the outlet of the reactor after the sulfur injection. After the sulfiding, the reactor inlet temperature was maintained at 335°C for the final preparation for feed introduction.

TABLE 1. Guaranteed values of performance parameters Item

Guaranteed value

PX approach to equilibrium (PX-ate), %

≥ 95

EB approach to equilibrium (EB-ate), %

≥ 60

C8 aromatics loss, wt%

≤ 2.9

TABLE 2. Catalyst operation conditions during performance test run Ranges of parameters

Value during performance test run

3–4.5

3.1

Reaction pressure, MPa

0.65–0.13

0.69

Inlet temperature, °C

350–415

374

Hydrogen-oil ratio, mol/mol

2.5–6.0

5.04

Recycle gas H2 purity, vol%

≥ 75

86

Item WHSV, h–1

TABLE 3. Performance comparison between catalysts New catalyst Previous catalyst Designed Performance Designed Performance value test run value value test run value

Item Parameter

≥ 75

86

≥ 80

85

0.65–1.13

0.69

0.65–1.13

0.76

350–415

374

370–420

373

Recycle gas H2 purity, vol% Pressure, MPa Inlet temperature, °C

3.0–4.5

3.08

≤ 3.2

3.2

2.5–6.0

5.04

≥ 4.8

5.4

PX-ate,%

≥ 95

≥ 95

93

EB-ate,%

≥ 59

≥ 59

52

WHSV,

h-1

H2/oil ratio, mol/mol Reaction performance

PX/xylenes, wt%

≥ 22.1

≥ 21

22.1

EB Conversion, wt%

≥ 25.8

≥ 30

25.8

≤ 2.9

≤ 3.7

4.1

C8A loss, wt% Service life of the first cycle, month 62

≤ 2.9 60

I FEBRUARY 2012 HydrocarbonProcessing.com

60

Catalyst feed introduction. Prior to introducing feed to

the catalyst bed/reactor, the composition of the liquid feed (raffinates and makeup hydrogen) was analyzed, and the feed met the required specification. The liquid feed was introduced into the reactor under these conditions: inlet temperature of 335°C, reactor pressure of 11 barg, recycle-gas hydrogen purity greater than 80% and makeup-hydrogen purity greater than 97 mol%. The weight hourly space velocity was 3.0 hr–1. After feed introduction, the reaction pressure decreased rapidly, and temperature rose sharply, during which the reactor outlet temperature rose to a maximum of 418°C, and the maximum reactor Δ temperature was 50°C. After the first round of heat waves passed, the reactor Δ temperature dropped to 35°C. This signified a successful catalyst feeding. Fig. 2 shows the reaction temperature increase and pressure changes during feed introduction. During the initial operating period after feeding, there were obvious increases in hydrogen consumption and in gas generation due to the formation of C8 naphthenes within the first few hours. After 24 hours, the difference between the temperatures at the reactor inlet and outlet was reduced to about 21°C, and the reactor outlet pressure was reduced from 10 barg to 6.3 barg, with

CLEAN FUELS

INDUSTRIAL APPLICATION

After smooth operations for more than three months, ZRCC and the catalyst provider conducted a 72-hour catalyst performance test run. Tables 2 and 3 summarize the catalyst performance test run conditions and results, respectively. During the catalyst performance test run, all performance indicators were met, with PX-ate and EB-ate, and the C8 aromatics loss was better than the guaranteed values. Performance comparison between catalysts. From the catalyst performance test run results, the new catalyst shows a great advantage in performance as compared to the original isomerization catalyst. The new catalyst system operates better in each of the indicators, especially the PX/xylene ratio, EB conversion rate and C8 aromatics loss, under less severe operating conditions (at a similar temperature but at a lower pressure of 0.7 barg). The comparison of specific performance indicators is summarized in Table 3. From the comparison of the reactor inlet and outlet compositions, the PX concentration in the product increased by 2.2 wt% and EB concentration was reduced by 3.1 wt% using the new catalyst. Daily PX production increased by about 110 tpd, and ZRCC can achieve the operations target of increasing PX production while significantly reducing the C8 aromatics losses without any modifications to the process or to the configuration in the complex. In 2009 and 2010, after the new catalyst was installed, ZRCC produced 500,000 tons of PX annually, in spite of some performance decline in the PX adsorption unit observed at the end of the period. The PX production was maintained at a similar level before replacing the catalyst, with the throughput remaining unchanged, and the C8 aromatics losses were reduced by 30,000 tons and 20,000 tons, respectively. The excellent range of performance offered by the new xylene isomerization catalyst allowed to compensate declining PX adsorbent separation performance by increasing operational severity and thus helped to maintain the competitiveness of the complex. Longer operation cycle for the catalyst. By January 2011, the xylene isomerization unit has been in operation for over two years, and the catalyst still demonstrated good isomerization activity and conversion rates while maintaining a low C8 aromatics loss. The reaction inlet temperature is now 374°C, and the rate of temperature increase is less than 0.5°C/month on average, particularly in 2010 when the temperature was only raised by 4°C for the entire year. These conditions indicate that the catalyst has excellent stability. ZRCC’s PX plant has been in continuous operation for nearly eight years. In the second half of 2010, a decline in PX separation efficiency was observed. In order to maintain PX production throughput, ZRCC decided to reduce the EB concentration in the adsorption unit feed and to optimize the adsorption unit efficiency. ZRCC increased the operating pressure of the isomerization unit to maintain a relatively high EB conversion

425 415 405 395 385 375 365 355 345 335 325

FIG. 2

1.2 1.1 1.0 0.9 0.8 0.7 Reactor inlet temperature Reactor outlet temperature HPS pressure

0.6

HPS pressure, MPa

Temperature, °C

the hydrogen purity up to 86%. The EB-ate and PX-ate were maintained at a relatively high level. With the catalyst further stabilized, the C8 aromatics loss was significantly reduced, thus indicating that the C8 naphthenes balance was established. After 48 hours, the PX-ate and EB-ate remained unchanged, with the C8 aromatics losses further reduced to the expected values. Thus, the feed introduction was successful.

SPECIALREPORT

0.5 0.4

Reaction temperature increase and pressure changes during feed introduction.

TABLE 4. Long operation cycle at ZRCC’s xylene isomerization complex Item Weight space velocity, h-1

2009

2010

3.2

3.2

Reaction pressure, bar

6.4–7.6

7.6–8.2

Inlet temperature, °C

360–370

370–374

4.2

4

Hydrogen/oil ratio, mol/mol

rate. In this case, even with a relatively high EB conversion rate and high PX/xylene ratio, the C8 aromatics loss was kept at a relatively low level, indicating that the catalyst is a very robust catalyst and can operate well in a wide range of conditions. Observations. The new generation xylene isomerization

catalyst showed a very good performance after the startup. The performance test run data confirmed that indicators such as PXate, EB-ate and C8 aromatics loss are superior to the guaranteed values. The application at ZRCC is considered as a success. With better PX/xylene ratio in the product and a higher EB conversion rate, the catalyst helped to optimize the PX adsorption unit feed while increasing PX production and lowering C8 aromatics loss. This led to a reduction in the C8 aromatics feed requirements and increased the total competitiveness of the PX complex, without any modification to the process and/or configuration of the complex. In addition, data from the long cycle operation indicate that the catalyst operated with good performance even under severe feed conditions, and it is a very robust catalyst with a good response to different operating conditions. HP BIBLIOGRAPHY Yingbin, Q., “The progress and application of catalysts for isomerization of C8 aromatics,” Engineering Science, Vol. 1, No. 1, 1999. Zhanggui, H., “Industrial application of the SKI-400C catalysts for isomerization of C8 aromatics,” Petroleum and Petrochemical Today, Vol. 35, No. 4, 2005. Yang, J. and D. Shi, “Industrial application of the SKI-400-type catalysts for isomerization of C8 aromatics,” Petroleum Refinery Engineering, Vol. 1, No. 1, 1999. 1

NOTES This catalyst is jointly developed by Zeolyst and Axens, using a proprietary carrier.

Guo Shouquan joined ZRCC in 2001 in the aromatics production and technical management department. Jenson Chua joined Zeolyst International in 2006 as a technical consultant. HYDROCARBON PROCESSING FEBRUARY 2012

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Improve diesel quality through advanced hydroprocessing New upgrading technologies help meet fuel quality specifications C. PENG, X. HUANG, T. LIU, R. ZENG, J. LIU and M. GUAN, Fushun Research Institute of Petroleum and Petrochemicals, Liaoning, China

F

luid catalytic cracking (FCC) is an essential technology for converting heavy oil to light oil in refineries around the world. Around 85% of the FCC, or catalytic, diesel produced by Chinese oil refineries is used in the production of transportation diesel. Catalytic diesel is also used in fuel oil blending and as heating oil in other countries.1 Recently, heavy, low-quality FCC feedstock has led to deterioration in the quality of FCC diesel in China. Moreover, many companies have revamped their FCC units or increased operational severity to improve gasoline quality and to produce more propylene. All of these efforts are contributing to a decline in diesel quality. The aromatic content of catalytic diesel in Chinese refineries is around 45%–80% [including large quantities of polycyclic aromatics (PCAs)2 ], with a cetane number between 20 and 35. As the diesel is high in both aromatics and sulfur, it leads to poor ignition performance in diesel engines. Tightening environmental laws are pressuring Chinese refiners to raise the quality of their products. To improve fuel quality and boost profits, researchers have developed a series of catalytic diesel hydroprocessing solutions. This article discusses a number of these technologies, which aid in the production of clean fuels that meet product quality specifications. DIFFICULTIES IN PROCESSING CATALYTIC DIESEL

In refineries, diesel fractions are produced by FCC units, atmospheric and vacuum towers, delayed cokers and hydrocrackers. Table 1 shows the characteristics and makeup of Sinopec’s diesel fraction in 2008. The proportion of catalytic diesel in Sinopec’s total diesel output in 2008 was 17.8%. Although this was a small percentage, the production from some units exceeded 30% due to differences in unit scale and feed characteristics. In 2008, catalytic diesel from Sinopec was mainly used in the production of transportation diesel, as a blending component and as industrial fuel in power plants and factories in the Guangdong and Zhejiang regions. Environmental standards at the time required diesel sulfur content to be less than 350 ppm, the cetane number to be 49+ and the PCA content to not exceed 11%. Compared to other types of diesel, Sinopec’s catalytic diesel had high sulfur, nitrogen and aromatic contents; high density; and a lower cetane number. It was also difficult to upgrade. Converting aromatics in catalytic diesel via hydroprocessing can affect the burning properties of the fuel, but it is also a key factor in boosting diesel quality. Researchers in China have developed

a series of catalytic diesel hydroprocessing technologies that help meet fuel quality requirements and have diverse characteristics to accommodate different upgrading needs. FCC DIESEL HYDROPROCESSING TECHNOLOGIES

Catalytic diesel is an important fraction of China’s commercial diesel stockpile, as it can help meet demand for transportation diesel during petroleum shortages. However, due to FCC diesel’s high aromatic content, it is difficult to considerably improve its quality, especially its burning properties. Researchers have developed a number of catalytic diesel hydroprocessing technologies to address these issues. TABLE 1. Makeup of Sinopec’s diesel fraction in 2008

Type of diesel

Production, thousand tons per year (tpy)

Proportion, wt%

Cetane number

Total aromatics, wt%

39.65

56.8

42–58

15–30

Atmospheric and vacuum diesel Coker diesel

12.74

18.2

44–51

30–50

FCC diesel

12.41

17.8

20–35

45–80

5.03

7.2

55–65

1–20

Hydrocracker diesel

TABLE 2. Results from Gaoqiao diesel hydrogenation unit Process conditions Constitute proportion of feed, %

60.8 SR diesel, 30.8 coker gasoline and diesel, 8.4 catalytic diesel

Hydrogen partial pressure in inlet, MPa

6.2

LHSV of main catalyst, h–1

2.44

Inlet H2:oil, vol%

390:1

Average reaction temperature, °C

348

Industrial application results

Feed

Hydrotreated oil

Density, g/cm–3

0.8374

–

Distillation, °C

76–381

–

9,900

280

Nitrogen, ppm

322

48

Cetane number

–

58

PCAs, %

–

6

Sulfur, ppm

HYDROCARBON PROCESSING FEBRUARY 2012

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Hydrotreating paths. In refineries where there is sufficient straight-run (SR) and coker-based diesel production, transportation-specification diesel can be processed with only hydrotreating, as needed. No adjustments are necessary for the cetane number. Researchers developed the FH-UDS hydrotreating catalyst series and ultra-desulfurization catalysts, which were successfully used in hydrogenation units. Operational requirements for the ultra-desulfurization of diesel were a liquid hourly space velocity (LHSV) of 1.5 h–1 to 2.5 h–1 and a total pressure of 6 MPa to 10 MPa. In the test, a 3-millionton-per-year (MMtpy) diesel hydrogenation unit at Sinopec’s Gaoqiao refinery processed SR diesel, coker gasoline and diesel, and FCC diesel into clean diesel with a sulfur content of less than 10 ppm and a cetane number increase of 3–5 compared to the feedstock. Results from the test are shown in Table 2. The properties of the hydrotreating process were varied. The ultra-desulfurization catalyst series demonstrated powerful

TABLE 3. Results from Guangzhou diesel hydrogenation unit Process conditions

hydrodesulfurization (HDS) ability. These catalysts produced clean diesel with a liquid yield of over 98% and sulfur content of less than 10 ppm. The catalyst series was used successfully in many units and carried a relatively low investment cost. Maximizing diesel cetane number. In the 1990s,

researchers began developing technology to maximize diesel cetane, and they successfully carried out experiments in industrial applications in 1998. The Maximum Cetane Number Improvement (MCI) technology soon saw widespread application. Based on the first generation of MCI technology, researchers developed a second generation of MCI catalysts and process technology and applied it to a 600,000-tpy diesel hydrogenation unit at Sinopec’s Guangzhou refinery in 2002. Operational conditions required for the MCI process were a total LHSV of 0.8 h–1 to 1.5 h–1 and a total pressure of 6 MPa to 12 MPa. The process upgraded catalytic diesel into clean diesel with a sulfur content of less than 10 ppm and a cetane number increase of 8–20 compared to the feed. Moreover, the diesel yield was as high as 93% to 98%. Results are shown in Table 3. TABLE 5. Results from pilot-scale FD2G test

Feed

Catalytic diesel

Hydrogen partial pressure in inlet, MPa

6.3

Process conditions

Total LHSV, h–1

1

Density, g/cm–3

0.9500

Inlet H2:oil, vol%

703:1

Distillation, °C

195–379

360

Sulfur, ppm

7,900

Average reaction temperature, °C Industrial application results

Feed

Hydrotreated oil

Nitrogen, ppm

1,109

Cetane number

< 15

Total aromatics, %

79.9

Density, g/cm–3

0.8962

0.8534

Distillation, °C

189–367

164–357

7,000

5.8

Hydrogenation products

Gasoline fraction

Diesel fraction

1.1

Yield, %

53.27

35.95

44.8

Octane number (RON)

92.4

–

10.9

Aromatics, %

53.74

–