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APRIL 2012

HPIMPACT SPECIALREPORT BONUSREPORT

PETROCHEMICALDEVELOPMENTS

Innovative chemistryand catalysts improveprofitability

Energy for economic growth

Canadian oil sands alliance

ROTATING EQUIPMENT

New seal designs enhance operationsand reliability

www.HydrocarbonProcessing.com

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Select 51 at www.HydrocarbonProcessing.com/RS

SPECIAL REPORT: PETROCHEMICAL DEVELOPMENTS

41 Optimize olefin operationsThis operating company used process models to find solutions to poor separation performanceK. Romero

47 Alternate feedstock options for petrochemicals: A roadmapNew hydrocarbons will be needed to meet future demandS. K. Ganguly, S. Sen and M. O. Garg

55 Improve catalyst management at the FCC unitSystem revamp reduces unloading time, boosts refinery operationsM. L. Sargenti, N. Ergonul, M. Scherer, H. Upadhyay, R. McClung and T. S. W. Al Rawahi

59 Operational optimization for mixed-refrigerant systemsUse rigorous simulation to improve process efficiencyJ. Zhang, Q. Xu and K. Li

67 Consider new economics for purification on a small scaleFor smaller methanol units, new designs balance energy cost against capital cost for long-term profitabilityK. Patwardhan, G. Satishbabu, S. Rajyalakshmi and P. Balaramkrishna

Cover Night view of 25,000-metric-tpy ethylene plant built in Texas circa 1948. Project awarded to The Lummus Co. (now CB&I) in 1945. Photo courtesy of CB&I.

HPIMPACT19 Energy for economic growth

20 Medium-voltage AC drives surge, thanks to energy market

22 Canadian oil sands alliance

23 Polyurethane news from Riyadh

COLUMNS9 HPINSIGHT

All hydrocarbons have a place in the global market; timing depends on economics

13 HPIN RELIABILITYPump alignment saves power

17 HPINTEGRATION STRATEGIESThe journey to supply-chain excellence in the refining and petrochemical industries

126 HPIN AUTOMATION SAFETYThe imaginary hacker

DEPARTMENTS 7 HPIN BRIEF • 25 HPINNOVATIONS 29 HPIN CONTRUCTION • 37 HPIN CONSTRUCTION PROFILE 38 HPINCONSTRUCTION BOXSCORE UPDATE 122 HPI MARKETPLACE • 125 ADVERTISER INDEX

BONUS REPORT: ROTATING EQUIPMENT

73 Use better designed turboexpanders to handle flashing fluidsNew models eliminate vibration problems and improve reliability

K. Kaupert

79 Understand multi-stage pumps and sealing options: Part 2Designing for dirty service involves many factorsL. Gooch

CATALYST 2012—SUPPLEMENT

C-84 Perspectives on the 2012 energy industryHere are several thoughts on how companies can adapt to—and profit from—the uncertain environment V. Doshi, A. Clyde and C. Click

ENVIRONMENT AND SAFETY

103 Venting vapor streams: Predicting the outcomeLaminar and turbulent jet theories provide strong support when addressing cold venting situations

R. Benintendi

109 Apply audits to reexamine safety proceduresRecognizing distinctive vulnerabilities in various refinery units S. L. Chakravorty

CLEAN FUELS

117 Methanol contamination of naphtha: A case studyCreative problem solving was used to upgrade off-spec export products while minimizing tank storageF. Ovaici


APRIL 2012 • VOL. 91 NO. 4

4 I APRIL 2012 HydrocarbonProcessing.com

EDITORIAL Editor Stephany RomanowReliability/Equipment Editor Heinz P. BlochProcess Editor Adrienne BlumeTechnical Editor Billy Thinnes

Online Editor Ben DuBoseAssociate Editor Helen MecheContributing Editor Loraine A. HuchlerContributing Editor William M. GobleContributing Editor ARC Advisory Group

MAGAZINE PRODUCTIONDirector—Production and Operations Sheryl StoneManager— Editorial Production Angela BatheArtist/Illustrator David WeeksManager—Advertising Production Cheryl Willis

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HYDROCARBON PROCESSING (ISSN 0018-8190) is published monthly by Gulf Publishing Co., 2 Greenway Plaza, Suite 1020, Houston, Texas 77046. Periodicals postage paid at Houston, Texas, and at additional mailing office. POSTMASTER: Send address changes to Hydrocarbon Processing, P.O. Box 2608, Houston, Texas 77252.

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Publisher Bill WageneckE-mail [email protected]


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HPIN BRIEFBILLY THINNES, TECHNICAL EDITOR

[email protected]

HYDROCARBON PROCESSING APRIL 2012 I 7

The international availability of massive US shale gas resources could determine the fate of global gas pric-es over the next decade, said Paolo Scaroni, CEO of Italian oil and gas major Eni. Mr. Scaroni delivered the keynote address at the annual IHS CERAWeek energy conference, held March 5–9 in downtown Houston.

Mr. Scaroni bemoaned the global differences in sales prices for “the same stupid molecule” of natural gas, citing values of less than $3/MMBtu in the US compared with about $9 in European spot markets, $11 on European oil-linked contracts and $13 in Asia. The US is an island in gas terms, he explained, noting that the nation was set for at least the next decade.

“With recoverable gas resources and stronger gas markets across the ocean, there are many who think that the US might become a major exporter over the next decade,” Mr. Scaroni said. “But this is more complex than it sounds.”

For example, it remains to be seen whether US citizens, who slowly accepted the rationale of shale gas exploration for their own energy secu-rity, would be willing to export the gas, thereby benefiting the financial position of other countries.

On the whole, global gas demand is expected to grow by 2020. But the outlook on prices is murky, because supply remains unclear, given US mar-ketplace uncertainties. As such, Mr. Scaroni said it can be difficult for com-panies to gauge the viability of large-scale gas projects.

Other key questions include the fate of nuclear power following the Japan disaster and whether gas-based fuels can gain traction within the trans-portation sector. On the other hand, growth in LNG trade should allow for at least some rebalancing in global prices. “Over the next decade, the key to the market is LNG,” Mr. Scaroni said.

In addition, the gap between US gas and oil prices should narrow, he observed. Scaroni noted that, based on calorific power, US gas trades at roughly 1⁄6 the price of oil—down from 1⁄2 in 2008. HP

—Ben DuBose

ExxonMobil plans to invest approximately $185 billion over the next five years to develop new supplies of energy to meet expected growth in demand, CEO Rex W. Tillerson said in a recent presentation at the New York Stock Exchange. “During challenging times for the global economy, ExxonMobil continues to invest to deliver the energy needed to underpin economic recovery and growth,” Mr. Tillerson told investment analysts. He said that, even with significant efficiency gains, ExxonMobil expects global energy demand to increase by 30% by 2040, compared to 2010 levels. Demand for electricity will make natural gas the fastest-growing major energy source, and oil and natural gas are expected to meet 60% of energy needs over the next three decades. To help meet that demand, ExxonMobil is anticipating an investment profile of approximately $37 billion per year through 2016. A total of 21 major oil and gas projects will begin production between 2012 and 2014, he said.

Motiva Enterprises plans to convert all of its high-sulfur diesel heating oil (2,000 ppm) storage to ultra-low-sulfur diesel (ULSD) (15 ppm) at its Sewaren terminal in New Jersey. Motiva’s conversion aims to meet its customers’ needs under a new New York state mandate that all heating oil sold in the state be no more than 15 ppm sulfur by July 1, 2012. It will also allow the Motiva Sewaren refined products ter-minal with a capacity of more than 5 million bbl, to take deliveries of ULSD for New York Mercantile Exchange-based contracts via marine and pipeline. In addition to the conversion to ULSD heating oil, Motiva is undertaking a project to convert two tanks of heating oil storage to B100 biodiesel at the Sewaren terminal. With the addition of biodiesel tankage and improved rail logistics, Motiva Sewaren will be able to supply mul-tiple blends of biodiesel to the Northeast over the truck rack, as well as via marine vessel.

Metso has acquired South Korean global valve technology and service company Valstone Controls Inc. The acquisition enables Metso to expand its offering for the oil and gas and power industries with globe valve technology that plays a key role in most critical processes with extreme pressures and temperatures, the company said. Valstone is a privately owned globe valve and service specialist com-pany. Valstone has an established customer base in Korean engineering, procurement and construction (EPC) companies and in domestic South Korean petrochemical and power-generation industries. Metso said it further plans to develop partnerships with leading South Korean engineering, procurement and construction companies.

Petronas and BASF have taken the next steps in the development of the previously announced €1 billion investment that will expand their partnership in Malaysia, involving projects at their existing venture in Kuantan and at a new site with-in Petronas’ proposed refinery and petrochemical integrated development (RAPID) complex in Pengerang, Johor. These projects are to be implemented between 2015 and 2018. Under the terms of the recently signed agreement, the partners have agreed to form a new entity (BASF, 60%; Petronas, 40%) to jointly own, develop, construct and operate production facilities for isononanol, highly reactive polyisobutylene, non-ionic surfactants, and methanesulfonic acid, as well as plants for precursor materials. These world-scale facilities will become an integral part of Petronas’ RAPID project.

Oil trading and logistics company Gunvor Group has reached an agreement to buy the 107,500-bpd refinery that insolvent Swiss oil refiner Petroplus shut down in Antwerp, Belgium. Gunvor said in a statement that it expects the deal to close in the next month. Gunvor will retain all current workers, and will operate the refinery “on a long-term basis.” The company plans to restart the refinery immediately after the deal closes in late April. Petroplus began shutting down the Antwerp refinery in late December amid mounting credit woes. The Antwerp site also has a storage capacity of more than 1.2 million cubic meters. HP

■ Postcard from CERAWeek

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HPINSIGHT


All hydrocarbons have a place in the global market; timing depends on economics

Remaining profitable continues to be a critical issue for hydro-carbon processing facilities. Balancing new technology with gov-ernment mandates is a thorny problem. Environmental issues add more cost to refined products. Changes in transportation fuels continue as vehicle manufacturers update engine designs. R&D and innovative inventors continue to find solutions to old and new challenges of the hydrocarbon processing industry (HPI).

Headlines from Hydrocarbon Processing, April 2002:

Clean fuels: Estimated $7 billion in US refining capital spending. In 1999, The Environmental Protection Agency (EPA) released Tier II sulfur mandates, as part of the Clean Fuels Program. These rules require lowering sulfur concentrations in gasoline to 30 ppm by 2006. Compliance with the low-sulfur guidelines for gasoline and diesel is deemed to be complicated. Most refiners have studied two possible options: revamping die-sel hydrotreaters or constructing new desulfurization units. A study of the 162 US refineries identified construction of 96 new desulfurization units, representing $6.6 billion in total spending.

OPEC recommends output freeze; group will meet again in June. OPEC continues to maintain its crude oil output until the global economy and/or demand improves. The group also hopes to improve crude oil contributions from non-OPEC producers.

Controversy swirls around renewable fuel standard. The American Petroleum Institute (API) and the Renewable Fuels Association (RFA) have joined forces against pending legisla-tion to ban methyl tertiary butyl ether (MTBE) and to create a renewable fuel standard. The new mandate would require use of approximately 5 billion gallons of ethanol in gasoline before 2012. By providing liability protection to ethanol but not for MTBE, refiners will have significant incentives to abandon MTBE blending before the four-year ban takes effect.


Crude oil to remain ‘inexpensive’ for two years, said the renowned energy economist, P. K. Verleger. “OPEC cut nearly 2 million bpd of production to attain a $21/bbl minimum refer-ence set in July 1990. However, curtailment won’t hold prices at current levels,” Verleger said.

‘City diesel’ curtails emissions. Year-long trials are underway in Helsinki, Finland, with a new “diesel fuel” that promises to cut both sulfur and particulate emissions from public transport vehicles. “City diesel” was developed by Neste Oil, based on surveys with engine manufacturers. The new diesel has a low–sulfur content (0.005 wt% as compared to 0.1 wt% to 0.2 wt% of present diesel) and is also less aromatic.

Synthetic rubber demand on the rise. Recovery in the global synthetic rubber (SR) market is anticipated. Worldwide con-sumption of SR and natural rubber will increase over the next five years (1991–1996) to 15.8 million tons, thus having an aver-age annual 2.1% demand growth rate. All geographical regions should experience new growth. However, demand in Central Europe and the Commonwealth of Independent States (CIS) is expected to decline 17% over the same period.

OSHA issues final rule for chemicals PSM. The US Occupa-tional Safety and Health Administration (OSHA) issued a final rule entitled, Process Safety Management of Highly Hazardous Chemicals in the Federal Register on Feb. 24, 1992. This rule requires employers to manage hazards associated with processes using materials identified as highly hazardous. It will affect any industry that produces, uses, stores, transports or handles any of these materials in amounts equal to or greater than the specified quantity. As part of the rule, employers must compile written process safety information, conduct hazard analyses, develop and implement written operating procedures, train employees on the written procedures, and more. Twelve criteria are included under the new rule.


LPG emerging as the motor fuel for fleet vehicles. Once again, motor vehicles powered with liquefied petroleum gas (LPG) are under consideration, especially for fleet applications. Industry statistics indicate that more than 500,000 vehicles per year will be converted to propane during the 1980s. Most of the converted LPG vehicles will be part of municipal fleets, such as police cars and other emergency vehicles.

Get jet fuel from shale oil in single step? Amoco Oil’s new experimental catalyst moved closer to the reality of converting shale oil into aviation fuel.

Operations at Marathon Oil Co.’s 200,000-bpd Garyville, Louisiana, refinery are automatically and remotely controlled from four control centers. This main process control center oversees all process operations electronically. It is linked by radio and telephone to other centers monitoring and controlling the boiler area, tank farm and water treatment facilities. Hydrocarbon Processing.

HPINSIGHT


Synfuels viability boils down to economics. A coal gasification plant’s product would have to net $17/MMBtu in 1988 (as com-pared to $100/bbl of crude oil). At present, the most expensive category of natural gas is about $9/MMBtu. Capital cost for a synfuels facility is another huge factor; construction costs for coal gasification units continue to rise. The present oil glut, temporary or not, is another factor.

Natural gas price decontrol? Decontrol of the US natural gas (NG) market remains a controversial subject. As a major con-sumer, the US chemical industry remains vulnerable to NG supply shortages. Shortfalls are attributed to inadequate incentives under the Natural Gas Policy Act (NGPA), passed in 1978. NGPA has contributed to significant disruption in the NG market.


Heavy-oil cracking process developed. Kellogg International and Phillips Petroleum have developed a new heavy-oil cracking (HOC) process that can convert residuals from the atmospheric or vacuum towers directly into high-octane gasoline. The Kellogg-Phillips HOC Process disposes of high-sulfur residuals by extend-ing the feedstock range for fluid catalytic cracking. The first unit was constructed at Phillips’ Borger, Texas, refinery, and it has an operating capacity of 25,000 bpd.

Anti-pollution control will cost billions by 1976. Over the next four years, petrochemical/chemical companies will invest $1.43 billion on capital equipment alone for environmental projects. Total estimated costs for water, air and solid-waste pollution-control projects will bump $12.7 billion by 1976.

Lead drops, but US octane holds up. Despite a drop in the average lead content, the octane of regular and premium gasoline at US service stations remains at a high level. Octane levels were maintained by altering the proportions of fuel additives, and by incorporating new blending methods, to compensate for the lower lead content. In 1972, lead content in gasoline dropped from 2.43 g/gal to 2.22g/gal.

New desulfurization process available. Chisso Engineering of Japan has developed a new desulfurization process that can com-pete with conventional hydrogenation processes. The new process uses water at 250°C to melt and extract undesirable compounds from petroleum at a fifth of the cost of other methods.

Takahax process recovers sulfur dioxide directly from gases with very low hydrogen sulfide (H2S) content. The process was originally developed in Japan. Nissan Engineering has constructed 40 units, and has issued an exclusive license to Ford, Bacon & Davis to design and construct Takahax units in the Western Hemisphere. The process uses a caustic solution with an oxidation-reduction catalyst to remove nearly 100% of the H2S.

Alaska pipeline seems far off—and expensive. The Alyeska Pipeline Service Co. says the cost of the pipeline from Prudhoe Bay to Valdez would be about $3 billion. Putting this pipeline through Canada would double construction costs. There is still no (US) government approval on the construction project, but the approval is expected no later than mid-June (1972).

To see more headlines from 1962 to 1922, visit HydrocarbonProcessing.com.

Construction continues for the largest catalytic cracking and gas recovery unit, with 63,000 bpd of crude oil capacity. The cracker was designed and built by The M.W. Kellogg Co. for Gulf Oil’s Philadelphia refinery. Petroleum Refiner, 1954.

The new 360-ft tall Houdriflow cat cracker dwarfs the fixed-bed catalytic refining units at Sun Oil’s Marcus Hook, refinery. The new 18,000-bpd Houdriformer will increase the refinery’s capacity to produce high-quality gasoline. Petroleum Refiner, 1955.

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HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR

HPIN RELIABILITY

[email protected]


Awareness of energy efficiency is one of the minimum job qualifications for reliability engineers. In the summer of 1994, Jack Lambley, then an intern at the Imperial Chemical Industries (ICI) Rock-savage site in the UK, was assigned the task of quantifying the effects on power consumption for misaligned process pumps. A surplus pump was overhauled, and new bearings were fitted. This pump was reinstalled, and water was recircu-lated in a suitably instrumented closed-loop arrangement. Prueftechnik GmbH loaned Lambley a modern laser-optic alignment instrument.

Background. As an undergraduate student, Lambley had learned how mis-alignment affected bearing load, and how bearing load increases caused exponential decreases in bearing service life. Following instructions from his supervisor, Lambley reviewed the engineering sections of SKF’s general catalog, which stated that a 25% increase in bearing load caused the rated bearing life to be halved.

Lambley investigated the alignment accuracy and the methods in use at that time. He discovered that straight-edge methods were inappropriate for refinery pumps. Rim-and-face alignment methods

were judged difficult and unreliable. Prop-erly executed, reverse-dial-indicator meth-ods required consideration of the bracket sag, and they would require more time to apply than modern laser techniques.

From data available at the Rocksavage site, he calculated that the typical misalign-ment consisted of 0.02 in./0.5 mm vertical and horizontal offset and 0.002 in./in. verti-cal and horizontal angularity. In 1994, lasers were known to be inherently more accurate than the best competing techniques.

Proof. Lambley constructed several graphs and tabulations, as shown in Figs

Pump alignment saves power

00

2

4

6

8

10 20 30 40Horizontal offset, thousandth

Pow

er c

onsu

mpt

ion,

%

Accuracy +/– 3% of valueSource: ICI

50 60 70

Effect of parallel offset on power consumption of a pin coupling at 3,000 rpm.

FIG. 1

0 5 10 15 200

2

4

6

8

10

Gap, thou./in.

Pow

er c

onsu

mpt

ion,

%


Effect of angular misalignment on power consumption of a pin coupling at 3,000 rpm.

FIG. 2

0 10 20 30 40 50 6001

2

3

4

5

6

7

8

9

Horizontal offset, thousandthPo

wer

con

sum

ptio

n, %


Effect of parallel offset on power consumption of a toroidal (tire-type) coupling at 3,000 rpm.

FIG. 3

0 5 10 15 20 25 30 350

1

2

3

4

5

6

Gap, thou./in.

Pow

er c

onsu

mpt

ion,

%


Effect of angular misalignment on power consumption of a toroidal (tire-type) coupling at 3,000 rpm.

FIG. 4

HPIN RELIABILITY

14

1–4. The resulting recommendations were to align machinery to within 0.005 in./0.12 mm shaft offsets and to limit deviations in the hub gap to 0.0005 in./in. of hub diameter. Lambley further doc-umented that adhering to these recom-mendations would reduce ICI’s power con-sumption by about 1%. He confirmed that laser alignment was faster and superbly more accurate. Lambley determined that laser alignment technology was bottom-line more cost-effective; he deserves credit

for establishing these facts instead of repeating the opinions of others.

Using data from a mid-size refinery:Average demand: 27 kW/pump �

8,760 hr/yr � $0.1/kWh � 1,000 pumps � 0.01 = $236,520/yr. And, with 1,000 pumps operating at any given time, this location could annually save approximately $250,000 in avoided power consumption.

Total cost. The total cost for laser alignment instruments includes equip-

ment costs plus training costs. The ben-efit is 8 man-hours of time-saving credit per alignment job. For gathering more data, thermography and infrared moni-toring techniques are possible options. These methods have been used to quan-tify significant temperature increases in a coupling located between misaligned pump and driver shafts. You could com-pare the energy wasted by the rising temperature of a coupling to the energy loss, as described by Lambley. Regardless of calculation method, laser alignment will result in surprisingly rapid payback. Remember: In all reliability improve-ment endeavors, never let somebody’s opinion get in the way of sound science and facts.

Knowledge update. If you are like the majority of hydrocarbon process-ing industry facilities in the industrial-ized world, your worker and technician resources are probably stretched to the limit. Understandably, you may be look-ing for ways to simplify some of your tra-ditional work processes and procedures. You may have had an experience that rein-forces the contention in which high-tech tools are not always the answer. And hold the view that the back-to-basics thinking has considerable merit. However, decades of well-documented observation attest to the fact that misalignment has been responsible for huge economic losses. The more misalignment of the rotating unit permitted, the greater the rate of wear, likelihood of premature failure, and loss of efficiency of the machine.

As an inquisitive Lambley proved, mis-aligned machines absorb more energy than they consume more power. So, it’s always advantageous to update one’s knowledge of shaft alignment and alignment toler-ances. Competent vendors will assist you in illuminating the roadway to becoming reliability-focused. And indications are that only the reliability-focused facilities will be around in the future. HP

The author is Hydrocarbon Processing’s Reliability/Equipment Editor. A practicing consulting engineer with now 50 years of applicable experience, he advises process plants worldwide on failure analysis, reliability improvement and maintenance cost avoidance top-ics. He has authored or co-authored 18 textbooks on machinery reliability improvement and over 490 papers or articles dealing with related subjects. For more on alignment, refer to Bloch, H. P., Pump Wisdom: Problem Solving for Operators and Specialists, John Wiley & Sons, Hoboken, 2011, pp. 153–162.


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HPINTEGRATION STRATEGIES


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PETER REYNOLDS, CONTRIBUTING EDITOR

The journey to supply-chain excellence in the refining and petrochemical industries

In downstream refining and marketing, the handoff between manufacturing operations and product distribution and market-ing is often performed in a sub-optimal manner. Most process manufacturing companies claim supply chain as a core compe-tency, yet many still attempt to manage the workflow from end to end. In many cases, the production operations and supply-chain groups operate in silos. Refinery production groups typically make superb products, using the manufacturing assets available to them. However, since the logistics and supply-chain groups in refining and petrochemical businesses usually handle product distribu-tion and sales independently from production, their journey to supply-chain excellence clearly lags behind many other industries.

With this understanding, leaders in process manufacturing periodically peer into other industries—such as discrete manu-facturing and specialty chemicals—to learn ways to improve supply-chain operational excellence. When they do, they often learn that manufacturers must look at the entire supply chain through multiple lenses and develop business processes based on industry standards, best practices and appropriate use of technol-ogy. All often offer opportunities to streamline business opera-tions. In the downstream refining and petrochemicals industry, one of the last levers left to improve profitability, is to streamline the liquids supply chain.

It’s often difficult to attain clear visibility into liquid-product inventories due to inefficient or disconnected business processes and technologies across primary and secondary distribution. Ter-minal inventories are not reconciled in a timely fashion because businesses often don’t have the time to deal with spreadsheets and complex IT applications.

Organizations implement supply-chain improvement projects routinely, but with sub-optimal overall benefit. Successful IT proj-ects for supply-chain integration need the business leaders to get involved early in the project definition. However, these leaders are usually busy running various marketing, distribution and trading activities, and they seldom have adequate staff to support IT proj-ects. Many business end users use a host of manual business pro-cesses that involve e-mail, Microsoft Excel and hard-copy reports to manage the complicated supply chains in the process industries.

Enter the Supply Chain Council. In 1996, the Supply Chain Council (SCC) was formed to create and evolve an indus-try-standard process reference model to help companies improve supply-chain operations. The SCC created the Supply Chain Operations Reference (SCOR) model; now companies can evalu-ate and compare overall supply-chain activities and evaluate their own performance.

The SCC is made up of over 800 members from worldwide organizations. Owner-operators—such as Shell, DuPont, Irving Oil, ExxonMobil and Chevron—comprise 40% of the mem-bership. North American and European companies comprise

approximately 70% of the total membership. Most manufacturers reported that the supply chain accounts for 60% to 90% of the total company costs, while oil companies like ConocoPhillips and Chevron disclosed spending 90% and 88%, respectively.

The SCOR model and framework. As the industry-stan-dard supply chain business process reference model, the SCOR contains over 200 high-level business processes; 550 supply-chain metrics; and 200 skills classifications, including risk manage-ment. The SCOR reference model includes five key management process categories of activity. These provide a framework to link suppliers, enterprise supply chains and customers. The SCOR model is arranged with the fundamental business processes of plan, source, make and deliver.

SCOR project toolkit. Initially, executing a supply-chain project looks like a traditional project in which teams are devel-oped, roles and responsibilities are aligned, and the standard project charter is written. With the SCOR model, the competitive SCORcard benchmark and analysis are introduced at an early stage. SCOR metrics included in the benchmark are reliability, responsiveness, agility, costs and assets. This process allows com-panies to determine a supply-chain strategy and to analyze current performance against competitors.

The SCOR project toolkit includes a number of tools that have been used successfully to define a long-range plan to fix a supply chain. Process mapping tools, like Aris, can be used in addition to external benchmarking, logical and geographical maps, and defect analysis tools. The SCOR model has several hundred best practices that are easily identifiable with a given business process.

Organizations must execute IT projects in the correct order. People, business process and technology are fully intertwined. At the beginning of a project, it may be good practice to envision the technology that will transform an organization’s supply chain. But technology cannot be implemented successfully on broken business processes. Successful manufacturing companies look to similar manufacturing companies and adapt standards when they exist. These companies use the SCOR model to support tech-nology procurement activities and the requirement documents that are released to IT suppliers for bidding. The SCOR project provides a proven methodology to transform the supply chain. It includes the tools to define, analyze and benchmark supply-chain performance and to choose the right supply-chain projects. HP

The author has more than 19 years of professional experience in process control, advanced automation applications, information technology, enterprise and supply chain in the downstream oil refining and petroleum product marketing industry. Prior to joining ARC in 2011, Mr. Reynolds served as the strategic planning manager for automation and IT at Irving Oil in Saint John, New Brunswick, Canada. Irving Oil operates Canada’s largest refinery.

The Emerson logo is a trademark and a service mark of Emerson Electric Co. © 2011 Emerson Electric Co. D351992X012 MX11 (H:)

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YOU CAN DO THAT


HPIMPACTBILLY THINNES, TECHNICAL EDITOR

[email protected]


Energy for economic growth

Having proved resilient throughout the recent recession compared to other sectors, the energy industry has the potential to be a key engine of economic growth and recov-ery, according to a new study by IHS CERA and the World Economic Forum. The report provides a framework for understanding the larger economic role of the energy industry at a time when issues of employment and investment are so critical in a troubled global economy, its authors said.

The report examines the industry’s role as a driver of investment and job creation, as well as energy’s importance as the key input for most goods and services in the econ-omy. Fig. 1 shows the energy sector’s share of business-sector gross domestic product (GDP) along with other industries in sev-eral Organization for Economic Coopera-tion and Development (OECD) countries.

“The energy industry is unique in its economic importance,” said Daniel Yergin, IHS CERA chairman. “The energy sector has the potential to be a tremendous eco-nomic catalyst and source of innovation

in its own right, while it simultaneously produces the very lifeblood that drives the broader economy.”

The energy industry—by nature, capi-tal intensive and requiring high levels of investment—has the ability to generate outsized contributions to GDP growth, the study says. In the US, the oil and gas extraction sector grew at a rate of 4.5% in 2011 compared to an overall GDP growth rate of 1.7%.

The highly skilled technical nature of energy industry jobs is reflected in compen-sation levels. As a result, employees of the energy industry contribute more absolute spending per capita to the economy than the average worker, and contribute a larger share of GDP per worker than most indus-tries, the study says.

The energy industry’s most important immediate source of economic potential is its high “employment multiplier effect,” which is a result of its extensive supply chain and relatively high worker pay. Every direct job created in the oil, natural gas and related industries in the US generates three or more indirect and induced jobs across the economy, the study says. For further

illumination, Fig. 2 shows energy sector employment when compared to other industries in select OECD countries.

In the US, this places oil and gas ahead of the financial, telecommunications, soft-ware and non-residential construction sec-tors in terms of the additional employment associated with each direct worker.

“We always suspected that energy had a vital role to play in the economic recovery,” said Roberto Bocca, senior director and head of energy industries at the World Eco-nomic Forum. “But we were still surprised when the data uncovered the magnitude of the sector’s multiplier effects.”

Energy prices. As the key input for most goods and services in the economy, lower energy prices reduce expenses for consum-ers and businesses and increase the dispos-able income available to be spent elsewhere. Many countries, such as China, India and South Korea, are increasingly focusing on renewable energy sources as potential growth sectors for their economies, the report said.

Developed countries are also investing in renewables in an effort to meet sustainability goals and emerge at the forefront of this

Germany

Mexico

Norway

South Korea

United Kingdom

United States

Percent0 5 10

10.421.2

5.9

4.5

2.8

3.5

8.5

3.224.4

8.8

6.522.3

2.5

11.819.1

28

6.318.2

15 20 25 30

Energy-relatedindustries

Manufacturing Health andsocial work

Source: IHS CERA and OECD Structural Analysis Database.Note: Data are 10-year averages of the most recent data available:2000–2009 for the United States, 1993–2002 for Norway, and 1994–2003 for all other countries.

Share of business-sector GDP and energy compared to other industries.

FIG. 1

Source: IHS CERA and OECD Structural Analysis Database.Note: Data are 10-year averages of the most recent data available:2000–2009 for the United States, 1993–2002 for Norway and1994–2003 for all other countries.

Energy-relatedindustries

Manufacturing Health andsocial work

Germany

Mexico

Norway

South Korea

United Kingdom

United States

Percent0 5 10 15 20 25 30

16.918

1.2

0.9

2.6

0.6

18.6

2.711.9

0.8

9.522.1

1.4

14.32.3

27.8

11.115.7

Share of business-sector employment and energy compared to other industries.

FIG. 2

HPIMPACT

20

growing sector. However, the higher costs of these technologies create tradeoffs that must be considered, the study said.

“One must look at energy’s contribution to the overall economy, not just its direct contribution,” said Samantha Gross, IHS CERA director of integrated research. “Max-imizing direct jobs in the energy sector may not be the right goal if it reduces efficiency and increases energy prices to the detriment of the economy’s overall productivity.”

The study also examines the role of policy in maximizing the economic benefits of energy production, promot-ing steady and reasonable energy prices through stable tax and fiscal schemes, and encouraging of industrial diversifi-cation through cluster development. It points to the challenge for a resource-rich country to transform oil and gas earnings into the foundations of a wider, more diversified economy.

Medium-voltage AC drives surge, thanks to energy market

While large project orders helped main-tain the market size of medium-voltage AC drives in 2009, it also resulted in low growth in 2010 compared to other auto-mation product markets. However, 2010 was still not a disappointing year for the medium-voltage AC drives market. The market expected to experience higher growth in 2011 compared to sluggish growth in 2010, according to an ARC Advisory Group study.

The impact of the extraordinary amount of policy stimulus in 2009 boded well for the high-power AC drives market in 2009 and 2010. Monetary policy had been highly expansionary, with interest rates down to record lows in most advanced, and in many emerging, economies.

“Growth in power and automation solutions for all regions of the world [was seen continuing] in 2011 and beyond, with increasing market demand for building new—and upgrading existing—power infra-structure and improving industrial efficiency and productivity,” according to Himanshu Shah, the principal author of ARC’s study.

Demand from emerging markets. While demand in mature markets for auto-mation solutions and AC drives is expected to improve, emerging markets will remain significant drivers of growth as they build up their electrical power-generation capac-ity and expand industrial production with a major focus on improving energy effi-ciency and industrial process quality. These dynamics directly impact market growth for medium-voltage AC drives. Demand for commodities fueled by the economic growth of emerging countries and the need to become more globally competitive in product quality is also expected to propel demand for industrial automation solu-tions and medium-voltage AC drives in the emerging markets.

Infrastructure investment. Glo-balization has created a growing demand for modern infrastructures, especially in emerging economies. Major investments are underway, and more are being planned for airport facilities, railway and public transportation expansions, and new road construction. These projects are driving demand for products from the metals and mining, cement and glass, and oil and gas

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HPIMPACT

22

industries. Emerging economies know that their current infrastructures are a major bottleneck for their continuing economic growth. Medium-voltage AC drives are one of the critical components for these infra-structure investments, and they are used extensively in these industries.

In spite of the unpredictable economic conditions of some countries in Europe, the globalization environment is expected to resume over the next forecast period.

The beginnings of a modest recovery in the global economy would present an excellent backdrop for medium-voltage AC drives’ market growth.

While every region will experience growth in the medium-voltage AC drives market over the forecast period, there are significantly different factors affecting each market. A brief description regarding the economic scenarios for each region is cov-ered in the report.

Canadian oil sands alliance

Canadian oil sands producers have formed a new alliance named Canada’s Oil Sands Innovation Alliance (COSIA), seeking to accelerate the pace of improving environmental performance in Canada’s oil sands. Companies involved in the alliance include BP, Canadian Natural Resources, Cenovus Energy, ConocoPhillips, Devon, Imperial Oil, Nexen, Shell, Statoil Canada, Suncor Energy, Teck Resources and Total.

CEOs from those companies signed the alliance’s founding charter, committing to COSIA’s vision to “enable responsible and sustainable growth of Canada’s oil sands while delivering accelerated improvement in environmental performance through col-laborative action and innovation.”

The creation of COSIA as an indepen-dent alliance builds on work done over the past several years by both oil sands industry members and research and development organizations, the group said. COSIA plans to take these efforts to a much larger scale and seeks to help the industry address envi-ronmental challenges by breaking down barriers in the areas of funding, intellectual property enforcement, and human resources that may otherwise impede progress.

“The public’s expectation of environ-mental performance in the oil sands contin-ues to evolve; we want to meet those expecta-tions, and we’ll work collaboratively to do so, building on previous successes,” said John C. Abbott, executive vice president of heavy oil for Shell Canada. “Coming together today to sign the charter is a significant and impor-tant step for all our companies and marks a pivotal point for our industry.”

COSIA also announced Dr. Dan Wicklum as CEO of the new alliance. Dr. Wicklum has a background in environ-mental science and was selected following a national search. The organization said that his scientific qualifications and leader-ship experience position him well to lead COSIA, a science-based alliance focused on environmental technology and innovation.

“I am confident COSIA will greatly accelerate innovation and environmental performance in priority areas that Cana-dians care most about,” Dr. Wicklum said. “Today is just the beginning, and I am excited to be part of this new alliance. We understand we have a lot of work to do, and we are looking forward to working with our stakeholders and reporting on our progress along the way.”


HPIMPACT

COSIA will establish structures and processes through which oil sands pro-ducers and other stakeholders can work together for the benefit of the environ-ment. The alliance will identify, develop and apply solutions-oriented innovations around the most pressing oil sands envi-ronmental challenges (specifically water, land, greenhouse gases and tailings), and will communicate COSIA’s efforts and suc-cesses in addressing those challenges.

Jean-Michel Gires, CEO of Total E&P Canada, said that COSIA creates a new dynamic for the oil sands industry, promot-ing new approaches for intellectual property management of environmental technology and better working relationships with uni-versities, research agencies, technology pro-viders, regulators and oil sands stakeholders in the communities where industry operates.

“COSIA is a reflection of how the oil sands have evolved into a global resource, with companies committing to fostering continuous innovation and the develop-ment of new environmental solutions,” Mr. Gires said. “We have seen what can be achieved when we work together and multi-ply our ideas and efforts. For example, work done by the Oil Sands Leadership Initiative and the Oil Sands Tailings Consortium is already delivering technology that promises to reduce our environmental footprint.”

Companies participating in COSIA will contribute at varying levels to the alliance, based on their own areas of expertise, offi-cials said. COSIA will rely on the input of scientists and engineers from within the ranks of the member companies, as well as leading thinkers from government, aca-demia and the wider public.

Polyurethane news from Riyadh

Saudi Basic Industries Corp. (SABIC) has signed a toluene di-isocyanate (TDI) and methylene di-phenyl isocyanate (MDI)

technology license agreement with Mitsui Chemicals, under which Mitsui will provide manufacturing technology for producing TDI and MDI. TDI and MDI are each raw materials for producing polyurethane. The agreement also provides for joint technology development in TDI/MDI, officials said. The official signing ceremony (Fig. 3) took place at SABIC headquarters in Riyadh, Saudi Arabia, and featured Mohamed Al-Mady, SABIC vice chairman and chief exec-utive officer, and Toshikazu Tanaka, Mitsui Chemicals president and CEO.

Mr. Al-Mady said that the partnership would spearhead a strategic collaboration between the two companies to explore future possibilities to collaborate in the polyurethane business. “The agreement will spur our strategic business plan to penetrate the global polyurethane market, as well as to power the ambition and com-petitive advantage of our customers for the long term,” he said. “It will also enable a fast development of polyurethane applica-tion industries in Saudi Arabia, especially with regard to thermal insulation, which will contribute to employment creation in addition to energy savings.”

Mr. Al-Mady pointed out that Mit-sui Chemicals has lengthy experience as a manufacturer of TDI and MDI and has developed pioneering manufacturing pro-cesses. “Through this technology license agreement, we will strengthen our prod-uct capabilities with high-quality TDI and MDI, and expand into the polyurethane business,” he said.

“For Mitsui Chemicals, this license agreement will be the largest and most extensive one we have ever made,” Mr. Tanaka said. “We will support this project full force on every front and are commit-ted to its success. I hope that it will be just the first step in a future business partner-ship with SABIC, which may include the establishment of a strategic supply base for competitive TDI/MDI.” HP

Executives from SABIC and Mitsui Chemicals ink a deal in Riyadh, Saudi Arabia. FIG. 3

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HPINNOVATIONS


SELECTED BY HYDROCARBON PROCESSING EDITORS

[email protected]

Vessel monitoring system uses thermal cameras

The Critical Vessel Monitoring Sys-tem from Land Instruments International Ltd., a unit of AMETEK Inc., uses indus-trial-strength thermal-imaging cameras to provide higher measurement density than traditional systems based on ther-mocouples. The system measures surface temperature once every 16 cm2, as com-pared with one measurement every 250 cm2 in thermocouple systems. Each cam-era records over 110,000 individual mea-surements, ensuring that even the smallest degradation can be detected.

By measuring temperatures in more loca-tions, the system allows for earlier detection of refractory wear or breakdown. Measure-ments from all cameras are reported using graphical software that signals an alarm if a potential breakout is detected. The software also compiles temperature trends to sup-port statistical analysis of refractory wear. An integrated web interface allows for the visualization of current vessel conditions from all plant locations.

The system is optimized for use in gasifiers and other critical vessels in pet-rochemical production, power genera-tion, chemical and coal processing, waste management, and fertilizer and plastics production. Benefits include greater pro-tection against catastrophic vessel failure and extension of refractory lifetime based on actual data.Select 1 at www.HydrocarbonProcessing.com/RS

New catalyst produces high-performance polymers

Dow Chemical Co.’s CONSISTA C601 polypropylene catalyst, which is included in its Ziegler Natta catalyst family, is a non-phthalate-based catalyst system for the production of high-performance polymers. The system requires no capital or upgrades to existing facilities, and accommodates drop-in technology for Dow’s UNIPOL Polypropylene Process Technology.

CONSISTA C601 Catalyst was imple-mented in production trials at Slovnaft Petrochemicals in Bratislava, Slovakia. There, the catalyst was used to produce homopolymer and high melt flow impact copolymers. CONSISTA C601 Catalyst

demonstrated high yield and the capability to make a broad range of products with a non-phthalate-based catalyst system.

Andrej Horak, polypropylene plant manager for Slovnaft Petrochemicals, noted that the trials confirmed expectations for improved product properties, and resulted in “… lower production costs ensured by 40% higher catalyst yield compared to our current system.” Slovnaft Petrochemicals plans to install the CONSISTA C601 cata-lyst system for its entire production portfolio in the near future, enabling it to meet future REACH (Registration, Evaluation and Authorization of Chemicals) requirements.

Additionally, in a separate trial of CON-SISTA C601, the catalyst demonstrated excellent operability and process perfor-mance with homopolymer production, using a standard operation protocol, thereby validating the “drop-in” technology concept.Select 2 at www.HydrocarbonProcessing.com/RS

Pump shaft seal listed as Shell best practice

Shell Global Solutions has listed IHC Lagersmit’s LIQUIDYNE water-lubricated pump shaft seal as best practice for use with its cooling water pumps worldwide. The seal is also included in Shell’s Technically Accepted Manufacturers and Products (TAMAP) list.

The LIQUIDYNE seal was originally developed for dredging pumps and has been adapted to fit cooling water pumps.

Since the condition of the heavily rein-forced seal can be determined at any time, it offers significant reliability and above-average mean time between maintenance (MTBM) for cooling water pumps. The high MTBM improves grip on the pump-ing process and prevents both unnecessary maintenance and sudden pump failure, thereby reducing maintenance costs.Select 3 at www.HydrocarbonProcessing.com/RS

Wireless network solution links remote field sites

The Wireless Network Module (WNM) from Moore Industries is an accurate and reliable solution for sending process signals between remote field sites. The bidirectional WNM provides a low-cost wireless commu-nications link between field sites that are in rugged or impassable terrain, with a single unit transmitting for up to 30 miles. The unit can also act as a repeater for a virtually unlimited transmission range.

The WNM uses Spread Spectrum Fre-quency Hopping technology to avoid inter-

As HP editors, we hear about new products, patents, software, processes and services 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.

This vessel monitoring software shows the exact locations of imaging cameras.FIG. 1


HPINNOVATIONS

ference problems caused by crowded radio spectrums. This technology allows multiple radio networks to use the same band while in close proximity. The WNM does not require a regulatory license, and it typically can be installed without performing costly radio frequency site surveys.

The WNM is ideal for use with Moore Industries’ NCS NET Concentrator Sys-tem, as well as with other supervisory con-trol and data acquisition (SCADA) and distributed input/output systems. WNM models are available for data communica-tions networks that use Ethernet and serial (RS-485) communications.Select 4 at www.HydrocarbonProcessing.com/RS

Clean CCS process replaces ‘coal-mining’ steps

Refineries with delayed coker technol-ogy and open-pit or pad solids handling resemble a coal-mining operation. How-ever, engineering firm TRIPLAN AG’s Closed Coke Slurry (CCS) system offers a modern, state-of-the-art delayed coking process with sound economic incentives and low emissions. The CCS technology significantly improves overall plant reli-ability and reduces costs.

The CCS system is technically a closed system, improving mechanical, environ-mental and worker hygiene compared to an open-pit or pad system. All coke-handling steps—from coke drum outlet to discharge of dry coke to load-out, and the separa-tion and disposal of coke fines—have been converted from solids handling into one smooth, swift step.

CCS technology enables a reduction in cycle time of up to four hours, allow-ing for greater feed processing and clean products output. Also, improvements in the metallurgy have made the CCS process very stable, unlike the pit and pad designs. The instrumentation allows for fully con-trolled operation, and it enables the con-sole operator to view a complete status of the process at any time.

The typical payout time for a CCS sys-tem is one and a half years to two years (for a two-drum unit processing 1,000 tons of coke per day), as long as down-

stream modifications do not dilute the economics. Since each delayed coker and overall refinery configuration are different, careful investigation and review of the site are recommended before the installation of the CCS system.Select 5 at www.HydrocarbonProcessing.com/RS

Linde buys Choren’s Carbo-V technology

Linde Engineering Dresden GmbH recently acquired the Carbo-V multistage biomass gasification technology of the insolvent Choren Industries GmbH, for an undisclosed sum. Linde plans to offer the technology for commercial projects in the future.

During the Carbo-V technology’s first process stage, the biomass reacting in a low-temperature gasifier (LTG) is con-verted to biocoke and carbonization gas. The second process stage comprises the partial oxidation of the carbonization gas that takes place in a high-temperature gas-ifier (HTG), and, during the third process stage, the biocoke is blown into the hot gas stream of the HTG. After adequate pre-conditioning, the synthesis gas produced may be subsequently processed into “green” products; e.g., second-generation biodiesel.Select 6 at www.HydrocarbonProcessing.com/RS

Detector tube and slide card monitor gas pipeline humidity

The combination of Gastec’s direct-read water vapor detector tube No. 6LP and Methanol Correction Slide Card helps simplify quality assurance for humidity control in natural gas pipelines. Offered by Nextteq, the 6LP tube allows for quick and accurate detection of water vapor con-centrations with a measuring range of 3 pounds per million cubic foot (lb/MMcf) to 100 lb/MMcf. The tube is designed to measure the maximum acceptable water vapor concentration of 7 lb/MMcf set by most gas distributors.

If methanol is present in natural gas, it can interfere with water vapor measure-ments and require extra analysis and cal-culations to determine the correct water vapor level. For a precise methanol mea-surement, Nextteq offers the Methanol Correction Slide Card, which provides an on-the-spot correction factor. The slide card, for use with Gastec Gas Detector Tube No. 6LP (water vapor) and No. 111L (methanol), expedites the analysis and reduces the risk of miscalculations.Select 7 at www.HydrocarbonProcessing.com/RS

The water-lubricated pump seal extends mean time between maintenance.

FIG. 3

Example:Cycle time (actual) = 19 hrCycle time (target) = 17 hrExpected profit up to €32 MM/y when changing from pit to CCS system

Two-drum coker, 250 ton/hr of fresh feedUplift = €100/ton of fresh feed €25,000/yOne turnaround/y = 800 hrRun length of CCS = 8,000 hr = 100% pit = 7,600 hr = 95%

024

23

22

21

20

19

18

17

16

15

14

13

7,600 hr/year (yr)

Pitregion

17

18

19

21

22

23

24

20

CCSregion

8,000 hr/yr = 100%

10 20 30Earnings, €MM/y

Cycl

e tim

e, h

ours

(hr)

40 505 15 25 35 45 55 60

Attractive economics are achievable with the CCS system.FIG. 2

HPINNOVATIONS

27

Epoxy coating fights steel corrosion offshore

Sherwin-Williams recently launched a high-build, hazardous air pollutant (HAP)-free epoxy coating formulated for application to marginally prepared and damp surfaces in marine and offshore applications. The coat-ing, Macropoxy 80, combats steel corrosion caused by immersion in saltwater and fresh-water, as well as by atmospheric exposures.

A modified phenalkamine epoxy with high surface tolerance, Macropoxy 80 is recommended for use in coastal areas, salt-water and freshwater immersion, bilges and wet void areas, water and wastewater tanks, underwater hulls, and decks and super-structures. It can also be used as an anti-cor-rosive primer in an underwater hull system with anti-fouling coatings. The coating’s high solids formulation (80%) reduces the likelihood of solvent entrapment, which can lead to premature coating failure.

In addition to being HAP free, Macro-poxy 80 is low in volatile organic compounds (VOCs) (< 250 grams/liter) and is available in a standard hardener for applications between 40°F and 120°F (4°C and 49°C) or a low-temperature hardener for applications between 0°F and 77°F (−18°C and 25°C).Select 8 at www.HydrocarbonProcessing.com/RS

Dräger unveils new industrial breathing apparatus line

Two new National Institute for Occu-pational Safety and Health (NIOSH)-approved units, the Dräger PSS 3000 and Dräger PAS Lite, are designed to protect workers, increase plant productivity and reduce cost of ownership.

Dräger Safety AG & Co.’s PSS 3000 self-contained breathing apparatus (SCBA) is designed for use in plant maintenance, plant and operational safety, and emer-gency response in the petrochemical, oil and gas industries, as well as in other industrial applications. The PAS Lite unit, which offers both SCBA and airline options, is designed for use in industrial applications where a simple, easy-to-use breathing apparatus is required.

The harnesses used in both systems are five times more durable than those made of traditional materials. The PSS 3000 unit uses fire-retardant ethylene-vinyl acetate, while the PAS Lite system uses styrene-butadiene rubber-coated webbing, making them both less permeable to liquids and almost 100% inert to chemicals, thereby reducing the time and effort required to clean and maintain the units.Select 9 at www.HydrocarbonProcessing.com/RS

The Dräger PSS 3000 breathing apparatus is more durable than traditional equipment.

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HPIN CONSTRUCTIONHELEN MECHE, ASSOCIATE EDITOR

[email protected]

North AmericaBoardwalk Pipeline Partners, L.P.

has selected Exterran to design, manu-facture and construct a natural gas-pro-cessing plant in South Texas. The project includes engineering, procurement and construction (EPC) of a cryogenic gas-processing plant with a capacity of 150 million scfd of natural gas produced from the Eagle Ford shale.

It is expected that the equipment designed, fabricated and installed by Exter-ran will be capable of achieving up to 93% ethane extraction.

Clean Energy Fuels Corp. has signed a 10-year agreement with Green Energy Oilfield Services to build, supply and maintain a new liquefied natural gas (LNG) fueling station at Green Energy’s headquarters in Fairfield, Texas.

The LNG fueling station will fuel Green Energy’s new fleet of 60 LNG-powered heavy-duty Peterbilt trucks, which will sup-port Green Energy’s oil production custom-ers within a 100-mile radius of Fairfield, in the Freestone oil region of Central Texas. The trucks are anticipated to use approxi-mately 1.2 million gpy of LNG.

The new Green Energy Fairfield LNG station’s development is set to begin in August 2012, with completion scheduled by the end of 2012. Green Energy’s future plans include development of additional LNG truck-fueling stations in the Barnett (Fort Worth), Haynesville (Marshall), and Eagle Ford shale (Laredo) petroleum-pro-ducing areas of Texas.

Fluor Corp. has an engineering, pro-curement and construction management (EPCM) contract from Joule Unlimited, Inc., to design and build a biofuels demon-stration facility in New Mexico.

The facility is intended to scale up a pilot process to produce liquid fuels via Joule’s novel technology, which uses sun-light to convert proprietary organisms and carbon dioxide into liquid hydrocarbons and ethanol.

Fluor’s Greenville, South Carolina office is leading the EPCM services proj-ect. Engineering, procurement and site mobilization is underway.

Freeport LNG Expansion, L.P. and a joint venture comprising Zachry Indus-trial, Inc. and CB&I Inc. have a front-end engineering and design (FEED) contract for the engineering and design of the Freeport Liquefaction Project near Freeport, Texas. Under the FEED contract, the Zachry/CB&I joint venture will engineer and design three LNG liquefaction trains (each rated at 4.4 million tpy) and corresponding pretreatment facilities to be located near the existing Freeport LNG Regasification Terminal, which is owned and operated by Freeport LNG’s parent company, Freeport LNG Development, L.P.

Within the three-train design, the Zachry/CB&I joint venture will develop a fixed-price/fixed-schedule proposal for both a one-train initial develop-ment and a two-train initial develop-ment. This optionally enables Freeport LNG to choose the optimum size of the initial phase of the project based upon customer demand and financing con-siderations. In addition, the three-train project’s design will allow for expansion of additional liquefaction trains and pre-treatment facilities after the initial devel-opment has commenced.

MDU Resources Group, Inc. , through its wholly owned subsidiary, WBI Holdings, Inc., and Calumet Refining, LLC, an entity owned by the existing owners of the general partner of Calumet Specialty Products Partners, L.P., have signed a nonbinding letter of intent to explore the feasibility of jointly building and operating a 20,000-bpd diesel refinery in southwestern North Dakota. The facil-ity would process Bakken crude and mar-ket the diesel within the Bakken region.

Site selection, permitting, crude-oil feed procurement, marketing and engineering studies are underway. Upon successful completion of the project, Calumet Refin-ing, LLC expects to contribute its interest in the joint venture to Calumet Specialty Products Partners, L.P., in exchange for cash and/or partnership interests.

Air Liquide Large Industries U.S. LP has started up a new air-separation unit (ASU) at its facility in Geismar, Louisiana.

The Geismar facility supplies nitrogen, oxygen and argon to customers in a range of industries, including refining, natural gas, chemicals, metals and many others.

The new ASU began commercial production in October 2011, producing high-purity oxygen, nitrogen and argon. It is one of three at Air Liquide’s facility in Geismar. The first ASU became opera-tional in October of 1999, and the second in February of 2000.

Formosa Plastics Corp. will be invest-ing more than $1.7 billion in capital equipment and construction at its Point Comfort, Texas, site. This investment will increase the security and flexibility of the company’s raw and intermediate mate-rial supplies, as well as the reliability and breadth of the company’s products.

The investment consists of a new, grassroots 800,000-metric-tpy olefins cracker, an associated 600,000-metric-tpy propane dehydrogenation (PDH) unit and a new 300,000-metric-tpy low-den-sity polyethylene (LDPE) resin plant. The olefins cracker will take advantage of the increasingly reliable and low-cost domestic natural gas and supply feedstock both to existing production units and to the new LDPE unit. The PDH unit will produce additional propylene, increasing opera-tional flexibility. The addition of the coun-

Trend analysis forecastingHydrocarbon Processing maintains an

extensive database of historical HPI proj-ect information. The Boxscore Database is a 35-year compilation of projects by type, oper-ating company, licensor, engineering/construc-tor, location, etc. Many companies use the his-torical 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 77252-2608713-525-4626 • [email protected]

HPIN CONSTRUCTION

30

try’s newest LDPE resin plant will comple-ment the company’s existing product line of Formolene polyethylene (PE) and poly-propylene (PP), and Formolon polyvinyl chloride (PVC) and specialty PVC.

EuropeCB&I’s Lummus Technology busi-

ness sector has been awarded two separate contracts by a client in Russia. The com-bined value of the contracts is approxi-

mately $120 million. The first contract was awarded in the fourth quarter of 2011 and the second was awarded in January 2012. The work scope includes detailed design, engineering and material supply for numerous heaters for a refinery-mod-ernization project.

Sibur and Reliance Industries Ltd. (RIL) have formed a joint venture (JV) named Reliance Sibur Elastomers Pri-

vate Ltd. to produce 100,000 tpy of butyl rubber in Jamnagar, India. Reliance’s share in the JV will total 74.9%, while Sibur will account for 25.1%. The JV will invest $450 million to build the facility, which is expected to be commissioned by the middle of 2014.

The company has also signed a tech-nology license agreement facilitating Reliance Sibur Elastomers Private Ltd.’s use of Sibur’s proprietary butyl-rubber production technology at the new facility. Sibur will develop the facility’s basic engi-neering design and also train the JV’s per-sonnel at its production site in Togliatti, Russia. The JV will reportedly be the first manufacturer of butyl rubber in India and the fourth largest supplier of butyl rubber in the world.

KBR has been awarded a contract by

the TAIF Group to provide licensing and engineering services for the Veba Combi Cracker (VCC) to be implemented at the Nizhnikamsk refinery in the Republic of Tatarstan, Russia.

Under contract terms, KBR will pro-vide the license, basic-engineering pack-age and other services for TAIF’s VCC-based Deep-Conversion Complex. The complex will process 2.7 million tpy of refinery vacuum residues and 1.6 million tpy of distillates into high-value petro-chemical feedstocks and Euro 5 diesel. This award marks the third VCC license and KBR’s largest VCC project award since the acquisition of the rights to the technology in January 2010.

ITT Corp. has an enterprise framework agreement with Shell Global Solutions in which ITT’s Goulds Pumps brand will pro-vide American Petroleum Institute (API) centrifugal pumps to support Shell opera-tions worldwide.

Under the agreement, Goulds Pumps will supply these pumps in several configu-rations to Shell operations and affiliates worldwide.The agreement is for five years with an option for an additional five years. Shell applied a comprehensive process in selecting ITT Goulds Pumps, and this agreement includes the development of common specifications, terms and condi-tions, as well as pricing.

ZAO Far East Petrochemical Co. (FEPCO), which is implementing OJSC NK Rosneft’s project for the construction of a petrochemical complex in the Pri-

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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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HPIN CONSTRUCTION

32

morsk region of Russia, has selected Axens’ AlphaButol and AlphaHexol technologies for producing high-purity linear alpha-olefins. It is foreseen that the AlphaButol and AlphaHexol units, with a cumulative linear alpha-olefins capacity of 50,000 tpy, will be included into this complex.

AlphaButol will supply high-purity 1-Butene by ethylene dimerization, while AlphaHexol will produce high-purity 1-Hexene by ethylene trimeriza-

tion. Based on homogeneous catalysis and associated low-investment cost, both technologies are designed and optimized to ensure a flexible and reliable source of high-quality co-monomers for down-stream polyolefin applications.

A subsidiary of Foster Wheeler AG’s Global Engineering and Construc-tion Group has a contract from a sub-sidiary of JSC LUKOIL for the supply

of a waste-heat boiler for the LUKOIL Nizhegorodnefteorgsintez refinery, Nizhny Novgorod, Russia.

The waste-heat boiler will be installed downstream of a fluid catalytic-cracking unit, producing gasoline to meet European Union Euro-5 standards.

Foster Wheeler’s scope of work is sched-uled to be completed by March 2013.

Middle EastSiemens Industry Automation

Division is providing Abu Dhabi Oil Refining Co. (TAKREER) with a Zim-pro wet-air oxidation (WAO) system to treat refinery spent caustic as part of TAKREER’s refinery expansion in Ruwais, Abu Dhabi, UAE. The WAO system will treat odorous sulfides and pro-duce biodegradable effluent for discharge to the facility’s effluent-treatment plant. The expansion project is scheduled to be complete by late 2013.

The refinery expansion project will increase crude-oil refining capacity by 417,000 bpd, using the latest advanced technology for downstream processing units to produce higher-quality products and to comply with UAE and interna-tional environmental standards. The Zim-pro WAO system will be part of the new downstream units.

Subsidiaries of Foster Wheeler AG’s Global Engineering and Construction Group have been awarded an engineer-ing, procurement and construction man-agement (EPCM) contract by Aramco Overseas Co., B.V. (AOC), a subsidiary of Saudi Aramco, and Dow Europe Holding B.V., for a propylene-oxide (PO) unit at Jubail Industrial City, King-dom of Saudi Arabia.

This unit will be part of a world-scale, fully integrated chemicals complex, one of the largest of its kind in the world, which will be constructed, owned and operated by Sadara Chemical Co., a joint venture between Saudi Aramco and Dow. This contract has been awarded as an extension to the front-end engineering design (FEED) contract awarded to Foster Wheeler by AOC and Dow in 2008.

The world-scale unit is expected to be completed during the first quarter of 2015.

Saudi Basic Industries Corp. (SABIC) has signed a TDI and MDI technology license agreement with Mitsui Chemi-cals, Inc., in keeping with the company’s

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At Dresser-Rand, we know any unscheduled interruption of a client’s downstream operation is simply unacceptable. That’s why we make engineering reliability a primary focus. From one of the world’s largest hydrogen compressors (pictured at right) to our single-stage steam turbines, Dresser-Rand downstream solutions are easy to maintain. But for us, it’s not just about selling superior products, it’s about providing peace of mind as well. So, when you do need help, rest assured we’re there for you.

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HPIN CONSTRUCTION

34

strategic plan to be a global leader in poly-urethane (PU) and serve its customers with value-added services, solutions and products. Under the agreement, Mitsui will provide manufacturing technology for producing TDI and MDI, which are both raw materials for producing PU. The agreement also provides for joint technol-ogy development in TDI/MDI.

Mohamed Al-Mady, SABIC vice chair-man and CEO, pointed out that Mitsui

Chemicals has a long experience as a man-ufacturer of TDI and MDI, and has, over the years, developed pioneering manufac-turing processes. “Through this technol-ogy license agreement, we will strengthen our product capabilities with high-quality TDI and MDI and expand into the poly-urethane business,” he said.

Toshikazu Tanaka, Mitsui Chemicals president and CEO, commented, “For Mitsui Chemicals, this license agreement

will be the largest and most extensive one we have ever made. We will support this project full force on every front and are committed to its success. I hope that it will be just the first step in a future busi-ness partnership with SABIC, which may include the establishment of a strategic supply base for competitive TDI/MDI.”

Asia PacificThe Shaw Group Inc. has a contract

to provide the technology license and process design package for the revamp of Star Petroleum Refining Co.’s residue fluid catalytic-cracking (RFCC) unit in Map Ta Phut, Thailand. The design will upgrade the 40,800-bpd RFCC unit by incorporating the latest advances in reac-tor-system technology.

Shaw jointly developed the proprietary RFCC technology through an alliance with Axens and Total that began in the early 1990s. To date, Shaw and Axens have licensed 51 grassroots units and performed more than 200 revamp projects.

Sumitomo Chemical held a ground-breaking ceremony for its new solution-styrene-butadiene rubber (S-SBR) man-ufacturing plant to be constructed in Merbau area, Jurong Island, Singapore, by its group company Sumitomo Chemi-cal Asia PTE LTD. In November 2010, the company decided to construct the new 40,000-tpy S-SBR plant in Singa-pore because of its geographical advan-tage in supplying rapidly growing Asian markets, and stable procurement of the raw material butadiene, as well as tie-ups with Sumitomo Chemical Group’s existing businesses in the region.

Construction work commenced in January 2012, and the facility is scheduled for completion in June 2013. Commer-cial operations are planned to begin during the fourth quarter of 2013. The company, expecting further demand growth, is work-ing on a plan to build an additional plant to increase production.

Sumitomo Chemical’s S-SBR is man-ufactured by its proprietary production process technology. With its advanced polymer-modification technology, it is a key to achieving higher product per-formance. The company continues to enhance its S-SBR business globally through increased production with the new plant in Singapore and future expan-sions, along with its existing 10,000-tpy plant in Japan.

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HPIN CONSTRUCTION

35

By selling a new hydrogen-generation plant to Indonesia (the fourth plant sold to Asia in 2011), Caloric has reportedly further boosted its market position and proven its strength. Once again, a major chemical company has chosen Caloric´s know-how and reliability.

The plant’s design capacity is 1,000 Nm3/h of hydrogen. The steam-reform-ing process will be initially started with natural gas as feedstock, but it is also prepared to run with liquefied petro-leum gas (LPG). CO-Shift reaction and pressure-swing adsorption complete the process and ensure the highest purity of 99.9999% hydrogen.

Caloric will pre-assemble and test the plant at its workshop, and will also super-vise on the plant’s erection site, commis-sioning and startup.

INEOS Technologies has licensed its Innovene PP process to Zhong Tian He Chuang Energy Co., Ltd. Located in Ordos City, Inner Mongolia Autono-mous Region, the 350-kiloton/yr plant will manufacture a full line of polypro-pylene resins, including homopolymers, random copolymers and impact copo-lymers. It will serve the rapidly growing Chinese PP markets.

Zhong Tian He Chuang is a joint ven-ture between Sinopec and China Coal Energy Group Co., Ltd. The final selec-tion of Innovene PP in their Methanol-To-Olefin Complex demonstrates a grow-ing appreciation for Innovene PP in the Chinese coal industry.

Jacobs Engineering Group Inc. is executing four contracts from Arkema France for basic-engineering services to support the provision of Arkema’s propri-etary suspension and emulsion technology to four of its clients in China. Arkema’s technology is being used in four new poly-vinyl chloride (PVC) production plants in Hefei, Golmud, Etuoke Banner and Wu Lan Cha Bu, People’s Republic of China. Jacobs’ PVC technology experts in its office in Leiden, The Netherlands, and Arkema’s PVC technology team based in Lyon, France, are at present performing the basic engineering work.

Arkema’s PVC technology is reportedly one of the most efficient in the world. As planned, the four new projects in China will bring the total production capacity of facilities using Arkema PVC licenses to more than 4 million tpy.

Saudi Aramco Asia Company Ltd. (SAAC), a subsidiary of Saudi Aramco, and PT Pertamina (Persero) have signed a memorandum of understanding (MOU) to jointly evaluate the economic feasibil-ity of building an integrated refining and petrochemical project in Tuban, East Java, Republic of Indonesia.

The project represents an opportu-nity for Saudi Aramco to partner with Pertamina, and to capitalize on invest-ment opportunities in Indonesia’s grow-ing downstream industry. Additionally, it extends the close cooperation between Saudi Aramco and Pertamina, and increases prospects for industrialization and economic diversification in Indonesia.

Following the signing of the MOU, a project team will work on the proj-ect’s next phase, which will include a joint scoping study comprising market research, configuration studies and eco-nomic analysis.

Chiyoda Corp., as joint venture leader, jointly with Saipem S.p.A, has been awarded a contract for front-end

engineering design (FEED) and early works for the PETRONAS Liquefied Natural Gas (LNG) Train 9 Project in Bintulu Sarawak, Malaysia, under the dual-FEED scheme envisaged by PETRONAS.

The project is intended to add a new ninth LNG train with a capacity of 3.6 million tpy to the existing LNG production complex at Bintulu. The feed gas for this Train 9 comes from various offshore gas fields developed by PETRONAS.

Startup is set for the fourth quarter of 2015. To attain this scheduled tar-get, PETRONAS adopted a dual-FEED scheme, wherein two contractors are con-tracted to compete in the FEED design and EPC price proposal as a whole. The Chiyoda/Saipem joint venture was selected as one of the contractors for this task. Chiyoda and Saipem concluded a cooperation agreement to develop onshore LNG and upstream projects in 2011. Project execution will be developed by an integrated team at Saipem’s office in Milan, Italy. HP




BEN DUBOSE, ONLINE EDITOR

[email protected]

HPIN CONSTRUCTION PROFILE

Methanex targets US for relocation of capacityMethanex plans to move at least one

methanol plant from Chile to the US, seeking to capitalize on a trend of low natural gas prices and possible interest in gasoline alternatives.

For now, the Canada-based company hopes to relocate one of its four methanol plants in Punta Arenas, Chile (Figs. 1 and 2), to a new US Gulf site in Geismar, Louisiana.

The individual Chile plants have capaci-ties of between 800,000 tpy and 975,000 tpy of methanol. At least two are currently idled amid insufficient gas supply.

Project specifics. The move is expected to cost about $400 million and be com-pleted by the second half of 2014.

Methanex purchased the 225-acre land in Geismar and awarded Jacobs Engineering Group with an engineering services contract.

“The outlook for low North American natural gas prices makes Louisiana an attrac-tive location in which to produce methanol,” said Methanex CEO Bruce Aitken (Fig. 3).

“It is also a large methanol-consuming region, possesses world-class infrastructure, skilled workers and is a positive environ-ment in which to do business.

“We have a number of parallel work paths ongoing and expect to make a final

investment decision on this project in the third quarter of [2012].”

Further moves possible. Those paths could include multiple plants being shifted to Louisiana. Aitken said that the Geismar site “has space for multiple plants, so we will consider future expansion”.

Charles Neivert, analyst at investment bank Dahlman Rose, said in a research note that Methanex is likely preparing the Geis-mar site to accommodate a second plant from Chile.

“The advantages of this option are that the timeframe may be the shortest, the gas is most available, and the Louisiana site has available room for the unit,” Mr. Neivert said.

Demand is growing for methanol in the US, but the nation remains a net importer after production shutdowns during the recent recession.

US shale boom sparks interest. Recent shale gas discoveries, however, have made natural gas feedstocks available and affordable.

Last year, Egypt-based Orascom Con-struction Industries acquired an idled 750,000 tpy methanol plant in Beaumont, Texas, formerly run by Eastman Chemical.

It plans to restart production in the first half of 2012.

Methanol in transportation fuels mix. Rising US prices for crude-based gasoline could also play a role.

Tom Ridge, former Secretary of Home-land Security, argued in a February edi-torial in The New York Times that the nation should produce more cars to run on methanol.

“Consumers should have a choice in the cost and type of fuel their vehicles require,” Mr. Ridge wrote.

It would cost about $3 to travel the same distance on methanol as on a gallon of gaso-line, according to the Methanol Institute.

If such a scenario materializes, US-based plants like the one in Geismar would be in prime position to reap benefits.

“This project represents a unique opportunity in the industry to add capacity at a lower capital cost and in about half the time of a new greenfield methanol plant,” said Mr. Aitken.

“The timing of this project is excellent. There is strong demand growth for metha-nol globally and there is little new produc-tion capacity being added to the industry over the next several years.” HP

Methanol can be produced from four plants at the Punta Arenas, Chile, site. Photo courtesy of Google Earth.

FIG. 2

The Methanex methanol complex in Punta Arenas, Chile.

FIG. 1

Bruce Aitken, Methanex president and CEO.

FIG. 3


HPI CONSTRUCTION BOXSCORE UPDATE Company City Project Ex Capacity Unit Cost Status Yr Cmpl Licensor Engineering Constructor

AFRICAAlgeria Sonatrach Arzew LNG Liquefaction Plant 4.7 m-tpy 2400 U 2012 Saipem|Chiyoda Snamprogetti Angola Angola LNG Ltd Soyo LNG Storage 5.2 MMtpy 4000 U 2012 ConocoPhillips Bechtel|Saipem|KJT BechtelNigeria Nigeria LNG Ltd Bonny Island LNG (7) 8.5 MMtpy U 2012 Technip|FW|JGC|KBR Chiyoda|Snamprogetti Nigeria Nigeria LNG Ltd Bonny Island LNG (8) 8 MMtpy U 2012 Chiyoda|TSKJ Nigeria Chevron Nigeria\ Escravos GTL (2) EX 17 Mbpd U 2012 Haldor Topsøe JGC|KBR KBR|JGC Nigerian Natl Pet Corp Chevron|Saso Snamprogetti SnamprogettiNigeria Chevron Nigeria\ Escravos GTL (3) Mbpd P 2012 Haldor Topsøe JGC|KBR JGC|KBR Nigerian Natl Pet Corp Chevron |Sasol Snamprogetti SnamprogettiRepub S Africa PetroSA Coega Refinery 400 Mbpd 10500 F 2016 KBR Uganda Undefined Hoima Refinery 200 bpd 2000 P 2015 FW

ASIA/PACIFIC China Dalian West Pacific Petrochem Dalian Wet Sulfuric Acid (WSA) 30 Mtpd U 2012 Haldor Topsøe China Henan Jinkai Chemical Group Henan Wet Sulfuric Acid (WSA) 122 m-tpd U 2012 Haldor Topsøe China Zhong Tian He Chuang Energy Co. Ltd. Ordos Methanol-to-Olefins (MTO) 350 kty U INEOS China Sinopec Xinjiang Refinery EX 200 bpd 8.41 P 2015 India Mangalore Rfg & Petrochemicals Mangalore Refinery EX 9.69 MMtpy 2400 U 2012 EIL|Toyo Japan EIL EILIndonesia SAAC/Persero Tuban Refinery 300 bpd S Indonesia Caloric Undisclosed Hydrogen Generation 1000 Nm3/h U

EUROPE Ireland Conoco Phillips Co Cork Wet Sulfuric Acid (WSA) 30 m-tpd U 2012 Haldor Topsøe Russian Federation TAIF NK Tatarstan Cracker 2.7 m-tpy U KBR KBR Scotland Shell UK Ltd\Esso E & P Mossmorran Natural Gas Plant RE None E 2014 Wood Group Scotland Shell UK Ltd\Esso E & P St Fergus Gas Plant RE None E 2014 Wood Group

LATIN AMERICA Brazil Petr Brasileiro SA Pernambuco Refinery TO 230 bpd 12000 U 2014 Brazil Petrobras Rio de Janeiro Petrochemical Complex 165 bpd U 2013 Mexico Pemex Tula, Miguel Hidalgo Refinery Amine Regeneration Unit None 800 E 2013 Saipem Peru CF Industries Inc San Juan de Marcona Ammonia 2.6 Mtpy 2000 U 2013 Haldor Topsøe Technip Peru Petroperu Talara Wet Sulfuric Acid (WSA) 460 t/a E 2015 Haldor Topsøe

MIDDLE EAST Qatar QP/QAPCO Ras Laffan Ethylene 1.4 m-tpy 5000 P 2018 Saudi Arabia Sadara Chemical Co. Al Jubail Petrochemical Complex TO t/a 15000 F 2015 FW Saudi Arabia Sadara Chemical Co. Jubail Ind City Propylene Oxide None F 2015 FW

UNITED STATES North Dakota WBI Holdings/Calumet Refining Undisclosed Diesel 20 bpd S Texas Boardwalk Pipeline Partners, LP Eagle Ford Shale Natural Gas Plant 150 MMcfd 180 U 2013 ExterranTexas Zachry Freeport LNG 4.4 Mtpy F 2013 CB&I Texas DCP Midstream Glasscock Co Natural Gas Plant EX 75 MMcfd P 2013 Texas Valero Refining Co Port Arthur Desalter (2) RE 260 Mbpd U 2013 Cameron

FOR A FREE 2-WEEK TRIAL,contact Lee Nichols at +1 (713) 525-4626or [email protected].

www.ConstructionBoxscore.com

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PETROCHEMICAL DEVELOPMENTS SPECIALREPORT


Optimize olefin operationsThis operating company used process models to find solutions to poor separation performance

K. ROMERO, Pequiven S. A., Ana Maria Campos Complex, Venezuela

B ulk petrochemical manufacturing is a highly competitive global industry. When margins are tight, manufacturers seek ways to optimize performance and to reduce costs

while maximizing yields and revenue. Optimization options include alternative feeds, plant/process revamps and improved operations to achieve better separation and yields to lower energy consumption, to minimize product loss and to decrease maintenance costs.

Case history. Pequiven is a leading petrochemical company based in Venezuela. Its products include fertilizers (ammonia and urea), chlor-alkali, methanol, methyl tertiary butyl ether (MTBE), aromatics, olefins (ethylene and propylene) and other plastics.

Fig. 1 shows Pequiven’s Ana Maria Campos petrochemicals complex, Venezuela. This facility began operating in 1976, and it was expanded in 1992. This petrochemical complex has two olefin plants with a combined capacity of 635,000 metric tpy of ethylene and up to 250,000 metric tpy of propylene for 100% propane feed and uses ethane and propane as feedstocks.

Propane/propylene splitter study. The olefin plant’s performance had deteriorated. The conditions resulted in sig-nificant propylene losses, higher energy consumption and rising maintenance costs. To improve performance, Pequiven needed a better understanding of process problems and a list of possible cost-effective solutions. Pequiven elected to simulate targeted sections of the olefin plant. Results from the models would provide more insight into the root causes of the poor operat-ing performance. This article discusses the simulation study for the propane/propylene splitters. The study focused on the conceptual design and “what-if ” analyses for various revamp options. Using the study results, Pequiven selected the best option to optimize the distillation columns.

Pequiven olefin process. The Olefins I Plant at the Ana Maria Campos Complex was designed to produce 250,000 metric tpy of ethylene and 120,000 metric tpy of propylene, using feedstocks rang-ing from 100% propane to a mixed feed of 30% propane and 70% ethane. Fig. 2 is the process flow diagram of the Olefins I plant. The site processing operations are:

• Pyrolysis. This plant uses three sets of furnaces. The furnace effluent is first

quenched and then cooled to condense the dilution steam, oils and polymers. All are removed by a circulating water system.

• Process-gas compression. The process stream is compressed and cooled to separate ethylene and propylene (principal products) from other byproducts and unconverted feed. Five compression stages are used, with acetylene conversion, caustic scrubbing and gas-drying occurring between the fourth and fifth stages. The pro-cess gas from the fifth-stage discharge filters is chilled in three stages using refrigerants and a hydrogen/tail-gas stream from the process.

• Separation. The cryogenically chilled stream is processed through a series of distillation columns. Several columns are needed to separate out the desired products. This process sec-tion consists of a demethanizer, ethane/ethylene and propane/propylene splitters, and a debutanizer, as shown in Fig. 3.

Feedstocks

Pyrolysis

Ethylene

Propylene

Ethane

PropaneEffluentwater

scrubbing

Chillingsection

Acetyleneconversion

Caustic andwater wash

Process gasdrying

Ethane/propane recycle

Splittingsection

Process gascompression

stages

I II III IV V

Process flow diagram of Olefins I plant.FIG. 2

Pequiven’s Ana Maria Campos petrochemical complex.FIG. 1

PETROCHEMICAL DEVELOPMENTSSPECIALREPORT


This study focused on revamping the propane/propylene (C3) splitters to maximize recovery of propane and propylene with greater efficiency and reduced losses. Fig. 4 shows an in-depth description of the C3 splitter section.

The deethanizer bottoms stream (at approximately 21.3 kg/cm2g and 62°C) is split into parallel C3 splitter systems—primary and secondary trains. Each parallel train consists of two splitter columns. The feed is distributed between the two systems. The primary C3 splitter train receives 60% of the propane feed flow.

The primary train has 277 trays between the first column (124 trays) and second column (153 trays). Both columns use multi-downcomer trays. Feed enters the first column above tray

35 (tray 188 for the combined column) for the propane case, or above tray 51 (tray 204 for the combined column) in the mixed-feed case. The secondary train is configured and oper-ated similarly to the first train with a total of 198 trays between the first column (88 trays) and the second column (110 trays). The secondary system has sieve trays. The feed enters the first column on tray 26 (tray 136 for the combined column) for the propane case or on tray 36 (tray 146 for the combined column) for the mixed-feed case.

The C3 splitter system was designed to produce 99.6 mol% of propylene in the overhead stream. The bottom stream from the C3 section is sent to the debutanizer column where the top prod-uct, containing propane and butane, is recycled to the pyrolysis furnaces. The heavier components are recovered as a C5

+ pyrolysis gasoline stream. In the mixed-feed case, there are fewer heavier components to recover.

Plant operating problems. During 2005–2009, the pro-pane/propylene system experienced several problems. Gradually, the facility operating performance worsened. Performance issues included:

• High propylene loss, 25 mol% vs. design < 1 mol%• Poor separation and high energy usage of the C3 splitters• Fouling in the splitter reboilers

TABLE 1. Results from the Revamp Proposal A simulation modeling study

Column C (from secondary Primary propane/ system) depropanizer propylene splitter1

Feed flowrate, metric tph 16.98 14.16

Stages 88 277

Feed stream stage 36 171

Distillate rate, metric tph 14.16 6.9

Mol purity propylene, top 0.484 0.998

Mol purity propane, top 0.513 0.001

Bottom rate, metric tph 2.8 7.3

Mol purity propane, bottom 0.0007 0.992

Top pressure, bar 18.9 18.9

Reflux rate, metric tph 22.7 146

Reboiler duty, MW 2.9 12.3

TABLE 2. Results from the Revamp Proposal B simulation modeling study

Column D (from secondary Primary propane/ system) depropanizer propylene splitter1

Feed flowrate, metric tph 16.9 14.2

Stages 88 277






Mol purity propane, bottom 0.0007 0.992


Reflux rate, metric tph 22 146


Chillingsection

Compressedgas

Separators

DemethanizerMethane

Propane,propylene

and heaviercomponents

Propane and butane

Propaneand heaviercomponents

Propylene

Ethane and ethylene

Ethane

Ethylene

Deethanizer

Debutanizer

C2 splitter

C3 splitter section(2 trains each

with 2 columns)C5

+/pygas

Separation section of the Olefins I plant.FIG. 3

C3/C3=/C4

+

deethanizerbottoms

C5+

Propaneand C4

+

Debutanizer

Propylene

Propane and butaneto pyrolysis furnaces

Propylene

Secondary splittersystem

Primary splittersystem

Propane/propylene splitter section of the existing unit.FIG. 4



• Low propylene and propane recovery, problems with the overhead-product purity and high concentration of unsaturates in the recycle propane to the pyrolysis furnaces.

These problems resulted in significant propylene loss that cumulatively amounted to more than 70,000 metric tons over five years. The lost products were valued at over $75 million. Fouling of reboilers due to using oily water as the hot utility, and coking of the transfer line exchangers from higher propylene content in recycle propane, contributed to higher maintenance costs.

Process simulation study. The objectives of the modeling were to:

• Understand the root causes for these problems• Develop suitable and cost-effective solutions• Provide ongoing guidance for troubleshooting• Improve unit performance.The simulation model was constructed from design data from

the operating manuals and engineering drawings, as shown in Fig. 5. This model was tuned and validated against other data sets. This tuning included comparing different thermodynamic methods and selecting the best with respect to accuracy. The Peng-Robinson (PR) and Soave-Redlich-Kwong (SRK) models were used to describe thermodynamic behavior and equilibrium coefficients. Both methods are commonly used for hydrocarbon systems. For the Olefins I plant, Peng-Robinson provided an accurate fit with the design cases.

Several commercially available simulation programs were used to simulate the C3 splitters while also considering the existing col-umn geometries and tray efficiencies. This distillation model is a core element. It helped predict column performance and ensured

robust initialization and convergence. The rate-based algorithm also significantly improved the model’s accuracy compared to the equi-librium-based and first-generation rate-based distillation models.

Simulation results—such as column pressure, operating tem-perature, reflux ratio, composition, reboiler/condenser duties, column stages, feedrate, overhead and bottoms yield, and tray details—were specified to achieve 99.6% propylene recovery. Propane/propylene (principal products), isobutane, butanes, butenes and heavier components (traces) were also considered in this model. Once the model was tuned, it was used to study a series of conceptual design alternatives, including energy and economic analysis for the different proposals.

Revamp Proposals A and B. The first two options (A and B) were similar. They both involved reconfiguration and using one of the columns in the secondary splitter system as a depropanizer, while taking the other column out of service, as shown in Fig. 6. The simulation model showed that this approach would improve propane/propylene recovery and increase the recycle propane to the pyrolysis furnaces. Proposal A studied using the first column as the depropanizer, and Proposal B looked at using the second col-umn for this purpose. Tables 1 and 2 summarize the study results.

Findings for Proposals A and B. The operating condi-tions for Proposals A and B are similar to the original design. A

TABLE 3. Results from the Revamp Proposal C simulation modeling study

Secondary propane/propylene Primary propane- splitter (depropanizer) propylene splitter1

Feed flowrate, metric tph 17 14.4

Stages 198 277






Mol purity propane, bottom 0 0.996


Reflux rate, metric tph 23 182


TABLE 4. Results from the revamp proposal D simulation modeling study*

Primary Secondary propane/propylene propane/ propylene system LP steam system LP steam1

Required temperature, °C 128.7 128.7

Required pressure, bar 2.75 2.75

Propylene recovery composition 0.9985 0.9985

Required flowrate, metric tph 24,366 19,035

Total cost, $ million/yr 1.41 1.102

*Based on the original design with propylene losses of less than 1%

Simulation model of the propane/propylene splitter system.

FIG. 5

C3/C3=/C4

+

deethanizerbottoms

C3/C3=

C5+

C4+

Debutanizer

Depropanizer

Butane to pyrolysis furnaces

Propane topyrolysis furnaces

Propylene


RevampProposalsA and B


Proposals A and B: Use one column in the secondary C3splitter as a depropanizer.

FIG. 6



depropanizer in the C3 splitter system does increase propane and propylene recovery (about 99 mol%). Heating requirements are significantly reduced—15.2 MW vs. 22.8 MW from the original design. Jet flooding is 0.65 (well below the maximum jet flooding limit of 0.85). There is no evidence of overloading in the multi-downcomer trays, in spite of the high reflux rate requirements.3

Revamp Proposal C. This option considered using the entire secondary C3 splitter system (both columns) as a depropanizer, as shown in Fig. 7. The objectives were to improve propane and propylene recovery and to increase recycle propane to the pyrolysis furnaces. Table 3 summarizes results from this processing option.

Findings for Proposal C. The operating conditions are similar to the original design. A depropanizer in the C3 splitter system increases propane and propylene recovery (about 99.8 mol%). Additional heating is required—60.9 MW vs. 22.8 MW specified in the original design. The risk of jet flooding in multi-down-comer trays in the primary system was identified. Due to tray overloading, this process option was not pursued further.

Revamp Proposal D. This option evaluated replacing oily water with low-pressure (LP) steam as the heating medium in the

C3 splitter reboilers. The change could reduce fouling on tube surfaces, as shown in Fig. 8. The conceptual design and analysis are based on revamping the original design for the most limiting conditions, as represented by the 100% propane feed case.2 Table 4 lists the study results.

Annual steam costs are estimated at $1.41 million and $1.102 million, respectively, for the primary and secondary systems. The total steam consumption across the C3 splitter system is approxi-mately $2.51 million/yr.

Revamp Proposal D project costs. Option D not only addresses exchanger tube-side fouling and maintenance, but it also reduces propylene losses in the splitter bottoms. This will improve propylene recovery from the product and propane for recycle. The economics for this case were evaluated in detail. Table 5 summarizes cost estimates and project economics.

The total capital investment is estimated at $3.025 million, with an annual steam utility cost of $2.51 million as reported ear-lier. These process improvements are expected to result in 8,915 metric tpy of incremental propylene production. At $1,080/met-ric ton, the increased production represents $9.62 million of addi-tional annual revenue. This is an excellent return on investment for the project. Switching to LP steam reduces exchanger fouling and enables easier cleaning and maintenance of the thermosiphon reboilers. Annual savings of $500,000 are expected from reduced cleaning and maintenance costs.

Lessons learned and other findings. The overview of the entire study raised several interesting findings:

Proposals A and B. This design delivers the best performance for the C3 splitter system. The depropanizer aids in increasing product recovery (about 99 mol%) and improves operations for high-purity propylene (approximately 99.6 mol%). This design lowers heating requirements (15.2 MW vs. 22.8 MW for the orig-inal design). There is no evidence of overloading (flooding) in the multi-downcomer trays, even with high reflux rate requirements.

Proposal C. This alternative is not practical due to a high risk of tray flooding and higher energy requirements.

Proposal D. This design uses LP steam to meet reboiler duty requirements. The switch in heating medium provides easier

C3/C3=/C4

+

deethanizerbottoms

C5+

C4+

Debutanizer

Butane to pyrolysis furnaces

Propane topyrolysis furnaces

Propylene



C3/C3=Depropanizer

RevampProposal C

Proposal C: Use the secondary splitter system as a depropanizer.

FIG. 7

Propylene

Propane/propylenesplitters

TC

TG

Propane and C4+

LP steam

Process water

Process water return

Condensate returnRevampProposal D

Proposal D: Using LP steam as the heating medium in reboilers.

FIG. 8

TABLE 5. Pequiven C3 splitter revamp proposal D economic analysis1

Cost estimates USD, thousand

Basic and detailed engineering 500

Reboiler modification, process oily water to LP steam 250

Condensate removal system 1,200

Stainless steel pipe, 16 in. 18.5




Isolation 2.8

Installation and manpower costs 1,024

Total 3,025

Total investment (CAPEX) 3,025

Steam utilities and operating costs (OPEX) 2,510

Propylene incremental annual production 9,620

% profitability, propylene recovered/CAPEX x 100 318%

% profitability, net annual profit/CAPEX x 100 235%



cleaning and lowers maintenance time for reboilers. Greater recovery of propylene and increased purity of recycle propane are possible. This option improves furnace operations.

This study demonstrated that revamping the C3 splitter sys-tem to use one of the columns from the secondary C3 splitter as a depropanizer (Proposal A or B) results in propane recovery close to 100%. Heating requirements for the revamped system are lower, with easier cleaning and maintenance of reboilers. Propylene recovery would be 100% while the probability of tray flooding or weeping is low.

Simulation studies also indicated that it is not technically pos-sible to use the primary splitter system or one of its columns as a depropanizer, and the second one as propane/propylene splitter. This arrangement risks overloading trays and has higher heating requirements and reflux rates compared to the original design.

Optimization study. The results from this simulation and engineering study show that Proposals B and D are the opti-mal revamp alternatives. They deliver improved operability and performance for propane/propylene separation with lower duty requirements, better product recovery and purities and lower utilities and maintenance costs. These options would improve conversion and lengthen the service life for the furnaces, reboilers and distillation columns. However, due to budgetary constraints, only Proposal D is being implemented first—modification of reboilers from wash water to LP steam heating.

Pequiven is executing the project. The scope includes further developing the conceptual design, basic engineering and Class 4 cost estimates (± 20%). Project duration is expected to be around

24 months. When completed, this revamp will deliver 8,915 metric tpy of incremental propylene product valued at $9.62 million/yr, and additional annual savings of $500,000 through reduced reboiler cleaning and maintenance costs.

The process simulation and conceptual estimates in this study were invaluable. Both helped Pequiven gain clearer insight into its olefin plant operations. With such information, Pequiven was able to develop a better understanding of plant and equipment performance problems. HP

ACKNOWLEDGMENTThe author thanks Sanjeev Mullick of AspenTech for his help in preparing

this article for publication.

LITERATURE CITED 1 Aspen Plus and Aspen Capital Cost Estimator documentation, Aspen

Technology, Inc., Massachusetts, USA. 2 Billet, R., Distillation Engineering, M. Wulfinghoff Chemical Publishing Co.,

New York, New York, 1979. 3 Hsi-Jen, C. and L.Yeh-Chin, “Case Studies on Optimum Reflux Ratio of

Distillation Towers in Petroleum Refining Processes,” Tamkang Journal of Science and Engineering, Tamsui, Taiwan, Vol. 4, No. 2, pp. 105-110, 2001.

4 Romero, K., “Optimizing a Propane-Propylene Splitter in an Olefins Plant,” OPTIMIZE 2011, AspenTech Global Conference, Washington, DC.

Karen Romero is a process engineer at Pequiven. She has over 10 years of experi-ence in oil and gas and petrochemicals, with a focus on design, development, manage-ment and execution of projects. Ms. Romero is a chemical engineering graduate from the University of Zulia . She holds an MS degree in gas engineering. Ms. Romero is also an instructor professor of gas processing at Universidad Rafael Maria Baralt, Venezuela.


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Alternate feedstock options for petrochemicals: A roadmapNew hydrocarbons will be needed to meet future demand

S. K. GANGULY, S. SEN and M. O. GARG, CSIR-Indian Institute of Petroleum, Dehradun, India

F ollowing the economic slowdown in the US and Europe, a gradual demand shift has occurred from west of the Suez to east of the Suez. Asia-Pacific nations are the areas for energy

and petrochemical-based product demand growth. After China, India is the next growth hub for chemicals. A steadily growing middle class, which is about one third of the population, is a sig-nificant driver in India’s economy and supports new petrochemi-cal/chemical consumption. This young population with rising incomes is responsible for growing demand for consumer durable goods, such as automobiles and packaging. Petrochemicals con-stitute over 20% of the total chemical sector output—63% as polymers and 29% as synthetic fibers.1

Population function. Indian companies contribute 3% of global petrochemical capacity. This is unbalanced since India has almost 20% of the world’s population.2 India has a clear advantage in the petrochemical market. This nation has a rapidly growing domestic market and an abundance of trained manpower. Con-struction costs for Indian manufacturing facilities are 30%–40% cheaper.1–3 The present growth rate of the Indian chemical, indus-try is 8%–10%—the third largest in Asia.4

The high growth rate for polymers over the past five years can be attributed to substantial development in consumer industries, durables, automobiles, construction, infrastructure and the packag-ing industry.3 Table 1 lists growth rates of several polymeric materi-als. This demand growth in end-user segments can be translated into increased demand for basic petrochemicals such as olefins and aromatics. The additional demand for basic petrochemicals in 2020 is forecast to reach 20 million tpy (MMtpy).1,3

Feedstocks. Naphtha and natural gas (NG) are the major feedstocks in the petrochemical value chain. Limited crude and NG resources, and the volatility of crude oil prices, pose a threat to long-term naphtha supplies. There is an urgent need to identify alternative feedstocks to support new growth of the Indian pet-rochemical industry. A roadmap for diversification in the Indian petrochemical/chemical industry will be discussed.5–7

Searching for feedstock options. Globally, five regions have witnessed a significant shift in petrochemical market dynam-ics. Besides India, Brazil, Russia, China and the Middle East (ME) are centers of new growth for the hydrocarbon processing industry (HPI). Russia and the ME have abundant natural resources such

as low-cost NG. Brazil has successfully spearheaded a global bio-ethanol movement. China has substantially invested in coal to reduce its dependence on crude oil imports.

Brazil. This nation has been a vanguard in the development and usage of bioenergy. Brazil’s large-scale sugarcane production and subsequent ethanol production capability have made this nation one of the world’s most competitive biofuel producers. In 2005, Brazil was the largest producer of sugarcane, sugar and ethanol with 34%, 19% and 37%, respectively, of the world’s production. More than half of the country’s sugarcane yield is used for ethanol production.

Brazil has an extensive production platform for bio-ethanol and biopolymer production. International corporate giants are invest-ing in R&D for biobased technologies. Brazil’s Braskem and the US’ Dow Chemicals are partnering with Mitsui Japan, and they have announced plans to construct world-scale polyethylene (PE) facilities based on bioethanol. Braskem commissioned its first 200,000-tpy (200-Mtpy) green plastic plant in September 2010 at Triunfo. Excess ethylene generated in the process is converted to propylene through an “on-purpose” metathesis technology. The company plans to expand its capacity to 300 Mtpy by 2014. Braskem is successfully marketing its green PE at premium prices.

Dow’s biopolymer production initiative, with a planned 350 Mtpy of capacity, is forecast to be operational by 2015. When complete, Dow and Mitsui will have the world’s largest integrated facility for biopolymer production based on renewable, sugarcane-derived ethanol. This project is part of Dow’s low-carbon strategy. With every ton of green plastic produced, it is the equivalent of reducing 2.5 tons of carbon dioxide (CO2) from the atmo-sphere. The green plastics have identical properties and applica-tion characteristics to a hydrocarbon-derived plastic. The green

TABLE 1. End-user sector demand in India, thousand tpy

Sector Market size, 2006 Demand, 2011 Increase, %

Fiber and filament 59 117 98.3

Film and sheet 1,269 2,333 83.8

Woven sacks 860 1,570 82.6

Pipe 161 277 72

Roto molding 69 110 59.4

Blow molding 273 439 60.8

Injection molding 628 985 56.8



polymer can be used for home appliances, packaging, personal care, cleaning products and toys. Other chemical producers also plan to undertake projects in Brazil. Belgium-based Solvay plans to build a green polyvinyl chloride (PVC) facility in Brazil. The Solvay project is expected to produce 60 Mtpy of bioethylene for conversion to PVC.6–9

Russia. This nation has vast oil and NG reserves. Development of a domestic petrochemical/chemical industry is critical to Rus-sia’s future growth. Growth has been slow. The main hindrance for the petrochemical sector has been the absence of an industrial policy and a legislative framework aimed at overhauling this busi-ness sector. Despite having some of the largest NG and oil reserves in the world, Russia does not have a well-developed infrastructure for petrochemicals.6,7,10 Strengthening of the HPI infrastructure is essential before expansion can start.

Moreover, the Russian export market is seriously lacking. Stra-tegic ports must be built so that the HPI products can be distrib-uted and exported. Pipelines to supply feedstock and products are urgently needed. The Ministry of Energy is formulating compre-hensive plans to address these issues. Russia’s petrochemical industry, was severely impacted and reduced domestic plastic production by 10% to around 4 MMtpy in 2009.

As the markets stabilize in 2012, consumer confidence should rise. Market recovery is expected to be more pronounced as the 2018 World Cup approaches. Numerous commercial construc-tion projects are expected to impact PVC demand.6,7,10 With banks well placed to lend, it is believed that household spending will become an important driver of future growth. This should stimulate greater polymer consumption through expanding con-sumer-goods industries.

Petrochemical production growth will be led by Sibur. The com-pany’s proposed Tobolsk 1 MMtpy cracker would represent a heavier reliance on liquefied petroleum gas (LPG) and ethane as feedstocks instead of naphtha. This is in line with the government’s policy for cracking lighter feedstocks. Thus, Russia should exploit its low-cost NG resources to produce more petrochemicals. The new cracker is Sibur’s second cracker at Tobolsk. The existing plant has a capacity of 220 Mtpy. Another polypropylene (PP) project with a capacity of 500 Mtpy is expected to be onstream by 2012 at Tobolsk. The propylene feedstock will be supplied by a propane dehydrogena-tion (PDH) facility. The 330-Mtpy RusVinyl PVC complex, a joint venture between Sibur and SolVin at Kstovo, is due to come onstream in 2013.

Nizhnekamskneftekhim is also planning a new, 1-MMtpy eth-ylene facility at Kstovo. Sibur is revamping its ethylbenzene (EB) production in Perm, and is building an expandable polystyrene (EPS) plant at the site in phases. The company is also deliberat-ing with Gazprom on a gas cracker project in Russia’s Far East region, specifically Vladivostok or Khabarovsk. Vladivostok is the preferred location because the port is ice free. Sibur desires access to sufficient feedstocks to build a world-class cracker on the Baltic coast in the Leningrad region. Dow Chemical and Gazprom are partners on the proposed project.

Russia is expected to expand its petrochemical facilities, improve infrastructure and undergo a gradual shift in feedstock from naphtha to low-cost NG. Apart from meeting domestic demand, Russia plans to export petrochemicals to China. Russia possesses 13% and 34% of the world’s oil and NG reserves, respec-tively. The abundance of Russian reserves, with its close proximity to Asia, is a good reason for synergy and collaboration.6,7,11

China. In China, the HPI is dominated by three major players: China Petroleum and Chemical Corp. (Sinopec), China National Petroleum Corp. (CNPC) and China National Offshore Oil Corp. (CNOOC). All three companies have constructed world-class refining and petrochemical centers over the past 15 years. Even with many new projects under development, China continues to import petrochemicals and chemicals to meet domestic demand. Petrochemical imports are expected to double from 22 MMtpy to 39 MMtpy by 2012. Due to rapidly increasing demand for pet-rochemicals, China is aggressively exploring alternatives to reduce its heavy dependence on foreign oil, which currently comprises approximately 50% of total domestic consumption.

The chemical industry views coal as a feasible alternative feedstock, and is accelerating production of 114.5 billion tons of coal reserves. China has large coal reserves. In 2010, China developed several new technologies for coal-based chemicals, such as di-methyl ether (DME), synthetic natural gas (SNG) and olefins. By 2020, Shenhua Group, China’s largest coal producer, plans to bring onstream new coal-to-liquids (CTL) facilities with a total capacity of 30 million tons. Shell has licensed its gasifica-tion technology to 15 units in China. Due to the volatility asso-ciated with the price and availability of crude oil, coal is rapidly becoming the most favored alternative feedstock for polyolefins and other petrochemicals.6,7,12

The rapid development of polymer and polyester industries in China has resulted in a major demand surge for basic materi-als such as methanol, olefins and mono-ethylene glycol (MEG). Responding to this demand growth, the Chinese methanol indus-try significantly increased its output in 2010. However, stagnant growth in conventional products such as formaldehyde and acetic acid, along with obstructed DME growth, drove the industry to other processes/products such as methanol-to-olefins (MTO), methanol-to-propylene (MTP) and methanol-to-aromatics (MTA).13 It is estimated that more than 20 MTO and MTP projects, with a total capacity of 10 MMtpy, are in the planning stages or under construction. Several Chinese companies involved in coal-based MTO projects are Ningbo Heyuan, Dalian Fujia Dahua, Zhejiang Xingxing New Energy Technology, Jiangsu Shenghong Group, Chia Tai Energy Chemical and Shenhua Ningxia Coal Group (SNCG).

In addition, the big gap between MEG supply and demand has identified another new development—coal-to-MEG (CTMEG). Nearly 20 CTMEG projects are at different stages, with a com-bined capacity of 4 MMtpy. However, China plans to manage its total methanol capacity to be less than 50 MMtpy, with a maxi-mum of 150 producers by 2015.6,7,13 The Chinese coal-chemical industries are backed by intense government interest, along with new-generation technologies from Western multinationals. Lured by the country’s ample supply of coal, companies such as Total Petrochemicals, Celanese and Dow Chemical are advancing their cutting edge technologies in China.

Table 2 provides a few examples of new projects in China. It is anticipated that approximately 90% of PVC and 85% of methanol will be coal based by 2012. Dow is redoubling its efforts on coal-to-chemicals projects; the company has been studying this process with Chinese coal company Shenhua in Yulin, Shaanxi Province since 2007. The companies have submitted a project application report to the Chinese government for review and approval.

Construction of coal-based industries raises issues over CO2 emissions, which make sequestration an additional investment. Considering climate change protocols, carbon capture and seques-



tration (CCS) of CO2 is an important issue. Construction of the first CCS demonstration unit in the Chinese coal chemical industry has occurred. The project was designed to capture and sequester 100 Mtpy of CO2 from Shenhua’s Ordos CTL complex. The success of this demonstration unit will invite investment for mega-sized CCS facilities.7,13 Developing a domestic coal-chemical industry in China has made it possible to supplement and partially substitute traditional naphtha feedstocks. Develop-ing a clean coal-chemical industry by capturing CO2 will help China ensure energy security and sustainable development of its petrochemical industry.

The Middle East. A wave of ME capacity additions are expected to come online in the near term. Mega petrochemical projects are under construction in Saudi Arabia, Iran, Qatar, the United Arab Emirates (UAE) and Kuwait. By 2012, ME ethylene capacity is expected to increase to 28 MMtpy, and propylene capacity will increase by 7 MMtpy. Table 3 lists major ME projects. Saudi Arabia’s ethylene capacity will reach 13.5 MMtpy, and its propylene capacity will reach 4.1 MMtpy by 2012. Iran is the second major petrochem-ical player in the ME and is expected to increase its ethylene capacity to 8.4 MMtpy and its propylene capacity to 1.4 MMtpy by 2012.

Qatar has two major ethylene producers, Qatar Petrochemi-cal Co. and Qatar Chemical Co. Several ethylene projects are in progress for startup by 2018. Qatar has no propylene production capacity; however, a 700-Mtpy propylene unit is in planning with startup by 2013. The UAE has only one ethylene-producing facil-ity; it is currently under expansion. Kuwait increased its ethylene capacity by 80 Mtpy in 2010.7, 17

The ME holds an advantageous position when it comes to PE and PP production, due to its lower-cost NG natural resources and feedstocks. However, ME NG prices are expected to increase beyond $0.50/MMBtu–$0.75/MMBtu, as production costs have also risen significantly. The ME only consumes about 20% of the polyolefins it manufactures. Thus, ME petrochemical companies are focused on exports. Fast-growing China has always been a lucrative market for ME producers. However, a recent surge in ethane crackers has resulted in an imbalance of the ethylene-propylene market. The anticipated annual growth rate of ethylene over the next decade is 4%. During the same period, the expected

propylene growth rate is 5%. To close the gap, the ME is heavily investing in “on-purpose propylene” technologies.7,18 For new projects, the era of extremely cheap NG feedstock is over. The price will not rise dramatically, but it will remain in the range of $1.50/MMBtu–$2/MMBtu.17

US and Europe. Although China, the ME, India and Latin America are witnessing steady economic growth, mature econo-mies such as the US and Europe are facing demand decline for petrochemicals. The official start of the most recent economic downturn was December 2007; it deepened during 2008 and 2009, thus seriously affecting petrochemicals and derivative mar-kets in the US and Europe. US data showed that the petrochemi-cal market dipped by 11.9% in 2008 compared to 2007 and by 13.1% in 2009 compared to 2008.

The recovery has been rather tepid. For the US and Europe, which are historically the largest regions for producing and con-suming ethylene, the strategy has evolved around delaying new investments in the region, consolidating markets and rationalizing assets.5–7,19 Table 4 and Fig. 1 show how refinery utilization rates have changed. The trend is part of the rationalization occurring in Europe and the US. The sale/change of refinery ownership has increased in Europe and the US as major international refining companies restructure their downstream businesses.

Stagnant demand growth and the inability to compete with more efficient refineries have led to closure or capacity reduc-tions of 50 MMtpy in Europe and the US over the last two years. Another 35 MMtpy of capacity rationalization is forecast over the next two years.5–7 However, the US is moving forward with shale gas exploration. Shale is a very fine-grained sedimentary rock with parallel layers of low permeability. The US is estimated to have 3,600 Tcf of shale gas reserves. Between 2005 and 2010, US NG production jumped by 18% due to shale gas. US companies like Cheniere Energy Inc., ConocoPhillips, BG Group and Southern Union are considering opportunities to export NG as LNG, for which prices are two to three times higher than in the US.

Shell is planning to build a world-scale ethylene cracker with derivative units in the Appalachian region. The cracker would process ethane from Marcellus NG to produce ethylene. Other companies considering crackers include Dow Chemical, Chev-

TABLE 2. Recent coal-to-chemicals project in China

Company Location Startup Technology Capacity, MMtpy

SNCG and Air Liquide Ningxia 2012–2013 MTP 0.50

Ningbo Heyuan Guangdong 2012 MTO 1.80

Shenhua Baotou Inner Mongolia 2010 MTO 1.80

Qinghai Salt Lake Industry Company and Dow Chemicals Qinghai 2013 MTO 0.16

Total Petrochemicals and China Power Investments Inner Mongolia 2015 MTO 1.00

Celanese Shaanxi 2014 Coal-to-ethanol 0.80

Sinopec and Syntroleum Zhejiang 2010 Coal, asphalt, petroleum coke 80 bpd to petrochemicals

Henan Coal Chemical Industry Group and Danhua Technology Group Henan 2011–2012 Coal-to-MEG 1.00

East Hope Group Inner Mongolia 2012 Coal-to-PVC 0.40

Shaanxi Beiyuan Group Shaanxi 2010 Coal-to-PVC 0.50

Huadian Group and Tsinghua University Shaanxi – MTA (fluidized bed) –

CNOOC Hainan 2010 Coal-to-methanol –

Shaanxi Changqing Energy Chemicals, Xuzhou Mining Group Shaanxi 2013 Coal-to-methanol 1.50and Shaanxi Coal Field Geological Expl. Dev. Co.



ron Phillips Chemical and LyondellBasell.20 In Europe, Norway’s Statoil has cut deals for shale gas over the past year. The extraction of shale gas is more expensive than NG due to massive hydraulic fracturing procedures. Significant capital investment is the only deterrent to its wider commercialization.

Recommended roadmap. Selection of alternate feedstock options is a geopolitical and need-based issue. Every region must consider feasibility in terms of geopolitical and geographical posi-tion, economic strength and demand addressability. India has several initiatives:6,7

Waste plastics. The rising middle class of India has created a growing demand for polymers, which are major components in most consumer products. Current polymers consumption is reported at 12 MMtpy–14 MMtpy. The limited shelf life of

products leads to large-scale production of waste plastics, which are non-biodegradable. Environmental concerns associated with these plastics make incineration and land-filling less desirable.

Chemical recycling of such materials can address waste man-agement and bridge the growing gap between supply and demand of base petrochemicals. The catalytic conversion of such polymeric materials (particularly PP and PE) can yield a substantial amount of olefins (ethylene, propylene, butylenes and olefins of C10–C14 range) or aromatics. This technology has the potential to produce around 1.5 MMtpy–2 MMtpy of aromatic petrochemicals or alternately, 1 MMtpy–1.25 MMtpy of olefinic petrochemicals, which can comfortably meet the 5%–10% projected additional petrochemical demand by 2020.

However, the key hindrance lies in the logistics associated with collecting raw materials for the catalytic conversion process. Policy can be initiated for effective collection and segregation of waste plastics. Plastics can be collected at a nominal price of 5Rs/ kg–10 Rs/kg. A common facility to process these wastes from about 10 to 15 different city municipalities can be developed for petrochemi-cal production purposes.6,7,21

Lignocellulosic biomass. India is a favorable place to develop residual biomass into ethanol, lignin, olefins and phe-nolics due to the abundance of raw materials from forest and agricultural residues. About 800 MMtpy of forest and agricul-tural residues are generated annually in India. After distribution into animal fodder, fuel for heating, and manure, approximately 150 MMtpy of nonfodder residue is available at a nominal price of 2 Rs/kg–5 Rs/kg. A new biotechnological process can con-vert residual biomass into ethanol- and lignin-rich material. At 25% utilization of the available residual biomass, 7.5 MMtpy of ethanol or 4.5 MMtpy of equivalent ethylene, along with associated lignin-rich material, can be processed. This option has the potential to meet around 15%–20% of the additional petrochemical demand in 2020. However, technology must be improved for the efficient conversion biomass to ethanol; a more cost–effective reactor design is needed.22

Table 5 lists the commonly available nonfodder biomass found in India. One possible solution is to construct biomass-processing plants at sites where biomass residues collected from 10 to 15 nearby villages and/or forests may be processed at a common processing plant. Rural organizations should focus on collecting agricultural and forest wastes and then selling the biowaste to process plants for olefin production and to downstream petro-chemical industries for biopolymer production.6,7,22

TABLE 4. Global refinery utilization rates5

Refinery utilization, % OECD Non-OECD

2001 89 76

2002 87 75

2003 88 77

2004 88 79

2005 87.5 82

2006 86 82.5

2007 86.5 82.5

2008 87.5 83

2009 82.5 81

2010 82 80Year

Refin

ery

utili

zatio

n ra

tes,

%

65

70

75

80

85

90

95

Non-OECD nationsOECD nations

’10’09’08’07’06’05’04’03’02’01

FIG. 1

TABLE 3. Recent ME petrochemical projects

Ethylene, Propylene, Country Project Startup MMtpy MMtpy

Saudi Arabia PetroRabigh 2009 1.3 0.6

Saudi Arabia Saudi Ethylene and 2009 1.3 – Polyethylene Co.

Saudi Arabia SABIC Eastern Petrochemical 2010 1.3 – Co. (Shark III)

Saudi Arabia Saudi Kayan 2011 1 –

Saudi Arabia Sadara Chemical Co. 2016 1.2 0.4

Iran Morvarid Petrochemical Co. 2010 0.5 –

Iran Kavya Petrochemical Co. 2011 2 –

Iran Ilam Petrochemical Co. 2012 0.153 0.12

Iran Gachsaran Petrochemical Co. 2012 1 –

Iran Persian Gulf Co. 2014 1.3 1

Qatar Qatar Petrochemical 2011 – 0.18 (MIC complex)

Qatar Ras Laffan Olefin Complex, 2015 1.6 – Exxon

Qatar Ras Laffan Olefin Complex, 2018 1.3–1.6 – Shell

UAE Borouge 2 Petrochemical Co. 2011 1.4 –

UAE Borouge 3 Petrochemical Co. 2012 0.6 –

Kuwait Equate Petrochemical Co. 2010 0.8 –

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Milan, Italy | 12–14 June | www.HPIRPC.comInternational Refi ning & Petrochemical Conference

Dear Readers,

You are cordially invited to attend the third annual Hydrocarbon Processing International Refi ning and Petrochemical Conference, organized by Gulf Publishing Company, to be held 12-14 June 2012 in Milan, Italy.

As an attendee, you will have the opportunity to share your professional knowledge with others, while learning about the latest technical advancements from some of the brightest minds in the hydrocarbon processing industry. In addition, the networking opportunities aff orded by a gathering like IRPC 2012 provide the personal contact necessary for the free-fl owing exchange of ideas.

In past years, this event has welcomed attendees representing companies such as ABB, Baker Hughes Incorporated, BP, DuPont, Dresser, eni, ExxonMobil, Fluor Corporation, GE, Indian Oil Corporation, Reliance Industries, Saudi Aramco, Shell, Technip, UOP and Walter Tosto.

Following the highly successful 2010 conference held in Rome and the 2011 conference in Singapore, IRPC 2012 will maintain a high-level, two-day technical conference program devoted to knowledge sharing and best practices in international refi ning and petrochemicals.

By registering now, you will be able to take advantage of our Early Bird rate —a 15 percent discount off our regular attendee price. Please visit www.HPIRPC.com or call +1 (713) 520-4402 to complete your registration today. Thank you for your interest and consideration.

Sincerely, Bill Wageneck , Publisher, Hydrocarbon Processing

The Advisory Board for this conference is made up of industry experts from operators and service companies. The IRPC 2012 Advisory Board

members are:

Dr. Madhukar Onkarnath GargFNAE DirectorIndian Institute of Petroleum in Dehradun

Rajkumar GhoshExecutive DirectorIndian Oil

Andrea GragnaniRefi ning Product Line DirectorTechnip

Dr. Syamal PoddarPresidentPoddar & Associates

Andrea AmorosoVice President Process Technologyeni

Stephany RomanowEditorHydrocarbon Processing

Michael StockleChief Engineer Refi ning TechnologyFoster Wheeler

Giacomo RispoliExecutive Vice President, Research & Development and Projects IRPC Advisory Board Chaireni–Refi ning & Marketing Division

John BaricLicensing Technology ManagerShell Global Solutions International B.V.

Eric BenazziMarketing DirectorAxens

Carlos CabreraExecutive Co-ChairmanIvanhoe Energy

Dr. Charles CameronHead of Research& TechnologyBP

Antonio Di PasqualeVice PresidentRefi ning Product LineTechnip

Giacomo FossataroGeneral ManagerWalter Tosto S.p.A.

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MILAN, ITALY | 12–14 JUNE

About IRPC 2012Hydrocarbon Processing’s International Refi ning and Petrochemical Conference is a market-leading technical conference, providing an elite forum for industry leaders to come together to share knowledge and ideas relating to the refi ning and petrochemical industries.

The conference emphasizes the latest technological and operational advances from both a local and global perspective and is attended by project engineers, process engineers and hydrocarbon processing industry (HPI) management offi cials from around the world.

In today’s increasingly competitive global HPI, managers and engineers are actively seeking information and solutions to make their company or organization more effi cient and profi table. This is your chance to take part in the discussion. IRPC off ers an intimate, thought-provoking working environment to meet and network with industry leaders and key decision makers as they explore how technological and operating advances can benefi t their organization or plant.

This year’s conference will feature a dual-track program with topical sessions on heavy oil, hydrogen, environment/safety, energy effi ciency, petrochemical/refi nery integration and biofuels/clean fuels.

Why Attend IRPC 2012?• To be part of a focused forum dedicated to exploring the latest developments within the hydrocarbon processing industry • For the opportunity to participate in real-time information sharing with leading HPI professionals• To benefi t from ample networking opportunities between technical sessions that allow you to connect with old and new business contacts • Have the chance to hear the opinions of key industry players on both general and area-specifi c topics

Who will be at IRPC 2012?• HPI professionals looking to discover the fi eld’s latest technological advancements• Purchasing agents scouting out and mapping new ways to strategically invest• International HPI leaders representing a range of operating and technology companies• Engineers looking to expand their technical knowledge alongside other industry professionals• Companies of all sizes from the areas of operating, technology, service, construction and more

For sponsorship opportunities, contact Bill Wageneck, Vice President and Publisher, Hydrocarbon Processing at +1 (713) 520-4421 or [email protected].

IRPC 2012 Sponsors:

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eni Plant TourBy registering to attend IRPC 2012, you will have the chance to reserve your spot on an exclusive tour of eni’s Sannazzaro de’ Burgondi Refi nery in Pavia, Italy. A short bus drive from Milan, the refi nery is home to the fi rst-ever industrial application of the company’s proprietary eni Slurry Technology for the conversion of heavy oil residue. To enter your name for a chance to take part in the tour, please email Gwen Hood, Events Manager, Gulf Publishing Company, at [email protected]. Space is limited for this tour. Entrants must be paid registrants of IRPC 2012 in order to be eligible to attend.

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8:30–9:15 a.m. Continental Breakfast

9:15–9:30 a.m. Opening Remarks: John Royall, President & CEO, Gulf Publishing Company

KEYNOTE SPEAKERS

9:30–10:15 a.m. Giacomo Rispoli, Executive Vice President, Research & Development and Projects, eni

10:15–10:45 a.m. Michael Lane, Secretary General, CONCAWE

10:45–11 a.m. Coff ee Break

TRACK 1: HEAVY OIL TRACK 2: HYDROGEN

Session 1

Session Chair: Michael Stockle, Chief Engineer—Refi ning Technology, Foster Wheeler

Session 2

Session Chair: Syamal Poddar Ph.D, P.E Fellow AIChE, Poddar & Associates

11–11:30 a.m. Heavy Oil Processing in IOCL Refi neries—Shri Susobhan Sarkar & Shri Tapan Kumar Basak of Indian Oil Corporation Limited

Balancing Hydrogen Demand and Production: Optimising

the Lifeblood of a Refi nery—Luigi Bressan of Foster Wheeler

11:30 a.m.–12 p.m. Processing Heavier Crudes to Meet Future Energy

Needs; Improved Modeling Improves Design—Joseph McMullen (speaker) & David Bluck of Invensys Operations Management

Effi cient Hydrogen Management in Refi nery—Debangsu Ray & Mukesh Mohan of Indian Oil Corporation Limited

12–12:30 p.m. Latest Improvements in VGO Based Hydrocracking

Technologies—AxensHydrogen-Creep Resistant 9% Chromium Heavy Plates for

Future High Temperature Refi ning Reactors—Cedric Chauvy (speaker), S. Pillot & L. Coudreuse of Industeel, ArcelorMittal Group

12:30– 1 p.m. Commercial Experience in Diffi cult Feedstock

Upgrading with Criterion/Zeolyst’s Catalysts—Gert Meijburg of CRI/Criterion Catalyst Company Ltd.

Simulate Your Refi nery to Increase Your Bottom Line—

Luigi Pedone (speaker) & Regina Meloni of Saipem S.p.A. and Vassilis Harismiadis of Hyperion Systems Engineering, Modeling and Simulation (speaker)

1–2:30 p.m. Lunch Followed by Coff ee & Desserts in Exhibit Hall

TRACK 1: HEAVY OIL TRACK 2: ENVIRONMENT & SAFETY

Session 3

Session Chair: Eric Benazzi, Marketing Director, AxensSession 4

Session Chair: Madhukar Onkarnath Garg, FNAE, Director, Indian Institute of Petroleum

IRPC 2012 Agenda | Day 2: Wednesday, 13 June

eni PLANT TOUR

2:15 p.m. Depart from MiCo – Milano Congressi

3:30 pm Arrival at eni’s Sannazzaro de’ Burgondi Refi nery EST Project

3:45 pm Induction Meeting and Presentation of the Project

4:30 pm eni Plant Tour Begins

5:30 pm eni Plant Tour Ends, Refreshments Served

5:40 pm Depart from eni’s Sannazzaro de’ Burgondi Refi nery EST Project

7:00 pm Arrive Back at MiCo – Milano Congressi

IRPC 2012 Agenda | Day 1: Tuesday, 12 June

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IRPC 2012 Agenda | Day 3: Thursday, 14 June

2:30–3 p.m. (Getting) More Value from FCC Bottoms—Victor Scalco, General Atomics/Gulftronic Electrostatic Separators (speaker) & John Paraskos of Chevron Research/Gulf Petroleum

Sulphur Recovery Facilities of Petroleum Refi neries with

Very Stringent Requirements of SO2 Emissions—Michele Colozzi of Tecnimont KT S.p.A. & Antonio Salati of Processi Innovativi

3–3:30 p.m. A Proper Design and Sophisticated Numerical Analysis

May Extend the Life of Coke Drums—Patrizio Di Lillo of Walter Tosto S.p.A.

HSE Management System—Best Practice—Dr. Dhiraj D. Radadiy of ADNOC/SPC

3:30–4 p.m. Technological Advancements in Delayed Coking

Equipment—DeltaValve, presented by Werner Vermeire

Effl uence & Carbon Management in Petkim—Dilek Celenk Akinci, Sadi Senocak & Secil Kirsen Dogan of Petkim Petrochemical Inc.

4–4:30 p.m. Afternoon Break

TRACK 1: HEAVY OIL TRACK 2: ENERGY EFFICIENCY

Session 5

Session Chair: Giacomo Fossataro, General Manager, Walter Tosto S.p.A.

Session 6

Session Chair: Carlos Cabrera, Executive Co-Chairman, Ivanhoe Energy

4:30–5 p.m. EST Technology for Tar Sands Upgrading: A Profi table

and Sustainable Business by Nicoletta Panariti and Andrea Amoroso of eni

Flaring Minimization Program Saudi Aramco—Muhsin D Al-Khudhairi of Saudi Aramco

5–5:30 p.m. Sour2Power—P.C. Chandrahasan of Siemens Oil & Gas Energy Effi ciency in Oil Refi neries—Rakesh Jain of Indian Oil Corporation Limited

5:30–6 p.m. Co-Processing Canola Oil with HVGO for Green Oil by

Hydrotreating—Song Chen of CanmetENERGYEnergy Effi ciency Monitoring and Improvement in Refi nery

Process Plants Through Chemcad® Process Simulation

Software—Karthik Ramesh & Manish Mishra of Indian Oil Corporation Limited

6–7:30 p.m. eni Welcoming Reception in Exhibit Hall

9–9:30 a.m. Continental Breakfast

9:30–9:35 a.m. Morning Remarks: T. Wright, Director, Global Events, Gulf Publishing Company

KEYNOTE SPEAKERS

9:35–10:20 a.m. Dr. Fereidun Fesharaki, Chairman, FACTS Global Energy

10:20–10:50 a.m. tbd

10:50–11 a.m. Coff ee Break

TRACK 1: HEAVY OIL TRACK 2: ENVIRONMENT & SAFETY

Session 7

Session Chair: Rajkumar Ghosh, Executive Director, Indian Oil Corporation Limited

Session 8

Session Chair: Andrea Gragnani, Refi ning Product Line Director, Technip

11–11:30 a.m. The First EST Industrial Plant—the EST Project at

Sannazzaro Refi nery by Andrea Amoroso and Francesco Misuraca of eni

The Ultimate Path to H2S-Free Gas—Joseph Gentry & Zhepeng Liu of GTC Technology US LLC

11:30 a.m.–12 p.m. Maximize Heavy Oil Profi ts—Robert P. Bartek & Scott Fess of Applied Rigaku Technologies, Inc.

Greenhouse Gases Inventory Management in the Brazilian

Chemical and Petrochemical Industry—Obdulio Fanti of Brazilian Association of Chemical Industries (Abiquim)

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IRPC 2012 Agenda | Day 3: Continued

12–12:30 p.m. New Gasifi er Design to Convert the Bottom of the

Barrel—Dev Barot of KBRSulfur Recovery from Dilute H2S Sources: An Alternative

to the Liquid Redox Process—Michael P. Heisel of ITS Reaktortechnik GmbH (speaker) & Angela F. Slavens of WorleyParsons

12:30– 1 p.m. Oil Refi nery Product Blending—Alan Munns of ABB Ltd. Eff ect of Reliability on ROIC—Rick St. Laurent & Logan Anjaneyulu of Valero Energy Corporation

1–2:30 p.m. Networking Lunch Co-sponsored by ABB followed by Coff ee & Desserts in Exhibit Hall

TRACK 1: HEAVY OIL TRACK 2: PETROCHEMICAL/REFINING INTEGRATION

Session 9

Session Chair: Antonio di Pasquale, VP Refi ning Product Line, Technip

Session 10

Session Chair: Stephany Romanow, Editor, Hydrocarbon Processing

2:30–3 p.m. Diesel for Bunker. An Environmental Constraint or an

Opportunity for Deep Convesion in the Long Run?—

Laura Zanibelli and Carlo Gabriele Clerici of eni

Expand the Throughput—Leon Markowski of PROBAT Leon Markowski & Kamil Marszalek, ORLEN Projkt S.A. (Speaker)

3–3:30 p.m. Transportation Fuels and Petrochemicals from Waste

Polyolefi ns—Sanat Kumar, H U Khan, Manisha Sahai, Ajay Kumar, S M Nanoti & M O Garg of CSIR-Indian Institute of Petroleum, Dehradun

Refi nery & Petrochemical Integration—IOCL’s Experience

& Future Option—S.M.Vaidya & Sanjiv Singh of Indian Oil Corporation Limited

3:30–4 p.m. Production of US Grade Gasoline and Pure Benzene

from FCC C6 Heart Cut Simultaneously—M O Garg, S M Nanoti, B R Nautiyal, Sunil Kumar, Prasenjit Ghosh, Jagdish Kumar & Pooja Yadav, Misha of CSIR—Indian Institute of Petroleum, Dehradun

Unique Petrochemical Opportunities Harvesting Shale

Gas Deposits—Steven Cho of Lummus Technology, a CB&I Company

4–4:30 p.m. Afternoon Break

TRACK 1: HEAVY OIL TRACK 2: BIOFUELS/CLEANFUELS

Session 11

Session Chair: John Baric, Licensing Technology Manager, Shell Global Solutions International B.V.

Session 12

Session Chair: Andrea Amoroso, Vice President, Process Technology, eni—Refi ning & Marketing Division

4:30–5 p.m. Heavy Oil to Liquids—Carlos Cabrera of Ivanhoe Energy

Industrial Investigation on Feasibility to Raise Near Zero

Sulphur Diesel Production by Increasing Fluid Catalytic

Cracking Light Cycle Oil Production—Ilshat Sharafutdinov, Dicho Stratiev & Ivenline Shishkova of Lukoil Neftochim Bourgas

5–5:30 p.m. Maximise Transport Fuels and Power with Foster

Wheeler PetroPower™—Michael Stockle of Foster Wheeler

Bio-Based Chemicals: Going Commercial—Ron Cascone of Nextant

5:30–6 p.m. Integrated Refi ning and Petrochemical Units Convert

Residue to Propylene—Dalip Soni, Rama Rao & Gary Sieli of Lummus Technology, a CB&I Company, and Ujjal Mukherjee of Chevron Lummus Global

100% Renewable Jet Fuel from Biothylene—Edward Peterson of Synfuels International, Inc.

6–7:30 p.m. Closing Reception

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How to Register for IRPC 2012To reserve your spot at the conference, please visit www.HPIRPC.com or contact Gwen Hood, Events Manager, Gulf Publishing Company at +1 (713) 520-4402 or [email protected]. For more information about the conference, and to learn about other ways to get involved, please contact Teresa “T” Wright, Director, Global Events, Gulf Publishing Company at +1 (713) 520-4475 or [email protected].

RegistrationBy registering to attend IRPC 2012 you will have access to:

• More than 40 unique technical presentations

• Receptions and breaks between sessions to maximize networking potential

• Complimentary USB key containing all conference materials

• The chance to register for a tour of Eni’s Sannazzaro de’ Burgondi Refi nery

LocationIRPC 2012 will be held at the MiCo – Milano Congressi, which is located in Milan’s city center and is one of the largest conference venues in Europe. MiCo – Milano Congressi | Piazzale Carlo Magno, 1 | 20149 Milano

AccommodationsEnterprise Hotel | Corso Sempione 91 | 20149 Milano | +39 02 31818 1Please visit www.enterprisehotel.com to check room availability for 12–14 June 2012. Enter code irpc2012 in the customer code box to receive the special per-night rates of €135 (Single), €155 (Double), €165 (Executive Single) or €185 (Executive Double)—subject to availability.

Admiral Hotel | Domodossola 16 | 20145 Milano | +39 023492151Please visit www.AdmiralHotel.it to check room availability for 12–14 June 2012. Click on the International Refi ning and Petrochemical Conference

link under off ers to receive the special per-night rates of €199 (Single), €119 (Double Single Use) or €149 (Double)—subject to availability.


IRPC 2012 Registration Rates:Registration Type Early Bird (by 30 April) Regular (by 1 June)

Single Attendee USD $930 USD $1,095

Team of Two USD $1,674 USD $1,969

Pack of 10* USD $8,415 USD $9,900

*Pack of 10 purchase includes a reserved table at lunch, listing as a Team Pack Sponsor in the event program, and signage with your company name and logo displayed at the conference.

www.HPIRPC.com

1

3 m

3 m

3 m

3 m

3 m

5.5 m

5.5

m

2 3 4 5 6 7 8 9 10 11

12

19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35

13

14 15 16

17 18

* As of March 19.

1 Carpenteria Corsi5 Sicelub Iberico6 Pilosio S.p.A.7 Hiller GmbH8 ONIS9, 10 Invensys11 Auma Italiana Srl14 ABB15 eni

16 Walter Tosto19 Catapano S.r.E.24 West Virginia, USA25 Intergraph Italia L.L.C.26 Ametek27 Ansaldo28 Shin Nippon29 SIS SERVIZI INTEGRATI DI SICUREZ

30, 31 Curtiss-Wright32 Scame Sistemi S.r.L33 GTC Technology34 Foster Wheeler35 Eidos

Exhibition Booths Sold To Date

Available*

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Conference Exhibit Floor at MiCo–Milano Congressi in Milan, Italy:

How to Feature Your Company at IRPC 2012There is a way for your company to participate in IRPC 2012, no matter the budget. Sponsorships and exhibitor packages of various levels are still available. To reserve your sponsorship or exhibition space today, contact Bill Wageneck, Vice President and Publisher, Hydrocarbon Processing at +1 (713) 520-4421 or [email protected].

For more information about the conference, and to learn about other ways to get involved, please contact Teresa “T” Wright, Director, Global Events, Gulf Publishing Company at +1 (713) 520-4475 or [email protected].


AmetekAnsaldo Auma Italiana S.r.l. Carpenteria CorsiCurtiss-Wright Flow ControlEIDOS

Foster WheelerHiller GmbHIntergraphONISPilosio S.p.A.SCAME Sistemi

Shin Nippon Machinery Co.Sicelub IbericoServizi Integrati di SicurezzaWest Virginia, USA

IRPC 2012 Exhibitors:



Carbon dioxide. With climate-change policies in place, reduc-ing greenhouse gas (GHG) emissions is a key issue. Petrochemi-cal/chemical facilities are major GHG sources through CO2 emis-sions. Technologies to reuse CO2 as feedstock for chemicals are under development.

Fertilizer demand in India is rising at the rate of 3%/yr, with a consumption rate of 29 MMtpy. About 7 MMtpy of fertilizer is imported. Planned additions will not meet demand. This gap between supply and demand can be par-tially addressed by reusing sequestered CO2. Using CO2 as feedstock for urea is a synergistic option provided hydrogen from a non fossil source is possible. To produce 30 MMtpy of urea would require stoichiometrical 22 MMtpy of CO2. The CO2 can be sequestered from sources such as power plants, vehicles, refineries and chemical and cement industries. The amount of CO2 produced ranges from 0.2 kg kg–1–0.5 kg kg–1 of the final product produced. Indian refineries alone produce around 30 MMtpy–35 MMtpy of CO2.6, 7 There is sufficient CO2 for urea production, but sourcing renewable hydrogen is the main challenge.

Others. India’s rich coal reserves can be a key driver in devel-oping gasification technology, which involves converting coal to a synthesis gas and then into olefins. This technology has shown fantastic potential. But it is uncertain that this process can be used to effectively replace ethylene crackers. Moreover, the cost for gasification technologies is quite high due to the reactor size and recycle issues. The process is not currently economically attractive.

Recent prospecting of shale gas shows that India possesses 300 Tcf of shale gas that is methane rich. Low conversion lev-els (10%–20%) of methane sourced from shale gas or NG to petrochemicals require more process improvement before com-mercialization. However, R&D efforts will certainly make it more affordable and profitable.

Considering the necessary government policies and technol-ogy development in place, it is expected that roughly 20%–30% of additional petrochemicals demand in 2020 can be met by the suggested alternate feedstock options. HP

ACKNOWLEDGMENTSThis is a revised and updated version from an earlier presentation from the

International Refining and Petrochemical Conference–Asia, July 19–21, 2011 in Singapore. The authors would like to thank their colleagues, Dr. D. K. Adhikari and Dr. Sanat Kumar at CSIR-Indian Institute of Petroleum, Dehradun, for their fruitful technical discussions that helped in the development of this article.

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TABLE 5. Commonly available biomass residues in India

Byproducts—Agricultural residues Forest residues Agro-based industries

Rice straw Mahua flowers Sugarcane bagasse

Cassava Tree tops Molasses

Sweet sorghum Leaves Oil seeds

Jute plant Sawdust

Wheat straw

Cotton stalk

Sugarcane tops




LITERATURE CITED 1 Navavaty, K., “Vision 2020: Indian Chemical Industry Outlook,” Chemical

News, May 2009, pp. 21–25. 2 Purwaha, A. K., “Indian Petrochemical Industry-Challenges and

Opportunities,” 9th Petrochem Conference, Mumbai, India, Nov. 19–20, 2007.

3 Bansal, B. M., M. Mitra and M. George, “India-Polyolefin Perspective,” Hydrocarbon Processing, April 2009, pp. 41–46.

4 Hari, P., “Indian Chemicals: Hungry for Profits,” Chemistry & Industry, January 2009, pp. 23–25.

5 Ruwe, P., “Refining outlook: Capacity expansion and rationalization,” Hydrocarbon Processing, September 2011, pp. 53–57.

6 Ganguly, S. K., S. Sen and A. Bansal, “Alternate Feedstock Options for Petrochemicals: A Roadmap,” International Refining and Petrochemical Conference, Singapore, July 19–21, 2011.

7 “Feasibility Study on Alternative Feedstock Options for Petrochemicals,” CSIR-Indian Institute of Petroleum Report: SPD-02-09, 2010.

8 Jagger, A., “Viva Pretty Polymers,” Chemistry & Industry, September 2007, pp. 22–23.

9 “Dow Chemical, Mitsui form Biopolymers JV in Brazil,” Hydrocarbon Processing Newsletter, July 19, 2011.

10 “Russia Petrochemicals Report Q4 2010,” Business Monitor International, 2010.

11 “Russia Petrochemicals Report Q2 2011,” Business Monitor International, 2011.

12 Milmo, S., “Petrochemicals-New Technologies for Making Olefins,” Chemistry and Industry, September 2007, pp. 24–26.

13 “China Coal to Chemicals,” ASIACHEM Monthly Report, November 2010. 14 “Air Liquide to Engineer, license coal to propylene project in China,”

Hydrocarbon Processing Newsletter, Aug. 26, 2011. 15 “Dow Propylene process technology chosen for new Qinghai unit in China”,

Hydrocarbon Processing Newsletter, Aug. 23, 2011. 16 “Sinopec, Syntroleum open China coal to liquid unit,” Hydrocarbon Processing

Newsletter, Aug. 2, 2011. 17 Adibi, S., “A Special Report-Middle East,” Hydrocarbon Processing, April 2009,

pp. 29–37.

18 Tallman, M. J. and C. Eng, “Consider new catalytic routes for olefins produc-tion,” Hydrocarbon Processing, April 2008, pp. 95–101.

19 Swift, T. K., “A Special Report-North America,” Hydrocarbon Processing, April 2009, pp. 55–56.

20 “Shell plans world scale US ethylene cracker near Marcellus shale region,” Hydrocarbon Processing Newsletter, June 6, 2011.

21 “Catalyst and Processes on Conversion of Waste Plastics to Value added Products,” CSIR- Indian Institute of Petroleum Report no SPD-02-06, 2006.

22 Kumar, S., S. P. Singh, I. M. Mishra, and D. K. Adhikari, “Recent Advances in Production of Bio-ethanol from Lignocellulosic Biomass,” Chemical Engineering Technology, 2009, 32(4), pp. 517–526.

Sudip K. Ganguly is a principal scientist for the CSIR-Indian Institute of Petro-leum in Dehradun, India, a constituent laboratory of the Council of Scientific and Industrial Research (CSIR), New Delhi, India. He has 15 years of research experience. Mr. Ganguly is involved with modeling and simulation at CSIR-IIP. His research inter-ests include mechanistic kinetics of refinery conversion processes. He has published 30 research papers and is a member of AIChE. He is also Dean (Academics) of the post-graduate research program in engineering at CSIR-IIP.

Shounak Sen Sharma is a chemical engineer from the Birla Institute of Tech-nology and Sciences Pilani—Goa Campus, India. He is also a business analyst with Mu Sigma Business Solutions in Bangalore, India. His work primarily involves development of statistical models for firms in the banking, financial services and insurance sector.

Madhukar O. Garg is the director of CSIR-Indian Institute of Petroleum in Dehradun, India. He has 35 years of research experience in the field of refining and petrochemicals. Dr. Garg specializes in the area of liquid-liquid extraction, modeling and simulation, process integration, advanced control and process conceptualization. He obtained his Ph.D from the University of Melbourne. Dr. Garg has developed and commercialized several technologies and has been awarded two CSIR Technology Shields for his commercialization efforts. He has published 213 papers and holds 26 patents. He is also a Fellow of the Indian National Academy of Engineering.

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Improve catalyst management at the FCC unitSystem revamp reduces unloading time, boosts refinery operations

M. L. SARGENTI, N. ERGONUL and M. SCHERER, Grace Catalysts Technologies; H. UPADHYAY, R. McCLUNG and T. S. W. AL RAWAHI, Orpic Sohar Refinery

T he performance of the fluid catalytic cracking (FCC) unit benefits from the stable and consistent addition of catalyst to the unit. For the regular addition of fresh catalyst, the

best practice is to ensure steady activity in the inventory and mini-mize upsets typically caused by slug additions of fresh catalyst.

However, catalyst management in the FCC unit is important during a number of activities associated with the FCC, and the risks and costs of mismanagement can be magnified if a large volume has to be moved every day. The Orpic Sohar refinery in Oman sought to improve the injections of normal catalyst, equi-librium catalyst (Ecat) and additives, and to find an optimum solution to the hoppers’ configuration while improving the fresh catalyst unloading system, which is described in this article.

Orpic Sohar site description. The Sohar refinery, located 220 kilometers (km) northeast of Muscat in Oman, is the larger of the country’s two refineries. With a production capacity of 116,000 barrels per day (bpd), the refinery’s main products (gaso-line, propylene and diesel) are distributed to different markets inside and outside of the country.

The FCC unit typically processes 100% atmospheric residue, and approximately 2% of the total catalyst inventory is rejuve-nated with fresh material every day. Between 20 metric tons per day (mtpd) and 30 mtpd of fresh catalyst combined with addi-tives and/or Ecat (depending on the operational requirements) are injected daily.

Catalyst and additive injection system. In the original design setup, four hoppers were used for the storage of fresh FCC catalyst, Ecat and a ZSM-5 additive. Over the last year, a spe-cifically customized, multi-component database and information system (DAIS) for the simultaneous addition of various additives was installed to enable the refinery to operate at maximum flex-ibility and reliability.1

Due to the particular setup of the refinery, a technical visit prior to the installation of the addition device was necessary to determine the optimal location of the DAIS units and to design the proper connections between the hoppers. Catalyst injection is an intensive operation, since the volume managed in the daily additions is substantial. Therefore, it was suggested that two multi-component DAIS system units be installed, for operation on a standby basis. With this solution, it is possible to constantly main-tain an uninterrupted dosage of fresh catalyst into the FCC unit.

An additional flow bin was included to allow separate injections of a combustion promoter, if required, as shown in Figs. 1 and 2.

Revamp of catalyst unloading system. In the conven-tional operation, approximately 20 to 30 super sacks of fresh cata-lyst, weighing 1,000 kilograms each, were unloaded every day into

Design schematic of catalyst and additive injection system.FIG. 1

Sohar refinery catalyst and additive injection system.FIG. 2



the storage hopper (Fig. 3). The handling of such a large volume of material was a time-intensive and environmentally unfriendly operation. In addition, during the catalyst unloading, inevitable dust generation caused catalyst losses and limited maintenance activities in the area.

An effective way to avoid the handling of super sacks is to deliver larger volumes of catalyst and additives overseas in more suitably designed containers fitted with polyethylene bulk liners. However, this method requires specific facilities for unloading the trailer containers onsite.

Bulk-lined containers are the desired solution to safely and effectively transport catalyst overseas and to store large volumes of catalyst from the initial production site for shipment to the end user at the refinery. For the operation at the Sohar refinery, trailer tipping equipment was supplied to allow the plant to change from the traditional super sack delivery method to the safer, cleaner container system, while also providing a second backup system.

This solution was easily and successfully installed onsite, with-out the need for extra engineering and construction. The frame is adjustable to various trailer heights, and can accommodate a trailer of up to 40 feet without the front car. The maximum capacity is 35 mt, including the trailer tilting chassis. In this system, the truck drives the container onto the frame, the truck is removed, and the whole trailer is then fixed while being tilted backwards. After the container is emptied, the truck pulls away as the new supply arrives, as shown in Fig. 4. The catalyst is then

transported into the storage hopper by a proprietary piping system (Fig. 5). This easy-to-use system is operated by a vacuum, which substantially reduces the time of the unloading operation. While one trailer is being unloaded, a second trailer can be prepared for unloading on a second tilting chassis.

Improved operation and benefits. Implementing the above-mentioned solutions in a holistic approach allows for a large reduction in dust generation while handling the fresh catalyst. The reduced dust generation within the process areas could decrease the number of hours spent on site cleaning and housekeeping. Additionally, the lesser dust generation represents a safer and more pleasant working environment for operations personnel.

The reduced manual handling of catalyst, on the other hand, can be used either to free operator hours for other duties or to reduce site costs accordingly. For example, the number of contract personnel performing the manual handling can be reevaluated, or the personnel can be assigned to new duties.

In conclusion, the use of the newly implemented, multi-com-ponent DAIS system and the custom-built container offloading facilities at the Sohar refinery allowed the plant to operate at maxi-mum flexibility and reliability. Lastly, the unloading process for the daily consumption of catalysts was considerably simplified and shortened to around one quarter of the previous time required. HP

1 DAIS units are exclusively manufactured for Grace by Pneumix.

Design schematic of container trailer tipper facility.FIG. 4

Sohar refinery vacuum piping system.FIG. 5

Nathan Ergonul is a technical sales manager at Grace Catalysts Technologies.

Talal Said Wasser Al Rawahi is a senior process engineer at the Orpic Sohar refinery in Oman.

Robert McClung is the general manager of technical services at the Orpic Sohar refinery in Oman.

Hemant Upadhyay works as a senior process engineer at the Orpic Sohar refinery in Oman.

Matthias Scherer is director of sales for administration and logistics at Grace Catalysts Technologies.

Maria Luisa Sargenti holds the position of technology coordination manager at Grace Catalysts Technologies.

Super sacks previously used to unload fresh catalyst.FIG. 3

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Operational optimization for mixed-refrigerant systemsUse rigorous simulation to improve process efficiency

J. ZHANG, Q. XU and K. LI, Dan F. Smith Department of Chemical Engineering, Lamar University, Beaumont, Texas

R efrigeration systems are among the most critical operating systems in the chemical processing industry. A refrigeration system generally works by removing heat from low-temper-

ature streams and transferring it to higher-temperature streams through vapor-compression cycles at the expense of mechanical work, magnetism, laser or other means.1

Since a refrigeration system can cool down a process stream far below the ambient temperature, it is indispensable to cryogenic cooling and separation operations in many chemical industries, such as the large-scale production of ethylene, oxygen, nitrogen and liquefied natural gas (LNG). Refrigeration systems may employ a single compound as the refrigerant, as long as it is envi-ronmentally safe (e.g., nontoxic), thermodynamically desirable (e.g., having a sufficiently low boiling point, high latent vapor-ization heat and high critical temperature), and operationally feasible (e.g., noncorrosive).

A multi-component mixture can also be used as the refriger-ant.2 From a thermodynamic viewpoint, a mixed-refrigerant

system (MRS) provides refrigeration over a range of tempera-tures, with smaller temperature differences at the lower temper-atures. This leads to a smaller increase in entropy, or a smaller loss of energy.3

The MRS has many inherent advantages over a traditional single-component refrigeration system (SCRS), which has led to the application of MRS in new chemical processes. For example, an ethylene plant may need to process various streams with tem-peratures ranging from +40°C to –140°C. In the conventional refrigeration method, this broad temperature range is accom-plished by a cascade refrigeration system, where three single-component refrigeration subsystems are integrated together. Each refrigeration subsystem will employ a compressor, a set of flash drums, and many other types of auxiliary equipment.

To reduce capital costs and the operational complexity of the refrigeration system, an ethylene plant can employ a single refrigeration system with mixed refrigerants to accomplish the same refrigeration task.4 Thus, the number of compressors is

MIX3

MIX6

MIX1

MIX2

EE-13

EC-6EC-4EC-3

EC-1EC-7

FD-2 FD-3

FD-4

FD-5

EC-2

EC-3

EE-8 EE-9

EC-9

EC-8

EC-1

EC-10

C-3C-2

V-12

V-9

V-10FD-1

C-1 MIX5

V-1

EE-5V-1

EE-6V-4

EE-7V-3

V-6

SPL2

SPL3

SPL5

SPL4

EC-2V-2EC-5

EC-4

V-11

EC-12EC-11

V-7

V-8

Flowsheet of an MRS.FIG. 1



reduced from three to one, and over 25 pieces of equipment are saved. It has been reported that the introduction of a mixed-refrigerant system can reduce the capital cost of the entire eth-ylene plant by 7%.5

This article describes the operating performance of an MRS used in an ethylene plant that was studied through rigorous simu-lation. Insights on the MRS working mechanism are presented. Based on the simulation, optimization strategies have been devel-oped to improve the MRS operation under the disturbance of cooling-water temperature change.

Process description of an MRS. The studied MRS, which contains a mixed refrigerant of 0.1 wt% H2, 11.7 wt% CH4, 17.6 wt% C2H4, and 70.6 wt% C3H6, is used for an ethylene plant. As shown in Fig. 1, the refrigeration system has a three-stage compressor. All three compressor stages have suction drums to buffer inlet pressures and knockout liquids if any leak out of the compressor. The first stage (C-1) compresses the refrigerant from a pressure of 0.16 MPa to 0.61 MPa. The outflow of C-1 mixes with the vapor flow from suction drum FD-2 and then goes to the second stage (C-2), which compresses the refrigerant from 0.61 MPa to 1.02 MPa.

The outflow of stage C-2 is partially condensed, by cooling water, to 32°C, and then goes into another suction drum (FD-3) together with a mixed vapor flow from evaporators EE-5, EE-6, EE-7 and EE-9. About 88% of the FD-3 vapor flow goes to

the third stage (C-3). The rest of the vapor flow moves through coolers EC-4, EC-5 and EC-6, which reduces its temperature to −12°C. Then, the stream is flashed in drum FD-4 at 0.79 MPa to vapor and liquid streams at a temperature of −16°C. The vapor stream is used in evaporator EE-10, while the liquid flow is used in evaporator EE-13.

In the third stage (C-3), the refrigerant is normally compressed from 1.02 MPa to 3.0 MPa, with a flexibility of ±0.2 MPa for the output pressure. The output refrigerant of C-3 is partially condensed to 32°C in EC-2 by the cooling water. The condensate temperature may change from 29°C to 34°C due to the amount of cooling water and the inlet temperature.

The mixed refrigerant is separated into high-pressure light mixed refrigerant (HP-LMR) and high-pressure heavy mixed refrigerant (HP-HMR) in flash drum FD-5. HP-LMR is the vapor output of the flash drum, and HP-HMR is the liquid out-put. The compositions of HP-LMR and HP-HMR vary with EC-2 output temperature and C-3 output pressure. When the temperature is 29°C and the pressure is 2.8 MPa, the composition of HP-LMR is 0.2 wt% H2, 26.7 wt% CH4, 25.4 wt% C2H4 and 47.7 wt% C3H6; while the composition of HP-HMR is 5.7 wt% CH4, 14.5 wt% C2H4 and 79.8 wt% C3H6.

HP-LMR has the lower boiling point in the refrigeration sys-tem, and can refrigerate process streams to −130°C. HP-LMR is used at evaporators EE-1, EE-2, EE-3 and EE-4 in the chilling train section. It refrigerates the charge gas to −127°C, liquefying most of the C2 and heavier components, while the hydrogen and methane remain in the gas phase. The liquid-phase and gas-phase charge gases are separated by flash drums. The liquid flows to the demethanizer tower, and the gas flows to the Joule-Thompson expansion process to separate hydrogen from methane. After passing through evaporator EE-4, the HP-LMR goes into a pure vapor state, and then travels to the C2 splitter’s overhead condenser EE-13 as the cooling utility.

The HP-HMR has the higher boiling point in the refrig-eration system. About 38% of the HP-HMR is used in EE-5, EE-6, EE-7 and EE-9 to refrigerate the charge gas, hydro-gen and methane flows to 15°C. After that, the HP-HMR goes to the suction drum of C-3. The rest of the HP-HMR is used to condense the overhead stream from the low-pressure depropanizer tower to or under −20°C. After that, it travels to the suction drum of C-2.

TABLE 1. Statuses of process streams in MRS evaporators and coolers

Heat Input Output duty, temp., temp.,Name Type GJ/hr °C °C Description

EE-1 Evaporator 12.4 −102 −127 Charge gas condenser




EE-5 Evaporator 17.9 32 14 Charge gas condenser

EE-6 Evaporator 22.2 45 14 Caustic tower cooler

EE-7 Evaporator 1.0 31 15 Hydrogen cooler

EE-8 Evaporator 2.5 23 8 Refrigerant inter-cooler

EE-9 Evaporator 28.8 37 11 Methane cooler

EE-10 Evaporator 15.7 2 −20 Depropanizer condenser


EE-12 Evaporator 1.4 23 −14 Refrigerant inter-cooler

EE-13 Evaporator 144.1 −35 −36 C2 fractionator condenser

EC-1 Cooler 31.9 27 35 Water cooler

EC-2 Cooler 272.5 27 35 Water cooler

EC-3 Cooler 6.9 −39 −38 Ethane heater

EC-4 Cooler 25.9 −12 −11 C2 fractionator reboiler

EC-5 Cooler 5.3 −19 −16 C2 fractionator side-draw reboiler

EC-6 Cooler 0.7 −20 −19 Refrigerant inter-heater

EC-7 Cooler 119.2 −132 30 Charge gas heater

EC-8 Cooler 14.9 −15 30 Ethylene product heater

EC-9 Cooler 23.3 −18 8 Refrigerant internal heater

EC-10 Cooler 1.6 −27 −15 Ethylene product heater

0 50 100 150 200 250 300 350 400 450 500 550-150

-100

-50

0

50

100

Enthalpy, GJ/hr

Tem

pera

ture

, °C

Theoretical powerneeded from

the compressor

Pinchpoint

MR in evaporators

Hot process flows

Cold processflows

MR in condensers

Cooling water

MR in compressors

Temperature-enthalpy diagram of the MRS.FIG. 2



HP-LMR finally mixes with the liquid flow from FD-4 and goes to EE-13 to condense the overhead stream of the C2 splitter to under −35°C. Evaporator EE-13 has the largest cooling duty among all of the evaporators in the refrigeration system. The HP-LMR flow is in pure vapor phase, which gives a small amount of cooling duty. Most of the cooling duty of EE-13 is provided by the liquid flow from FD-4.

Modeling and operational optimization. A rigorous simulation model has been developed based on the aforemen-tioned process description. The thermodynamic package used in this simulation is the Peng-Robinson cubic equation of state with the Boston-Mathias alpha function. During the simula-tion, the minimum temperature difference is set at 2°C, and the minimum temperature difference in normal heat exchangers is set at 5°C. A compressor efficiency of 0.72 is used in this case. To check the performance of the MRS operation, the normal process operation condition has been simulated as the base case. In the base case, the process stream status in each evaporator and cooler is fixed as input (see Table 1); C-3 outlet pressure is fixed as 2.8 MPa.

Based on the simulation results, Fig. 2 presents the temper-ature-enthalpy diagram to describe the composite hot and cold flows of the entire MRS. The MR hot-flow curve represents the refrigerant as it undergoes condensing operations in various condensers. Thus, the refrigerant functions as the hot stream, and the heat will be removed from it. The released heat will be transferred to cooling water at higher temperature and the cold process stream at lower temperature.

However, contrary to the simulation results, the MR cold-flow curve represents the refrigerant as it undergoes evaporating opera-tions in various evaporators, where the refrigerant functions as the cold stream for absorbing heat. The absorbed heat/energy comes from the compressor and the hot process stream at lower tem-perature. Note that, since the minimum temperature difference is set at 2°C, the pinch point lies at a temperature of −20°C. Also note that the horizontal distance of the dashed line represents the theoretical power provided by the compressor. When compressor

24.0 25.0 25.5 26.0 26.5 27.0 27.5 28.0 28.5 29.02.7

2.8

2.9

3.0

3.1

3.2

3.3

24.5

Com

pres

sor o

utpu

t pre

ssur

e, M

Pa

Cooling water temperature, °C

38,000

39,000

40,000

41,000

42,000

43,000

44,000

45,000

46,000

47,000

Tota

l com

pres

sor w

ork,

kW

Profiles of total compressor work and compressor outlet pressure under various cooling-water temperatures.

FIG. 3




efficiency is known, the total energy consumption of the compres-sor will be identified. Obviously, any operational changes to the process streams or MRS will result in a corresponding energy flow change in the temperature-enthalpy diagram.

Note that, in the simulated base case, a large amount of the cooling-water temperature is set at 27°C. If the cooling-water temperature is changed due to a seasonal temperature difference, it will influence the MRS cycles and cause operational problems. Therefore, the optimal strategy for operating an MRS under

the disturbance of cooling-water temperature is presented in this article.

Assume the cooling-water temperature ranges from 24°C to 29°C. When the cooling-water temperature decreases, the opera-tional temperature of FD-5 will also decrease. Thus, the amount of HP-LMR will respectively decrease because the vapor fraction of FD-5 will decline with lower temperature. This would make HP-LMR hard to guarantee for the heat duties for evaporators EE-1 and EE-3. To balance it, the compressor output pressure should be decreased to raise the vapor fraction of FD-5. There-fore, the C-3 output pressure should be suitably adjusted within the feasible operating range.

The disturbance of cooling-water temperature also influences the heat duty of EE-13. Note that HP-LMR travels to evaporator EE-13, which has the largest heat duty among the evaporators. When the cooling-water temperature increases, the temperature of the HP-LMR flowing to EE-13 will also increase. Therefore, the HP-LMR will not be able to provide enough heat duty to EE-13. To handle this problem, the amount of liquid flow from FD-4 should be increased to provide enough heat duty to EE-13.

Based on the developed simulation model, nine case studies have been conducted for a cooling-water temperature change from 24°C to 29°C. Since the main manufacturing process should not be affected, the operating statuses of all process streams in these nine cases are unchanged. This means that the input flowrate, temperature, pressure, composition and output temperature of all process streams are still the same as those shown in Table 1.

Fig. 3 shows simulation results of the nine case studies under var-ious cooling-water temperatures. The related total compressor work

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2.80 2.85 2.90 2.95 3.00 3.05 3.10 3.15 3.2041,500

42,000

42,500

43,000

43,500

44,000

44,500

45,000

45,500

46,000

46,500

Compressor output pressure, MPa

Tota

l com

pres

sor w

ork,

kW

Simulation results of compressor work consumption and compressor output pressure.

FIG. 4


AD00133




and the compressor outlet pressure can be simultaneously obtained from this figure when the cooling-water temperature is given. Thus, Fig. 3 actually provides optimal MRS operation strategies under the disturbance of cooling-water temperature. For instance, if the cooling-water temperature is 28°C, the appropriate compressor out-let pressure should be controlled at 3.15 MPa. Under this scenario, the compressor will consume 45,410 kW of energy.

Fig. 4 provides more insight into the total compressor work and the compressor output pressure. It shows that, when the compressor output pressure increases from 2.8 MPa to 3.2 MPa, the total compressor work increases from 41,836 kW to 46,381 kW. Although lower pressure will reduce compressor work con-sumption and operational cost, it will require lower cooling-water temperature. Therefore, the simulation results provide an effective way to handle this issue. HP

ACKNOWLEDGMENTThis work was supported in part by the Texas Air Research Center (TARC)

and the Texas Hazardous Waste Research Center (THWRC).

LITERATURE CITED 1 Vaidyaraman, S. and C. D. Maranas, “Optimal synthesis of refrigeration cycles

and selection of refrigerants,” AIChE Journal, Vol. 45, Issue 5, May 1999. 2 Lee, G. C., R. Smith and X. X. Zhu, “Optimal synthesis of mixed-refrigerant

systems for low-temperature processes,” Ind. Eng. Chem. Res., Vol. 41, Issue 20, 2002.

3 McKetta, J. J., Encyclopedia of Chemical Processing and Design, Vol. 28, Marcel Dekker Inc., pp. 213-221, New York, New York, 1988.

4 Mafi, M., M. Amidpour and S. M. Mousavi Naeynian, “Development in mixed refrigerant cycles used in olefin plants,” Proceedings of the 1st Annual Gas Processing Symposium, Elsevier, 2009.

5 Stanley, S. J., R. Thakral and J. deBarros, “Changing the ethylene plant process chemistry and flowsheet configuration for improved return on invest-ment,” Petrotech 2009, New Delhi, India, 2009.

Jian Zhang is a research associate at the Dan F. Smith Depart-ment of Chemical Engineering at Lamar University. He has five years of experience in planning and scheduling for the petroleum and petrochemical industries. He holds BS and MS degrees, as well as a PhD, all in chemical engineering, from Tsinghua University in

China. Dr. Zhang’s research interests include process planning and scheduling, process simulation, process optimization and synthesis, and industrial waste minimization.

Qiang Xu is an associate professor at the Dan F. Smith Depart-ment of Chemical Engineering at Lamar University. He holds BS and MS degrees, as well as a PhD, all in chemical engineering, from Tsinghua University in China. His research interests include process modeling, scheduling, dynamic simulation and optimiza-

tion, industrial pollution prevention, waste minimization, and chemical process safety and flexibility analysis. Dr. Xu’s research work on proactive flare minimization and environmentally benign manufacturing has been extensively supported by TCEQ, TARC, THWRC, the US Department of Defense and industry.

Kuyen Li is a professor at the Dan F. Smith Department of Chemical Engineering at Lamar University. He received BS and MS degrees in chemical engineering from Cheng Kung University of Taiwan and a PhD in chemical engineering from Mississippi State University. His research interests include air pollution control by

dynamic simulation and advanced oxidation, advanced remediation methods for contaminated soil and sludge, and industrial wastewater treatment by biological and advanced oxidation methods. His research work has been strongly supported by the US Environmental Protection Agency, TCEQ, TARC and industry.

Engineering advanced© 2012 Chemstations, Inc. All rights reserved. | CMS-322-1 2/12

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Consider new economics for purification on a small scaleFor smaller methanol units, new designs balance energy cost against capital cost for long-term profitability

K. PATWARDHAN, G. SATISHBABU, S. RAJYALAKSHMI and P. BALARAMKRISHNA, R&D Center, Hydrocarbon IC, Larsen and Toubro, Powai, Mumbai, India

C rude methanol (MeOH) distillation is an energy intensive separation process and it contributes significantly to the total production cost. It is very important to choose the

right distillation configuration for MeOH purification. In the following study, a two-column configuration is compared with a three-column configuration with forward- and backward-heat integration schemes. Approximately 38% reduction in low-pres-sure (LP) steam consumption is observed in a three-column con-figuration case as compared to the base case for a small capacity plant (about 230,000 metric tpy). Further energy reductions for a three-column configuration is possible with a backward-heat integration scheme.

KEY PETROCHEMICALMethanol is one of the most important petrochemicals. It is

extensively used as a feedstock in the production of chemicals such as formaldehyde, methyl tertiary-butyl ether (MTBE), tertiary amyl methyl ether (TAME) and acetic acid. It is also a hydrogen source in fuel cells used in automobiles. The majority of MEOH is produced through steam reforming of natural gas; other processing methods include use of petroleum fractions and process offgas. The MeOH manufacturing process can be divided into three major sections: feedstock purification and syngas generation, compression and MeOH synthesis, and MeOH purification. Fig. 1 is a general flow diagram of a MeOH facility using natural gas as the feedstock.

The three process sections may be considered independently, and technology may be selected and optimized separately for each section. The normal criteria for technology selection are capital cost and plant efficiency.

In a conventional natural gas-based MeOH plant with a capacity of 2,500+ met-ric tpd, syngas generation accounts for 55% of the total capital cost, distillation accounts for 12%, compression and MeOH synthesis accounts for 12%, and utilities and other services account for 24%.

Methanol purification. Crude MeOH, as removed from the synthesis section, contains water, higher alcohols, impurities and light ends. Table 1 summa-

rizes the typical composition of crude MeOH obtained through commercial processes. US federal-grade specification OM-232e identifies three grades of MeOH. Grade “C” is for wood alcohol used in denaturing. Grade “A” covers methanol generally used as a solvent. Federal-grade “AA” is the purest product. It is used for petrochemical/chemical applications in which high-purity and low-ethanol content are required, such as for MTBE, methyl amines manufacture, etc. The general standard observed by the chemical industry for MeOH product purity is US federal-grade “AA”. Another known methanol grade is fuel-grade; it is used as a blending component for gasoline.

Purification schemes. Crude MeOH is purified by distil-lation with one- or two- or three- or four-column configuration. Fuel-grade methanol is normally produced with a single distillation tower. But to produce federal-grade “AA” methanol, two-, three-, and, sometimes, even four-tower distillation systems are used. The amount of distillation required depends on the byproduct forma-tion of the MeOH synthesis catalyst and plant capacity.

The economics of the purification scheme involves the com-plex relationship of plant capacity, available heat, energy export and customer requirements, etc. For example, the four-column configuration is justified only at large capacities such as 5,000 metric tpd of MeOH production. The two- or three-column configuration depends on the customer’s requirements and energy availability in the front end.

Single-column configuration. For fuel-grade MeOH as a blending component, the major demands regarding quality are water content and dissolved gases. Fuel-grade MeOH should

Reformingtechnologies1. Steam2. Combined3. Autothermal

Reactortechnologies1. Isothermal2. Adiabatic

Distillationtechnologies1. Single column2. Multicolumn

Desulfurization Syngasproduction Compression MeOH

synthesisMeOH

distillation

Naturalgas MeOH

General flow diagram for a natural-gas based MeOH facility.FIG. 1



be dissolved-gas free and not contain more than 500 wt-ppm of water. The limitation on water content is due to its immiscibility with gasoline (Fig. 2).

Multi-column configuration. Condensate from the synthe-sis loop is generally purified in two stages using conventional dis-tillation columns at pressures slightly above atmospheric pressure. The first distillation stage is for light ends removal, and is carried out in a single-distillation column known as the topping column. This column acts as a refluxed stripper. Liquid feed enters near the top stage, and MeOH vapor generated in the reboiler strips the light ends—such as dimethyl ether (DME), methyl formate and acetone—and residual dissolved gases from the crude MeOH.

The main area of investigation is the second stage of MeOH purification. This is the MeOH refining stage, where MeOH is recovered as the overhead product from one or more distillation columns. Water is withdrawn as the bottoms product. Middle boiling impurities (principally ethanol, but also higher alcohols, ketones and esters), are referred to as fusel oil and are withdrawn as a side stream below the feed stage.

The side stream enables MeOH production to US federal specification O-M- 232K Grade ‘‘AA’’. In a typical two-column MeOH purification scheme, as shown in Fig. 3, about 20% of the total heat for purification is associated with the topping column. The remainder is required to separate MeOH from ethanol and water. This basic arrangement is widely reported in the literature.1,2

With the sharp rise in energy costs, MeOH technology licensors and operators have focused attention on alternatives

to this standard two-column arrangement.2–8 A double-effect three-column scheme was developed, and it is widely applied.4 A number of these alternative schemes involve splitting the refin-ing column into two separate columns that operate at different pressures, such that the overheads of the higher pressure column can be used to reboil the lower pressure column. Several novel energy-saving three-column distillation configurations have been explored in the literature.9

The capital cost of the three-column schemes is significantly greater than the standard two-column arrangement. The three-column distillation unit consists of a topping column and two refining columns. Refining column II operates at normal pressure. Refining column I operates at a higher pressure, thus utilizing the condensation duty of this column as reboiler duty for refining column II. This substantially reduces the LP steam consumption of the distillation section. Another configuration of three-column systems is operating the refining column I at atmospheric pressure and refining column II at a higher pressure (HP).

Federal-grade “AA” MeOH is withdrawn close to the top of both refining columns. Although the three-column system is more costly, it can reduce the required distillation heat input by 30%–40%. Multi-column systems (three or more columns) can only be justified when energy costs are prohibitively high. The design of the MeOH distillation unit primarily depends on the energy situation in the front end. The two-column distillation unit rep-resents the low-cost unit, and the three-column distillation unit is the low-energy system. Multi-column designs maximize the yield and minimize LP steam consumption.

The four-column design (Fig. 4) includes the three columns described previously as well as an additional recovery column. The fusel oil purge from refining column II is processed in the recovery column to minimize MeOH losses. The distillation unit can be designed to limit the MeOH content in the process water to a maximum of 10 wt-ppm. The heat available from the front end (syngas generation) at a low temperature is efficiently used to minimize steam consumption. In four-column configurations, as high as 60% savings in the steam consumption can be achieved when compared to a two-column configuration.

Raw MeOH

LP steam

Process gas

Fuel-gradeproduct

Tail gas

Single-column configuration for an MeOH plant.FIG. 2

LPsteam

Recycle water

ProductMeOH

Liquid offsteam Reflux

drum 2

Processgas

Stabilizer MeoH pump

Higher alcohols

Refluxdrum 1

CrudeMeOH

Stabilizercolumn

Concentrationcolumn

Condenser 1 Condenser 2Stripped gas

Two-column configuration for an MeOH plant.FIG. 3

TABLE 1. Typical crude MeOH composition to purification section

Component Wt%

CO, CO2, H2, CH4, N2, DME, aldehydes, ketones 0.5–0.8

Methanol 88–90

Ethanol, higher alcohols (propanol, butanol, etc.) 0.1–0.6

Water 9–11



SIMULATION STUDYAn analysis was conducted for purifying “AA” grade MeOH

from crude MeOH through a two-column and three-column configuration using a commercially available process simula-tor. The results were validated with reference data available for the two-column scheme. The simulations were extended for the three-column configuration. In the three-column configuration, due to higher degree of freedom, one extra case is generated for the reboiler coupling. In forward-heat integration, out of the three columns, the first column is the topping column, as in the two-column case; the second is a HP refining column; and the third is LP refining column.

Total heat required for the HP column reboilers is provided by LP steam. Instead of using a cooling water heat exchanger to chill overheads of the HP column, heat is used to run the LP column reboiler. This is called forward-heat integration because heat integration is in the direction of material flow. The HP column is operated at a pressure of 7 to 10 atmospheres depending on feed composition. The LP column is operated near atmospheric pressure.

In backward-heat integration, the second and third columns are exchanged. In this scheme, the overheads from the third column (HP) supply heat for the second-column reboiler. The material and heat flow in opposite directions. The basic assumptions are:

• All trays behave ideally (tray efficiency is 100%).• Liquid reflux from the condenser is saturated at calculated

conditions.• Pressure drop/tray is 0.01 kg/cm2.• Negligible pressure drop occurs in reboiler and condenser.• Reductions or increases in the pressure between the columns

are achieved by the reduction valve and pump, respectively.• A 15°C approach (Δ temperature difference) is maintained

between LP column reboiling liquid and HP column overheads.Table 2 summarizes the simulation results for the Base Case of

two-column, three-column schemes with forward- and backward-heat integration configuration.

LP steam consumption in the two-column configuration is much greater than the three-column configuration, as the heat required for the concentration column is supplied by LP steam. In a three-column configuration, there is a possibility to couple the reboiler of one column with the condenser of another.

Temperature differences between utility (LP steam) and reboiler temperature decrease with increasing column pressure.

TABLE 2. Simulation results for column schemes

Two-column scheme

Stabilizer column Concentration column

No. of stages 38 80

Reboiler duty, Gcal/hr 5.20 25.53

Condenser duty, Gcal/hr 6.26 25.22

Diameter, m 1.84 4.10

Reflux ratio 132 2.21

Boil-up ratio 0.64 13.27

LP steam consumption, 1.3384metric ton/metric ton of MeOH

Three-column (forward integration) scheme

Stabilizer column HP column LP column

No. of stages 38 58 53

Reboiler duty, Gcal/hr 5.20 19.47 17.98

Condenser duty, Gcal/hr 6.26 17.98 19.09

Diameter, m 1.84 2.61 3.51

Reflux ratio 132 5.64 2.96

Boil-up ratio 0.64 3.45 9.44


Three-column (backward integration) scheme

Stabilizer column HP column LP column

No. of stages 38 55 58

Reboiler duty, Gcal/hr 5.20 17.46 17.85

Condenser duty, Gcal/hr 6.26 17.67 17.46

Diameter, m 1.84 3.36 2.62

Reflux ratio 132 2.70 5.00

Boil-up ratio 0.64 3.83 9.92


Processgas

StabilizerMeOH pump

Liquidoff

steam

Refluxdrum 1

Toppingcolumn

Condenser 1 Condenser 2

Strippedgas

LPsteam

Refluxdrum 2

HPcolumn

Reboiler3

Recycle water

Product MeOH

Reboiler2

Reboiler1

Higher alcohols

Refluxdrum 3

LPcolumn

CrudeMeOH

Three-column configuration (forward integration) for an MeOH plant.

FIG. 4A

Processgas

Liquidoff

steam

Refluxdrum 1

Toppingcolumn

Condenser 1 Condenser 2

Strippedgas

LPsteam

Refluxdrum 2

HPcolumn

Reboiler3

Recycle water

Product MeOH

Reboiler2

Reboiler1

Higheralcohols

Refluxdrum 3

LPcolumn

CrudeMeOH

Three-column configuration (backward integration) for an MeOH plant.

FIG. 4B



Thus, the reboiler requires a higher area for the same duty when compared to the base two-column configuration.

In the backward-heat integration scheme, due to altered col-umn sequencing (i.e., LP column preceding the HP column), around 60% of MeOH product is recovered in the first stage. It offers advantages in two ways:

1) Ease of separation (characterized by the relative volatilities) increases with decreasing operating pressure for a constant feed composition

2) Altered composition as compared to a forward-heat inte-grated scheme distillation can be done at a lower pressure in the HP column.

This reduces the heat duty on the HP column reboiler. The reverse heat integration results in more energy savings.

ECONOMICS OF METHANOL DISTILLATIONAn MeOH distillation complex involves distillation column,

reboiler, condenser, reflux tank, pump and associated column controls. The cost for each unit depends on various operating and design parameters. Fig. 5 summarizes the contribution of the individual costs to the total cost for the distillation setup under consideration. Cost contribution is higher for instrumentation in a three-column backward configuration than for a forward design due to the complex control system.

The capital cost in the case of the three-column configuration is more (12%–17%) than the two-column configuration due

to the additional column and associated equipment. It is very important that before adopting any of the listed schemes, a bal-ance between the fixed and operating costs is done.

Operating cost. The operating cost for the distillation column scheme under consideration includes cost for cooling water in the overhead condenser and steam in the reboiler. The operating cost of cooling water is governed by various factors such as ambi-ent conditions, electrical consumption in fans and cooling water pumps, water cost and chemical treatment. The cost of cooling water is taken as $0.2/m3.

The three-column configuration saves energy consumption in terms of LP steam supplying heat to the reboiler. The steam required is the operating cost, and it can be expressed in terms of natural gas consumption. The steam costs can be determined assuming water at available temperature is heated in a boiler by burning natural gas, and it can be expressed by:

Cost of steam, $ =M Cpw TB −Tref( )+ λ( )

LHVNG( )×ηBoiler

⎛

⎝

⎜⎜⎜⎜⎜⎜

⎞

⎠

⎟⎟⎟⎟⎟⎟⎟NGunit price( )

The three-column configuration saves energy. Thus, less natural gas is consumed via lesser steam demand by the reboiler. Almost 30%–40% savings can be realized by adopting either three-column forward configuration or three-column backward configuration. It also requires less coolant compared to a two-column scheme. But a

ColumnReboilerCondenser drum

CondenserPumpInstrumentation

76.68%9.58%3.36%0.27%7.18%

2.93%

77.52%7.75%4.27%0.28%3.15%

7.04%

84.69%4.23%2.58%0.34%2.56%

5.61%

(a)

(b)

(c)

Cost contribution to the capital cost of equipments for various configuration—A: two-column configuration, B: three-column forward integration configuration and C: three-column forward integration configuration.

FIG. 5

0 20 40 60 80 100 120 140

2-columnconfiguration

3F-columnconfiguration

3B-columnconfiguration

Relative cost

Operating costCapital cost

Relative capital/operating cost for column configuration.FIG. 6

0 20 40 60 80 100 120

2-columnconfiguration

3F-columnconfiguration

3B-columnconfiguration

Relative cost

LP steamCW

Operating cost contributions.FIG. 7



higher coolant flow is required in forward-integration scheme com-pared to a backward-integration scheme. Accordingly, operating costs are higher. Fig. 6 illustrates the combined effect. Operating costs are higher for a three-column configuration with forward integration, while, in others, marginal savings can be seen, as shown in Fig. 7.

New thinking. A comparison of the two- and three-column schemes for a medium capacity MeOH plant is presented here. The three-column scheme with backward-heat integration offers approximately 38% saving in LP steam as compared to two-column scheme. Although, in the three-column scheme, back-ward integration offers higher savings as compared to forward integration scheme, column control will be complicated, and more operating attention is necessary. HP

LITERATURE CITED 1 Pinto, “Methanol distillation process,” US patent 4,210,495, 1980. 2 Fiedler, E., G. Grossmann, D. B. Kersebohm, G. Weiss, and C. White,

Ullmann’s Encyclopedia of Industrial Chemistry, Wiley-VCH Verlag/ GMbH & Co., Weinheim, 2002.

3 Meyers, R. A., Handbook of SynfuelsTechnology, McGraw Hill, New York, 1984.

4 M. Harvey, “Methanol Distillation-Two and Three Column Schemes,” IMTOF, London, 1993.

5 Chiang, T. P. and W. L. Luyben, “Comparison of energy consumption in five integrated distillation column configurations,” Industrial Engineering Chemical Process Des. Dev., No. 22, 1983, pp. 175–179.

6 Wu, J. and L. Chen, “Simulation of novel process of distillation with heat integration and water integration for purification of synthetic methanol,” Journal Chemical Industrial Engineering, China, No. 58, 2007, pp. 3210–3214.

7 Liu, B. Z., Y. C. Zhang, P. Chen, and K. J. Yao, “Research on energy sav-ing process of methanol distillation,” Chemical Industry Engineering Progress, China, Vol. 27, 2008, pp. 1659–1662.

8 Douglas, A. P. and A. F. A. Hoadley, “A process integration approach to the design of the two- and three- column methanol distillation schemes,” Applied Thermodynamics Engineering 26, 2006, pp. 338–349.

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Dr. K. V. Patwardhan is a senior Process Engineer at R&D Cen-tre of Larsen & Toubro’s Hydrocarbon IC. He has five years of experi-ence in the field of process design, modeling, troubleshooting and optimization of ammonia, hydrogen and methanol process plants.

G. Satishbabu is a process engineer at R&D centre of Larsen & Toubro’s Hydrocarbon IC. He has been working in process simula-tion, design and engineering of ammonia and reforming technolo-gies for the last four years.

Mrs. Rajyalakshmi is process engineer at the R&D centre of Larsen & Toubro’s Hydrocarbon IC. She has three years experience in simulation and design of hydrogen and onshore gas processing projects.

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Use better designed turboexpanders to handle flashing fluidsNew models eliminate vibration problems and improve reliability

K. KAUPERT, Energent, Santa Ana, California

M illions of dollars or euros in revenue are creatively found by clever process engineers through flashing liquid tur-bines. These turbines convert a liquid into a vapor for

hydrocarbon processes. A flashing liquid turbine generates electric-ity and concurrently removes heat from the process fluid.

For simple electric-power-generation applications, the obvi-ous benefit of a flashing liquid turbine is generating power on a turbine shaft while a liquid is flashing. This power can be used to drive a generator. Examples of this case include waste-heat-recovery systems and geothermal plants where the so-called tri-angular power cycle approaches an ideal power cycle for sensible heat sources.1 But, the triangular power cycle requires a flashing liquid turbine to generate electricity.1

Energy efficiency. For petrochemical/chemical applications, a flashing liquid turbine also generates electricity, but this is only a small benefit. A much greater value is the heat removal from a flashing liquid, especially in a refrigeration cycle. In this example, the heat removed through the turbine shaft load results in a reduced specific input power for the refrigeration cycle. Examples of heat-removal benefits can be found in ethyl-ene plants, air-separation units, natural-gas liquids plants and natural-gas liquefaction operations.2

The reduced refrigeration input power resulting from heat removal from process fluids can have 10 to 20 times greater value than the electric power generated. For a 3-MW flashing liquid turbine, the benefits are €1 million/yr in electric power produced plus €20 million/yr in heat rejection. This rejected heat translates to input power that can be saved by the compres-sors in the refrigeration cycle, thus reducing the specific input power for the cycle.

The industrial demand for flashing liquid turbines is not new. It existed in the 1960s. Since then, many lessons have been learned on “how to” and “how not to” design flashing liquid turbines. Initially, many attempts tried to adapt exist-ing thermal or hydraulic turbines for operation with flashing liquid flow. As shown in this article, those attempts met with some success for very small vapor quantities in the liquid, e.g., a turbine-outlet vapor-volume fraction less than 10%. For moderately higher vapor-volume fractions, these early “adapted” machines had poor thermodynamic performance and were unreliable. With such poor performance, major turbomachinery manufacturers abandoned flashing liquid tur-bines until their more recent resurgence.

History of flashing liquid turbines. The most obvious development path for flashing liquid turbines is to adapt exiting thermal and hydraulic turbines to handle a flashing liquid. This was attempted initially by NASA in the 1960s using radial-inflow centrifugal turbines. The results were unsatisfactory in terms of efficiency and vibrations. Later, in the 1980s, other companies again tried the radial-inflow centrifugal turbine for handling flash-ing liquids. This attempt, likewise, had poor efficiency and high vibrations when the vapor-volume fraction at the turbine outlet rose above 10%.3,4 Figs. 1 and 2 show results from both studies.

In Fig. 1A, the liquid was not actually flashing; rather, air was added to the water in closely controlled amounts. The turbine was a three-stage centrifugal pump operating in reverse. The mass vapor fraction reaches 0.002 (a vapor-volume fraction of nearly 30%) and the efficiency drops by more than 20 points. The effi-

0.0

0.2

0.4

Pres

sure

coe

ffici

ent,

�(–

)Ef

ficie

ncy 0.6

0.8

0.8

Gas content X (–)x = 0.002

x = 0.001

x = 0.0005

x = 0.0005

0.05 0.01 0.15Flow coefficient, �(–)

0.2 0.25

x = 0.001 x = 0.002x = 0

x = 0

1.2

1.6

2.0

2.4

2.8

Performance of three-stage centrifugal pump operatingas a radial-inflow centrifugal turbine with water andchanging air content.4,5

FIG. 1A

ROTATING EQUIPMENTBONUSREPORT


ciency degradation is summarized in Fig. 1B, as a function of the vapor-volume fraction in the liquid. In Fig. 2, an eight-stage cen-trifugal pump was operated in reverse and a hydrocarbon mixture was flashed through the machine. The turbine outlet fluid had 35% vapor volume. The measured efficiency is five points lower than with a single-phase nonflashing liquid.

Due to performance deteriorations, the radial-inflow centrifu-gal turbine was abandoned by the turbomachinery community for use with flashing liquids. It was correctly reasoned that the centrifugal field, which is the functioning basis for radial-inflow turbines, acts as a centrifugal separator between liquid and vapor. Such action leads to poor efficiency as the vapor-volume fraction increases at the impeller inlet. An upper limit of near 0 is set on the amount of vapor that can be flashed before the flow enters the cen-trifugal impeller. From a design perspective, this can be reviewed in

the example P vs. h diagram of Fig. 3. For example, a 0.5 degree of reaction is assumed for the centrifugal turbine, although this could easily be lower for greater enthalpy drop in the nozzles. If vapor forms in the nozzle before entering the impeller, then efficiency deteriorates and vibration levels rise. This is due to the centrifugal separator effect, as the vapor and liquid have different densities. The radial-pressure gradient acts on each phase with dP/dr = �V�

2/r where P is the pressure, r is the radius, � is the density and V� is the tangential velocity. If the liquid begins to flash well inside the turbine impeller near the turbine outlet and not in the nozzle, then satisfactory performance for very low-vapor-content liquids can be achieved by the centrifugal turbine. The centrifugal field is not as strong near the impeller outlet. However, vibrations will still be problematic due to flashing liquid in the rotating impeller.

The poor performance and high vibrations caused by flashing liquids in radial-inflow centrifugal turbines were the motivation for NASA and the Jet Propulsion Laboratory (JPL) to embark on developing a new way to expand flashing liquids. The driving application was a magnetohydrodynamic power system project.5

The flashing liquid turbine methodology applied at JPL was a linear nozzle expansion of the flashing liquid flow, avoiding curvature and ensuring close coupling between the expanding vapor and liquid droplets. This method proved highly successful; it produced the maximum conversion of available enthalpy drop to the nozzle out-let kinetic energy. The successful nozzle design was applied to a pure axial-impulse turbine impeller. The new style of turbine, as shown in Fig. 4, was an axial-impulse turbine, similar to an axial cross-flow impulse turbine or even similar to a Pelton style impulse turbine.6

Simple physics. In a radial-inflow centrifugal turbine, any flashing liquid flow will be separated by a centrifugal field into liquid and vapor. This is the basic functioning principle of a centrifugal separator or a centrifuge. The heavier liquid is slung outward, while the lighter vapor passes inward and a sizable recir-culation pattern is formed within the liquid-vapor mixture. This causes substantial mixing losses and efficiency degradation. Fur-thermore, the liquid droplets in the liquid-vapor mixture are large and uncontrolled in size. This has the consequences to generate entropy by flow and contribute to total flow losses. The simple slip velocity of a liquid droplet in a vapor stream is given by:

Vs = Vv – Vl

where Vs is the slip velocityVv is the vapor velocityVl is the liquid droplet velocity.A larger slip velocity logically leads to larger entropy losses due

to friction, wakes and mixing.7 Entropy losses will always be gener-ated due to the interphase exchange process of mass, momentum and heat transfer due to the phase change occurring from liquid to vapor. A low slip velocity will reduce these losses and lead to the highest efficiency during the flashing process. The size of the liquid droplets during flashing can be determined by examining a force balance between the two forces acting on the liquid droplet. These forces include drag force, due to the slip velocity, and buoyancy, due to the pressure gradient in the flow. In the Lagrangian reference frame (the frame moving with the particle), the force balance is:8

(Dynamic pressure of relative gas flow) � (Drag coefficient) � (Frontal area of droplet)(Volume of droplet) � (Pressure gradient) = (Mass of droplet) � (Droplet acceleration)

Turb

ine

effic

ienc

y, �

0.04 0.06 0.08 0.10 0.12Flow coefficient, �

Measurements with35%-40% outlet vapor

Single-phasemeasurements

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

Turbine efficiency vs. flowrate coefficient as measured on aneight-stage radial-inflow centrifugal turbine.

FIG. 2

0.6

0.8

1.0

1.0

1.1

1.2

1.3

Effic

ienc

y,Ef

ficie

ncy,

�TP

/�SP

L––

–�

TP�

SPL

0.0 0.1 0.2 0.3 0.4Void fraction, z

1.0 bar back pressure3.45 bar back pressure5.9 bar back pressure7.85 bar back pressure

Efficiency and energy correction factors due to vapor in a radial inflow centrifugal turbine. For a vapor-volume fraction of 30%, the 20 points decrease in efficiency from 1 to 0.8 can be seen.4

FIG. 1B



(0.5�vVs2) (Cd ) (πD2/4) – (πD3/6) (dP/dx) =

(�l πD3/6) (Vl dVl /dx)Vs 2 = 4D[�l(Vl dVl /dx) + (dP/dx)]/(3�vCd )

where �v is the vapor densityCd is the drag coefficient along a linear direction x�l is the liquid densityP is the pressureD is the liquid droplet diameter.The final equation shows that larger droplet diameters lead to a

larger slip velocity and larger efficiency losses. When expanding a liquid to vapor through a turbine, large droplet diameters should be avoided to achieve the highest efficiency. This is the motiva-tion for a controlled linear acceleration of the flashing liquid, to provide a fine small-diameter uniformly distributed mist that has a small slip velocity. Curvature of the flashing flow must be avoided to ensure that the vapor mist is uniformly formed and distributed.

During a controlled linear acceleration of the flashing liquid, the maximum droplet diameter can be found from the Weber number (We). We is proportional to the ratio of the pressure force breaking up the liquid droplets to the surface tension force holding the drops together:

We = �v D(Vv – Vl )2/2�

where � is the surface tension. Based on several experimental data sets in the literature, setting We equal to 6 for liquid droplet breakup is appropriate in linear acceleration nozzles.6,8 This gives a maximum liquid droplet diameter of:

Dmax = 12�/�vVs2

Example. If we take the following values for a methane-rich hydrocarbon flashing liquid at a nozzle exit, the representative values of � = 0.013 N/m, �v = 3.5 kg/m3, Vs = 60 m/s give Dmax = 12.4 �m as the largest liquid droplet size during a controlled linear acceleration of the flashing flow. This is a very small diameter-sized mist, which is dispersed in the vapor to make up the liquid-vapor mixture. Large liquid droplets, or larger liquid slugs and plugs, are avoided with the linear acceleration of the flow in linear nozzles.

It has been suggested that there is a delay during flashing of a liquid to a vapor in the turbine so that a 50% degree of reaction, radial inflow centrifugal turbine may not have quite the amount of vapor predicted by a P vs. h equilibrium diagram (Fig. 3). However, measurements with flashing hydrocarbons in short two-phase nozzles have shown that an almost equilibrium expan-sion does occur.

Mathematical models in the literature also tend to confirm that the time taken for the liquid to flash is equal to or less than the time it takes for the fluid to pass through the turbine. An almost equilibrium behavior is found during the flashing.9–11 There is very little measureable time delay, and the flashing of the liquid occurs practically instantaneously per the P vs. h diagram.

Fig. 5 shows a flashing hydrocarbon liquid-vapor jet exiting from a 100 mm-length linear nozzle. In this example, the mea-sured expansion efficiency of 92% agreed with the computed equilibrium expansion of the flashing liquid, which is proof of the near instantaneous flashing. Furthermore, in most flashing liquid-expander applications, some vapor is present in the liquid upstream of the turbine. Thus, the entire turbine must function with both liquid and vapor present. Even if there were a sizable delay and no liquid flashing through the turbine, then the turbine would merely

be a liquid turbine without gaining the additional enthalpy drop and power from the expansion of the flashing liquid into vapor.

Axial-impulse turbine. An axial-impulse turbine design that uses linear nozzles to flash a liquid to vapor has several advantages:

• Avoiding a centrifugal field that separates the flashing liquid and vapor phases

• No curvature of the flashing flow in the nozzles, which avoids separating the phases.

Fig. 6 is an example of a linear nozzle. In an axial-impulse tur-bine, the inlet liquid undergoes a controlled linear expansion in the nozzle and forms a flashing liquid-vapor mixture. This controlled expansion forms a fine mist of droplets that has a low slip velocity

0.16 xv0.52 �v

0.00 xv0.00 �v

Nozzle inlet

T1 T2 T3 T4 T4 T6Nozzle inlet

Pres

sure

Nozzle outlet

Nozzle outlet/impeller inlet

Impeller inlet

Enthalpy

Molar composition, MolarMethane: 94%Nitrogen: 5%

xv = vapor mass fraction�v = vapor volume fraction

Impeller outlet

Impeller outlet

0.29 xv0.83 �v

Typical P vs. h diagram for a single-stage radial-inflowcentrifugal turbine during a liquid to vapor, flashingexpansion with a hydrocarbon liquid.

FIG. 3

Impellerblades

Vapor Liquid

Nozzle

Two-phase jet from nozzle

Sketch of a vapor-liquid axial jet flow exiting the nozzleand entering an axial-impulse impeller blade. Above right: A titanium axial-impulse impeller produces 1 MW of power. Below: Visualization of a flashing liquid mixture as it passes through an axial impulse impeller.

FIG. 4



and high efficiency nozzle. These findings were verified by NASA, JPL and Caltech by experimental testing and development.6 In the axial-impulse turbine, the impeller is an impulse style so there is no pressure or enthalpy drop across the impeller, only across the nozzles. The impeller can be manufactured from hard, lightweight titanium, which, together with impact velocities, is well-below the erosion threshold. This design eliminates any erosion that droplet impact could cause. Titanium impellers are commonplace in the turboexpander industry, with a long history of success.

Existing axial-impulse turbine designs. Over 100 axial-impulse style flashing liquid turbines have been in service for 30 years. Examples include in refrigeration chillers.12 The power levels are only at 20 kW to 55 kW in these chillers. Larger axial-impulse flashing liquid turbines are found operating in geothermal applications including units at 800 kW and 1.6 MW power levels.13 Ten other axial-impulse turbines for flashing liquids are found in the oil and gas industry, with sizes ranging from 20 kW to 100 kW.13

From a new construction point of view, Fig. 7 is a new 1-MW axial-impulse turbine for a flashing hydrocarbon liquid application now under commission. The design features an axial-impulse impel-ler with 10 nozzles to flash a liquid hydrocarbon. The generator is an external air-cooled type. The single-stage design keeps the unit axially compact to ensure stable rotordynamics and low vibrations.

Options. The research and development work done in the 1980s by several large turbomachinery manufacturers revealed that radial-inflow centrifugal turbines are not suitable for handling flashing liquid flows when the vapor volume fraction at the tur-

bine outlet is greater than 10%. The work by NASA and JPL has shown that axial-impulse turbines, which don’t use a centrifugal field for power transfer can achieve reasonable efficiency when liquid is flashed through the turbine. Axial-impulse turbines are known to have reduced vibration levels compared to the radial-inflow centrifugal turbines when a liquid is flashed. This has consequences for bearings and seals, as the reduced vibrations promote reliability and a longer service life. HP

LITERATURE CITED 1 Dipippo, R., “Ideal Thermal Efficiency for Geothermal Binary Plants,”

Geothermics—International Journal of Geothermal Research and its Applications, Vol. 36, pp. 276–285, 2007.

2 Hahn, P., et al.,“Application of a Flashing Liquid Expander to Enhance LNG Production,” LNG-15 Conference Poster Presentation, Barcelona, April 2007.

3 Apfelbacher, R., C. Hamkins, H. Jeske and O. Schuster, “Kreiselpumpen in Turbinenbetrieb bei Zweiphasen-Strömungen,” KSB Technische Berichte, Vol. 26, pp. 20–28, 1989.

4 Gülich, J., “Energierückgewinnung mit Pumpen in Turbinenbetrieb bei Expansion von Zweiphasengemischen,” Sulzer Technical Review, Vol. 3, pp. 87–91, 1981.

5 Gülich, J., “Kreiselpumpen: Handbuch für Entwicklung, Anlagenplanung und Betrieb,” Springer Verlag, Heidelberg, 2010.

6 Elliott, D. G., D. J. Ceromo and E. Weinberg, “Liquid-Metal MHD Power Conversion,” Space Power Systems Engineering, Academic Press Inc., pp. 1275–1297, 1966.

7 Elliott, D. G., Theory and Tests of Two-Phase Turbines, JPL Publication 81-105, DOE/ER-10614-1, Jet Propulsion Laboratory, Pasadena, California, 1982.

8 Young, J. B., “The Fundamental Equations of Gas-Droplet Multiphase Flow,” International Journal of Multiphase Flow, Vol. 21, No. 2, pp. 175–191, 1995.

9 Elliott, D. G., and E. Weinberg, Acceleration of Liquid in Two-Phase Nozzles, JPL Publication 32-987, Jet Propulsion Laboratory, Pasadena, California, 1968.

10 Gopalakrishnan, S., “Power Recovery Turbines for the Process Industry,” Proceedings of the Third International Pump Symposium, Houston, 1986.

11 Grison, P. and J. F. Lauro, “Biland es études de Thermohydraulique des Pompes Primaries de Reacteurs PWR,” La Houille Blanche 7/8, 1982.

12 Payvar, P., “Mass transfer-controlled bubble growth during rapid decompres-sion of a liquid,” International Journal of Heat Mass Transfer, Vol. 3.0, No. 4, 1987, pp. 99–706, 1987.

13 Hays, L. G. and J. J. Brasz, “Two-phase flow turbines as stand-alone throttle replacment units in large 2000–5000 ton centrifugal chiller installations,” Proceedings of the 1998 International Compressor Engineering Conference, Purdue, Vol. 2, pp. 797–802.

14 Hays, L. G., “History and Overview of Two-Phase Flow Turbines,” C542/082/99, IMechE International Conference on Compressors and Their Systems, Sept. 13–15, 1999, City University, London, UK, pp. 159–168.

Hydrocarbon-liquid flashing expansion at the outlet of a linear nozzle with no curvature. There is a fine mist in the expansion due to the high nozzle efficiency.

FIG. 5

The linear 1D nozzle design linearly accelerates the flashing liquid before the flow enters the axial flow impeller. Curvature is avoided to ensure a fine well-dispersed mist flow, as seen in Fig. 5.

FIG. 6

New 1-MW flashing liquid expander being commissioned using, hydrocarbon flashing liquid.

FIG. 7

Dr. Kevin Kaupert is the director of technology at OC Tur-boexpanders. He holds a doctorate in turbomachinery engineering from the ETH Zurich Swiss Federal Institute of Technology. He has over 25 years of experience in turbomachinery for cryogenics, power generation and aerospace applications.


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Understand multi-stage pumps and sealing options: Part 2Designing for dirty service involves many factors

L. GOOCH, AESSEAL plc, Rotherham, UK

W ell-engineered single and dual seals are needed in the hydrocarbon processing industry (HPI). As more pro-cesses involve high-pressure (HP), toxic, flammable,

lethal or explosive pumping services, a thorough understanding of the available options for rotating equipment, especially pumps, is mandatory. Seals in produced-water injection (PWI) services are typical applications deserving further investigation.

Option 1: Single seals for multi-stage pumps. For-tunately, single seals are often a possible option for multi-stage pumps. Unlike dual-mechanical seals, single seals will not require

a buffer fluid support system; thus, single seals are less expensive. Although the service life for single seals is about two years, these seals require more frequent replacement; some may last only a few weeks. The main issue with some single seals is often design-related. Some single seals ignore the deleterious effects of salt and other contaminants. It appears that careless selection routines allow API seals designed for clean-duty applications to be applied to dirty salt water.

Old design Modern design

Examples of the older and newer styles of mechanical seals. (Source: AESSEAL Inc., Rotherham, UK, and Rockford, Tennessee.)FIG. 3

B A

A. common style of mechanical seal often found in PWI water applications. As salt accumulates near A, fretting damage often occurs near B.

FIG. 1Multiple springs are exposed to the process fluid in this seal.

FIG. 2



A common seal style used in PWI service is shown in Fig. 1. The principal drawback of this design is a lack of clearance under the seal faces (point A). Single seals operating in a fluid with a high salt content often allow salt crystals to accumulate under the seal faces. The lack of clearance then causes the seal faces to hang up and fail. Moreover, these seals can sometimes experience problems if hard plating is used under the elastomer at point B. The plating tends to lift off unless the underlying substrate is corrosion resistant.

Another version of a single seal is shown in Fig. 2; it, too, has distinct drawbacks. The seal in question is a stationary car-tridge seal, i.e., the spring-loaded face does not rotate—-a gen-erally advantageous feature. However, multiple small springs are located in the contaminant-laden process fluid. This design should be considered less reliable than those that place the spring (or springs) away from the process fluid.

An area of concern common to all seal styles is the location of the flush port location, as shown in Figs. 1 and 2. Unfor-tunately, the flush ports are directly placed over the seal faces. Most PWI pumps are fitted with API Flush Plan 31. This plan involves using cyclone separators. Apart from being expensive, cyclones are typically only about 97% effective in removing abrasive particles from the flush stream. When they are slightly undersized or are starting to clog, the effectiveness of cyclones is reduced even further. Solids then manage to reach the seal region and cause erosion damage. This is why the pump and seal specifications of at least one major international oil com-pany have disallowed cyclone separators for several decades. This company has discovered a far more suitable alternative to flush arrangements for its PWI pumps. They are collectively called recent, or modern, seals.

Fig. 3 shows diagrams of the older and more recent seal designs. In the older design, debris may impede the axial move-ment of the rotating seal face. Also, the flush port is very close to the two seal faces. In the newer design, care is taken to move the springs away from both pumpage and flush fluid. The flush port is relatively far from the seal faces. Note: The older seal is conventional inasmuch as the axially moving seal face is part of the rotating assembly. In the modern design (Fig. 3), the nonro-tating (“stationary”) seal can move axially.

Single-seal options. By addressing the key causes of pre-mature failure, thoughtfully engineered, reliable single-seal solu-tions are available for PWI systems. The same principles can be applied to crude-oil transfer pumps, wastewater pumps, water outfall booster pumps and many others. When dealing with crude oil, consideration must be given to the presence of hydro-

gen sulfide (H2S). Even small amounts (approximately 10 ppm) can cause sulfide-stress corrosion in “conventional” metal-lurgies. So, the proper metallurgy must be selected. Recall that in H2S-containing services, the elastomers should be changed from the more commonly used Viton to Kalrez. Fig. 4 is a representative example of the single-seal alternative in PWI or related services. These seals are installed in pumps, as shown in Fig. 5.

Option 2: Dual-seal option. Con-ventional industrial applications tend to use dual seals whenever difficult-to-seal fluids are involved. This thinking would also prevail in the case of fluids with high salt content. Dual seals offer extended ser-vice life because the fluid film is controlled and the salt-crystal accumulation is effec-tively prevented.

Yet, dual seals in PWI systems are often impractical because of pump location and

Cross-sectional view of a modern “stationary” single-seal option that does not allow process fluid to reach the small springs. Potential leakage flow would be seen exiting from the seal drain port. (Source: AESSEAL Inc., Rotherham, UK, and Rockford, Tennessee.)

FIG. 4

Pump type 6UZDL21 2-stageService/duty Water disposal boosterFluid Salt waterTemperature 55°C-80°CSpeed 1,450 rpmSeal pressure 10 barCurrent seal UCW-4250-5X4U Metal parts C 276Other materials SiC/SiC/Aflas

Pump type 6 x 13 WMSN 5-stgService/duty Shipping pumpsFluid 20% Crude oil + 80% Formation waterTemperature 63°CSpeed 2,960 rpmSeal pressure 104 psiDischarge pressure 1,000 psiSeal currently used Borg Warner (N2031 – 90)Metal parts Hastelloy COther materials SiC/SiC/Aflas

Two single seals are installed in two pumps. (Source: AESSEAL Inc., Rotherham, UK, and Rockford, Tennessee.)

FIG. 5



geography. Much of the Middle East is considered an extreme environment for typical PWI stations. The average daytime tem-perature can exceed 45°C (115°F), and the nearest freshwater supply could be more than 40 miles away. As a rule, severe station environments make using dual seals problematic. The primary issues are quite obviously how to conserve fresh water and how to cool the barrier fluid that separates the inboard and outboard seals.

Whenever dual-seal systems are used in harsh environments, they are expensive. The costs escalate when the seals are rated for full-pump discharge pressure. Conversely and not surprisingly, dual-seal systems have significantly extended seal life.

Fig. 6 shows a particular HP dual seal found on PWI and crude-oil transfer pumps. Its manufacturer supplies seals rated to the full discharge pressure of the pump. The owner-user is instructed to operate with a barrier fluid pressure in excess of 100 bar, even if the seal environment does not exceed 15 bar.

The HP rating of certain seals can lead to unforeseen draw-backs. So as to prevent O-ring extrusion, the clearances between the component part tolerances must be extremely tight. Tight clearances in dirty fluids are prone to clogging and to elevated risk of seal-face hang-up.

Materials of construction. Often single and dual seals use the same materials of construction. Since corrosion is an issue, the metallic components must be Hastelloy C, unless dictated and specified otherwise by the owner-user. Viton serves as the traditional elastomer; Kalrez is used if H2S is present. Silicon carbide/silicon carbide face combinations are used for single seals and for the inboard seal faces of dual seals. Silicon carbide/carbon combinations are used on external dual-seal faces. One successful approach to sealing produced water, as shown in Fig. 4, is giving due consideration to potential problem areas:

Best materials of construction include C 276/SiC/SiC/Viton or Kalrez. Using the correct materials of construction virtually eliminates corrosion issues.

Springs not contacting process fluid. Multiple small springs offer many benefits over a single, large-coil spring. However, small springs are prone to clogging. An advantageous design deliberately places the springs outside the process fluid. This may be considered a simple item. Yet, it is often overlooked, and not even API-682 makes reference to the issue.

Large clearance under the seal faces. Comparing seal cross-sectional views from different manufacturers will reveal how the

properly designed modern seals have greater clearance under the seal faces than seals potentially offered by another manufacturer. Suitable designs consider that the fluid has a high salt content and will crystallize under the seal faces. There should be sufficient room for this to happen without restricting seal-face movement.

Directed-flush port. For applications where solids could potentially cause a problem or where the customer wishes to move away from cyclone separators, at least one major manufac-turer offers a directed flush design. This design allows solids to be directed away from the seal faces while still providing circulation in the seal chamber.

Modern dual-seal options. With oil companies moving toward lower-pressure-rated seals and striving for longer equip-ment operating times, users are compelled to find knowledgeable seal manufacturers and suppliers. Compliance with the dual-seal recommendations of API-682 is highly desirable as well.

Apart from being modular in design and thus allowing for interchangeability between single and dual components, the mod-ern O-ring pusher dual seal, as shown in Fig. 7, has many advan-tages over traditional seals. It represents a true dual seal with two independently mounted seal faces. Both seal faces are internally pressure-balanced. The inboard seal faces are double-balanced and all faces are flexibly mounted.

A standard dual seal is typically used in conjunction with a conventional thermosiphon system in duties or at sites where cooling water is readily available. At such locations, most PWI

Side view of an HP seal offered by a prominent seal manufacturer.

FIG. 6

Side view of a modern dual mechanical seal. (Source: AESSEAL Inc., Rotherham, UK, and Rockford, Tennessee.)

FIG. 7

An API Plan 54 cooling unit. (Source: AESSEAL Inc., Rotherham, UK, and Rockford, Tennessee.)

FIG. 8


82

and water-disposal pumps use dual seals per API Plan 54 sys-tems, as shown in Fig. 8. The modern dual seal is then often supplied with the pumping ring removed (Fig. 7). It achieves a measure of enhanced cooling between the seals while retaining all the advantages of interchange with other seals onsite.

There is, however, a note of caution. When fitting seals to PWI or HP water-disposal pumps, be sure to use nickel-plated, carbon-

steel grub screws. These must be secured to the shaft by dimpling the shaft surface to rule out seal sleeve slippage during operation.

More on Plan 54 systems. As mentioned earlier, heat removal from the seal is a prime concern, especially so that the pumps can operate in high ambient conditions. With PWI stations generally situated in remote locations, cooling units must be self-contained. Figs. 8 and 9 are two examples of API Plan 54 units.

The Plan 54 water-circulating cooling unit in Fig. 9 is perfectly acceptable at locations with ample cooling-water supplies. Con-versely, air cooling (Fig. 10) is the preferred method in regions or areas where water is at a premium or not available. An air-cooled Plan 54 unit has the standard water-cooled shell-and-tube heat exchangers replaced with air fans or blowers. A second example is illustrated in Fig. 11.

The systems used in the oil and gas industry are generally far more sophisticated than those found at normal industrial sites. They are also more expensive and often equal (if not exceed) the value of the seals involved. It is, therefore, vital that the reliability-focused user-purchaser gives equal attention to seals and seal-support systems.

Comments. The intent of this two-part article is to give the reader a basic insight into the many opportunities for well-engi-neered components offered by highly competent seal manufactur-ers. Most of the applications illustrated are either dirty water or dirty oil. There obviously are a multitude of applications that can greatly benefit from best available technology. HP

End of series: Part 1, February 2012.

A water-circulating API Plan 54 cooling unit operating onsite. (Source: AESSEAL Inc., Rotherham, UK, and Rockford, Tennessee.)

FIG. 9

An air blower unit for an API Plan 54 seal support system.

FIG. 11

A high-capacity air cooler unit for an API Plan 54 seal support system. (Source: AESSEAL Inc., Rotherham, UK, and Rockford, Tennessee.)

FIG. 10

Lee Gooch has been with AESSEAL for 14 years. He has held various positions within the company including project engineer and senior sales engineer. He now is responsible for business devel-opment and applications engineering roles for AESSEAL and spe-cializes in the upstream sector of the oil and gas industry. Before

joining AESSEAL, he worked for Fisher Rosemount in the control valve division, and for Mono Pumps where he served in a mechanical technicians apprenticeship and went on to hold a project application engineer’s position in UK Sales.


CATALYST 2012Perspectives on the 2012 energy industry [C–84]

CORPORATE PROFILESAxens [C–87] BASF [C–89] Chevron Lummus Global [C–91] Criterion [C–93] Grace Davison [C–95] Haldor Topsøe [C–97] Sabin Metal Corporation [C–99] Saint-Gobain NorPro [C–101]

COVER PHOTO Photo courtesy of Criterion.

Special Supplement to

CATALYST

C–84 CATALYST 2012 HydrocarbonProcessing.com

PERSPECTIVES ON THE 2012 ENERGY INDUSTRYHere are several thoughts on how companies can adapt to—and profit from—the uncertain environment

V. DOSHI, A. CLYDE and C. CLICK, Booz & Co., Paris, France

Never has the old adage that “the only cer-tainty is uncertainty” been truer for the energy sector. In the past 12 months, we’ve seen a strong emphasis on green energy evaporate as country after country withdrew support for renewables. While the green imperative slipped, natural gas took center stage—par-ticularly in the US. A raft of new shale gas pro-duction has put the US on course to be a net exporter, rather than an importer, of natural gas. If that transition takes place quickly, European and Asian gas distributors and users that had locked in long-term, oil-price-related contracts could be vulnerable.

More developments. Japan’s Fukushima earth-quake has tainted the prospects for nuclear energy, once considered to be the answer for abundant clean power. Germany has already banned nuclear utilities. We can expect a slow-down in nuclear plant development in virtually every country.

Oil will remain extremely sensitive to politi-cal turmoil in the Middle East, risks of potential environmental accidents, the (US) dollar’s value and the notion that it is a dwindling resource. All are contributing to ongoing price volatility and supply uncertainty. In North America, the debate over the Keystone XL pipeline project further highlights the uncertainties facing this industry, as political decision makers balance concerns over energy security, the environment, job growth and consumer prices. Another great unknown affecting oil price and availability is the extent of future production from producers outside the US, such as Brazil, Canada, Iraq, Russia and West Africa. Biofuel, improved gas mileage, and increased use of hybrid and elec-tric vehicles will further nibble away demand.

All of these factors will contribute to the uncer-tainty with which energy companies will have to cope. Most energy companies will find that their current operating models, strategy and plan-ning processes, and optimization practices are inadequate. They will need new capabilities to enable them to meet whatever the future holds. The four capabilities that are particularly impor-tant include:

• Strategy and long-term planning• Managing inherent risks in joint ventures• Capturing information and insight• Supply-chain optimization.

Strategy and long-term planning. Leading an energy company over the next few years will be like sailing. At any given moment, compa-nies will need to look at the way the wind is blowing and execute an integrated plan to align the sails in the right direction, while remaining alert to any changes in the wind’s direction and then rapidly adjusting the strategy as required. We believe that energy companies will need to develop dynamic strategy capabilities. These involve betting on a set of integrated options, any one of which can be switched on or off depend-ing on results and how the business environment evolves. This involves integrated-option planning.

Integrated-option planning is often over-looked because companies don’t usually think of it as a capability that they must develop. They believe that it is simply a part of normal business—something that they already do rou-tinely and perhaps on an annual basis. These companies believe that coordinating disparate elements of the business to operate in sync is a natural byproduct of an organization. But, such a task requires a concerted investment of time and resources to create the structure that can coordinate a complex set of elements, behaviors and analysis at a very high strategic level. This is particularly true if a company may suddenly need to change course to a different direction on short notice. For example, there could be a shift in financial, supply chain and human capital resources to more liquids-rich gas basins and away from dry-gas fields, or a shift in capital deployment based on geopolitical changes.

A company with a strong integrated-option planning capability is accustomed to laying out multiple options and linking strategic choices, such as which projects to pursue, which markets to focus on and which regions to target. These choices are linked to the appropriate operat-ing models, including supply chain, logistics, workforce planning and capital management. With a holistic integrated planning capabil-

ity in place, a company can react quickly to uncertainties, responding dynamically to chang-ing upstream and downstream conditions and redirecting resources, technology, talent and capital to areas of opportunity.

For many energy companies, this is an elu-sive capability. With so many different layers and business operations to manage, few organi-zations have systems that fuse the right processes, people and data to drive profitable outcomes on a consistent basis. But the lack of integrated-option planning can often lead to missed oppor-tunities. For example, one oil company hoped to broaden its Middle East operations with a series of investments. Focusing solely on the financial angle, the company spent months developing a “can’t-miss” capital structure for this expansion, including an inexpensive approach to building the new plants. But management completely neglected the substantial costs of hiring and train-ing skilled workers that would be needed. It did not put in place contingency plans for the poten-tial spread of political disruptions in the Middle East. Already, it’s clear that this company will not get the return on investment projected by its initial one-dimensional plan. A more risk-mitigated plan would have built in a variety of options, including the ability to withdraw at various checkpoints if certain criteria were met, without fear of writing off sunk costs.

Managing inherent risks in joint ventures. In periods of high uncertainty, delivering on multiyear capital projects requires unique risk-management capabilities. Energy projects are big, complicated, expensive and risky. And, for those reasons, they are often best pursued through joint ventures (JVs) and other multi-owner entities. Indeed, for some energy companies, minority stakes or JVs spread the project risks and are the only practical way to access resources and build portfolio diversification.

But the success rate of JVs is stunningly low. Often, the varied owners have different concep-tions of—or outright misunderstandings about—their respective roles in the project. Sometimes, the partners’ agendas (what they each hope to gain from the project) work at cross-purposes,

HYDROCARBON PROCESSING CATALYST 2012 C–85

CATALYST

ultimately affecting the smooth running of the operation. Insufficient attention may be given to governance or assigning accountability. The decision-making processes are typically not designed to deal efficiently with complex, multi-stakeholder issues, let alone to flexibly redeploy or redirect investment in response to changing market conditions.

Moreover, the Macondo incident of 2010 brought attention back to operational risks for all offshore assets. The fracking debate continues to intensify for shale gas and oil. The public battles over environmental impact and highlights the need for well-honed operational capabilities and incident preparedness. Many of these com-panies, pursuing opportunities without a coher-ent view of their strengths and strategy, have built up project portfolios that have become overly broad and incoherent over time.

Dramatic improvements in JV management capabilities can be gained by any energy company. Those that have this capability have learned to invest the time to understand the stra-tegic intent and objectives of partners and to ensure that these objectives are aligned. They identify in advance the capabilities that the proj-ects will require and the roles played by each operating and non-operating partner. They then allocate assignments for each entity, based on the capabilities it has or can develop. They also develop the influencing and communication skills needed to guide operating partners to best practices. Finally, they have governance and decision-making model in place that lets each owner protect its strategic agenda and that maximizes the efficiency of joint decision making. This model also establishes processes for information sharing, performance review and flexible capital allocation.

Capturing information and insight. This capa-bility can make the difference between earnings and losses, especially where oil products and gas inventories are involved (as in the down-stream) or where there is high dependency on third-party suppliers (as in the upstream). Com-panies that have been diligently pursuing the more traditional paths to prosperity—for exam-ple, by executing multiple rounds of cost cutting and restructuring—may well find that any gains in their earnings are dwarfed by the impact of price volatility. These companies need to invest in the capability of capturing information and insight, and putting them to use.

At the heart of this capability is an integrated information base that covers every aspect of the marketplace and operations, and that is avail-able to every business and function within the company. Skilled people on the front line can now make split-second decisions about oppor-

tunity and risk. They have updated information about where the tanker ships are located, how much stock is available, what will be left after each shipment, whether demand is rising or falling, where customers are located, which are fixed- vs. variable-contract customers, how much profit they can make under different options, and much more.

For example, a “strategic pilot” working within this capability might say, “I won’t meet a customer’s suddenly increased demand today, because I can’t get enough product in time and still make a profit. However, tomorrow, if the price goes up, I’ll have shipments and a new contract ready.’’ The capability to leverage information and insight can create value and reduce risk across the value chain and across functions. A “control-tower operator” role for supply chain and logistics can improve coordi-nation and avoid unnecessary expediting costs.

This capability is not just an IT tool. It also involves the shift in decision making that ensues, with all of the appropriate risk-managed pro-cesses, authorities, and commercial and techni-cal abilities required to make it work in the front office. These abilities are equally required for managing third-party procurements.

Supply-chain optimization. As much as 80% of the operational budgets at most oil and gas com-panies is earmarked for supply chains—primarily for materials and services provided by third-party suppliers. Because of the size of this percentage, many companies have, over the years, targeted supply chains for cost cutting and efficiency improvements. Although these campaigns have led to incremental, short-term successes, most oil and gas companies are poorly equipped to take the big-picture steps that would drive supply-chain management improvement.

A powerful way to address this shortcom-ing, particularly in companies with diverse busi-ness models, is a concept that we call natural supply chains. Under this approach, business operations are segmented into a few relatively similar groups, such as deepwater domestic offshore production, onshore unconventional development, onshore production, midstream and refining. The goal is to take advantage of economies of scale for those supply-chain activi-ties that can deliver cost and value advantages to all of the groups, while customizing supply-chain capabilities for the specific requirements of disparate segments of the portfolio.

Human resources, information technology and contract support can probably be shared across the organization. But other supply-chain activities must be managed individually, in a way that empowers the front line to be agile.

For example, one part of an energy com-

pany’s portfolio might demand services such as maintenance logistics to support an overarching objective around production uptime. A pressure-pump truck may be needed every 30 days in each of several different locations. To manage this schedule, the company would establish an exclusive arrangement with its trucking suppliers, with incentives and penalties based on meeting deadlines and quality of work. For this part of the business, performance and safety imperatives out-weigh all other considerations, including price.

Another business in the same company may center on major capital projects—for example, pipeline construction. As it buys 400 miles of pipe for half a dozen projects scattered across a continent, the company will negotiate low-priced bid contracts with a primary focus on delivered cost. There would not need to be as much emphasis on narrow delivery windows, because of access to warehouses and staging locations. The difference in priorities is explicit, and if people move from one part of the busi-ness to the other, they easily manage that shift because it is clear to everyone on the front line.

Putting it all together. The subject of building capabilities to deal with uncertainty is particu-larly important in the oil and gas sector. Many independents are already running up against the limits of their scale, struggling with the clash between their small-company cultures and the process and bureaucracy inherent in large projects. They are scrambling to manage an increasing portfolio breadth that stretches the limits of their existing capabilities. For the large companies, continuous rounds of cost cutting and restructuring have failed to yield sufficient profits, in part because gains in earnings are often offset by price volatility. Also, they have not invested in building the essential capabilities and agility they need to grow in these uncertain times. HP

Viren Doshi, senior vice president, is head of the Global Energy, Chemicals and Utilities Practice at Booz & Co. He has 30 years of experience in supporting oil and gas companies in developing and implementing new integrated operating models. Prior to joining Booz & Co., he worked at ExxonMobil. Mr. Doshi holds a BSc degree with honors from the University of Southampton and an MBA from Cranfield School of Management.

Christopher Click, vice president at Booz & Co., is focused on developing and implementing growth and organizational strategies for oil and gas companies in the US for the past 10 years. He specializes in the upstream and oilfield services sectors.

Andrew Clyde is a vice president with Booz & Co., and is based in Dallas, Texas. Mr. Clyde has spent over 20 years in consulting to the oil & gas sector globally. He holds an MS degree in management from the Kellogg Graduate School of Management from Northwestern University and a BBA degree from Southern Methodist Uni-versity. Mr. Clyde is a licensed CPA in the State of Texas.

The winning catalyst combination for your hydrocracker

www.axens.net


SPONSORED CONTENT HYDROCARBON PROCESSING CATALYST 2012 C–87

AXENS

Axens is recognized as a worldwide technology benchmark for clean fuels production, conversion solutions, aromatics and olefins production and purification. The combination of the technology and services with the catalyst and adsorbents manufacturing and supply business is an efficient organization that handles market needs as a single source.

With the improvement in fuel product specifications and increased demand for middle distillates, hydroprocessing catalyst technology has become crucial to the refining industry. Axens offers a complete product range of hydrotreating and hydroconversion catalysts from naphtha and gas oil to residue applications. Recently, Axens has launched a full range of catalysts to meet high conversion and mild hydrocracking unit’s objectives.

HYDROCRACKING CATALYSTSAxens’ commercial hydrocracking catalyst suite upgrades a wide range

of heavy feedstocks to produce the desired slate of products while meeting ultimate quality targets. It relies on a combination of products derived from HRK, HDK and HYK series depending upon operator conversion targets.

• Pretreating section: The combination of HRK 658 NiMo catalyst and HDK Series, including HDK 776, HDK 786 and HDK 766 catalysts is the most effective way to maximize HDN activity in the pretreatment section and to ensure that pretreating catalytic section will perform at its optimum during a long cycle length. It has proved to be superior to conventional hydropro-cessing catalyst only options. This is of particular interest when processing heavier and more refractory feedstocks with high organo-nitrogen content.

Optimized catalyst combination between HRK and HDK Series is also suitable for achieving higher conversions in new mild hydrocracking unit or in revamped FCC pretreatment units.

• Hydrocracking section: HYK 700 Series, Axens latest generation zeolite products suite including HYK 732, HYK 742, HYK 752 and HYK 762, displays high activity coupled to utmost selectivity, improved hydro-genation activity, extended long-term stability and cycle lengths. This was made possible by optimizing the dispersion of zeolite crystals, improving metal impregnation technology to reduce the distance between acid and metal sites and by increasing the hydrogenation function efficiency.

The combination of HRK, HDK and HYK series enables to squeeze more middle distillates from heavy ends while reaching high conversion levels.

HR SERIES HYDROPROCESSING CATALYSTSFor ultra-low sulfur diesel (ULSD) service, HR 626 (CoMo) and HR

648 (NiMo) catalysts are considered by many refiners as being the most stable catalysts available on the market. They offer an optimum activity and stability balance for ULSD service leading to very long cycles while maintaining industrially proven full regenerability by simple carbon burn-ing, thus providing best in class cradle to grave economics.

Axens has also introduced a new and highly active tri-metallic CoMoNi catalyst HR 568 for VGO processing and FCC Feed Prepara-

tion applications. This catalyst displaying same basic properties as other HR Series products (activity, stability, regenerability) has established itself as a benchmark in the field according to several major companies.

REFORMING CATALYSTSAxens has recently completed the acquisition of the Willow Island (West

Virginia) manufacturing plant for reforming catalyst and appropriate intel-lectual property rights to pursue such business from Criterion. This acquisi-tion strengthens our offer in the area of catalytic reforming for gasoline and aromatics production and helps us to better serve customers by providing them a wider range of products from a larger manufacturing platform.

• For aromatics production, Axens offers AR 501, AR 505, AR 701 and AR 707 catalysts for ultimate CCR (continuous catalyst regeneration) severity technology.

• For gasoline production Axens provides a wide range of catalysts covering:

o CCR technology (medium to high severity applications): PS 40, PS 100, CR 601, CR 607

o Fixed bed technologies (all reactor types): RG 582, RG 586, PR 9, PR 15

• Cyclic reactors: RG 532, P 15, P 155 • Semi regenerative reactors: RG 682, PR 30, PR 33, PR36.

CONTACT INFORMATION89, Bd Franklin Roosevelt – BP 5080292508 Rueil-Malmaison Cedex – France Email: [email protected] Website: www.axens.net

Hydrocracking catalyst performance mapping.

THE PERFORMANCE IMPROVEMENT SPECIALISTS

HRK 658

HDK 776 HDK 786 HDK 766

HYK 762

HYK 752

HYK 742

HYK 732

Increasing Conversion Activity

Increasing Middle Distillate Selectivity

HR Series

action loves reactionChemical reactions require chemical catalysts. As the

global leader in chemical catalysts, BASF acts through

continuous product and process innovations in collaborative

partnerships with our customers. The result is a broad

chemical catalyst portfolio backed by dedicated customer

and technical service and enabled through the strength of

BASF - The Chemical Company.

At BASF, we create chemistry.

www.catalysts.basf.com/process

� Adsorbents� Fine Chemical Catalysts � Environmental Catalysts � Catalysts for Fuel Cells � Catalysts for Oleochemicals & Other Biorenewables � Oxidation & Dehydrogenation Catalysts � Petrochemical Catalysts � Polyolefi n Catalysts � Refi ning Catalysts � Syngas Catalysts � Custom Catalysts



BASF

BASF’s Catalysts’ division is the global market leader in catalysis. The division develops and produces mobile emissions catalysts as well as process catalysts and technologies for a broad range of customers worldwide. BASF Catalysts expands its leading role in catalyst technol-ogy through continuous process and product innovation.

Focus of R&DBASF remains committed to R&D investments in catalysis to sustain

innovation. In the area of process catalysts, recent developments for diesel maximization and propylene maximization from an FCC unit are designed to help customers achieve more revenue from their existing processes.

MAIN PRODUCTS

Process catalysts and technologiesBASF Process Catalysts and Technologies are the leading manu-

facturer of catalysts to the chemicals industry with solutions across the chemical value chain, as well as intermediates for pharmaceuticals and fine chemicals. We have provided groundbreaking oil refining technol-ogy catalysts for over 50 years including FCC catalysts, co-catalysts and additives. Our polyolefin catalysts use a proprietary platform to offer product differentiation and value to our customers. Finally, our adsorbents business offers guard bed and catalyst intermediate technologies for purification, moisture control and sulfur recovery.

Mobile emissions catalystsMobile Emissions Catalysts enable cost-effective regulatory compli-

ance by providing technologies that control emissions from gasoline- and diesel-powered passenger cars, trucks, buses, motorcycles and off-road vehicles.

Precious metal servicesPrecious Metal Services support the catalysts business and BASF

customers with services related to precious metals. The business pur-chases, sells, refines and distributes these metals and provides storage and transportation services.

Key capabilities of BASF• Technology innovation• Production efficiency• Strict working capital management• Technology leadership in mobile emissions and process catalysis• Keen insight on global precious metal markets• Partnerships with industry leaders• Strong position in Asia through joint ventures

CONTACT INFORMATIONAmericasBASF CorporationIselin, NJ 08830, USATel: +1-732-205-5000E-mail: [email protected] PacificBASF East Asia Regional HQ Ltd.Central, Hong KongTel: +852-2731-0191E-mail: [email protected], Middle East, AfricaBASF SELudwigshafen, GermanyTel: +49-621-60-21153E-mail: [email protected]: www.catalysts.basf.com

BASF—The global leader in catalysisWe create chemistry

Refi ners worldwide use our hydroprocessingtechnologies and catalysts to deliver

cleaner products from low-quality feeds.Let us show you how. (001)510.242.3177www.clg-clean.com

Learn how CLG’s tailored hydroprocessing catalyst systems maximize coversion to clean products — visit clg-catalysts.com

ICR 512ICR 180 ICR 185 ICR 250

ISOCRACKING

VGO

clean transportation fuels ultra-low sulfur diesel (<5 ppm) high smoke point jet (25-30 mm) Ultra-low sulfur naphtha (<0.5 ppm)FCC feed



HYDROPROCESSING CATALYSTSFOR IMPROVED PROFITABILITY

Chevron Lummus Global (CLG) has been helping refiners with hydrocracking solutions as an entity since 1993. Chevron pioneered development of the modern hydrocracking process through focused R&D, design, and operating experience dating back to the late 1950’s. As the market leader in licensing world-class units, CLG relies heavily on state-of-the-art, high-performance catalysts to process even the most difficult feeds and provide high operating stability.

At a time when many are cutting back, we’ve been busy—CLG’s focus on catalyst development is stronger than ever because our indus-try requires it. Hydrocracker utilization continues at record levels and severity of operation continues to grow as more upgrading of low-value stocks such as HCGO, DAO, and LCO is required while environmental regulations on products continue to tighten. Feed endpoints continue to increase, adding even further difficulty. CLG catalyst development efforts have been focused on both pretreat and cracking catalysts to address refiners’ needs to safely process these feeds and to increase unit throughput as well.

PRETREAT CATALYSTCLG has recently introduced ICR 512, a high-activity pretreat catalyst

targeting higher activity HDN, HDS, and HDA. ICR 512 is fully commer-cialized and successfully operating in several hydrocrackers. ICR 512 is designed to meet the needs of hydrocrackers around the world process-ing heavier and/or more refractory feeds. Combined with unit-specific demet and grading catalysts such as ICR 161, ICR 132, and ICR 171 ensures that these catalysts will perform at their maximum efficiency and provide a long and stable operating cycle.

HYDROCRACKING CATALYSTCLG has also introduced several new hydrocracking catalysts which

are in perfect alignment with our latest pretreat catalyst introductions. These new catalysts are the result of our ongoing and focused develop-ment programs, noted as follows:

• ICR 250—base metal max. diesel• ICR 214—base metal max. naphtha• ICR 185—base metal max. middle distillateWhile these catalysts are designed for somewhat different markets

and operating objectives, they all share common attributes for which CLG catalysts are known, including:

• Low gas make• High liquid yield• Low deactivation rates• High nitrogen toleranceAll CLG catalysts are successfully utilized in units designed by CLG

or by others with no special requirements. Accompanying all of these catalysts is CLG’s extensive technical and operations support networks to help our customers get the most from their operating units.

LUBES CATALYSTUnconverted oil from a hydrocracker is often utilized as feedstock

for lubes processing. CLG has been in the business of licensing lubes hydrocrackers and catalytic dewaxing and hydrofinishing units since the early 1980’s. We design and service fully integrated base oil plants

with hydrocrackers and finishing units. We can uniquely provide a com-prehensive catalyst solution from start to finish, ensuring the consistent production of high-quality base oils. Like hydrocracking, our researchers have been focused on improved lubes and finishing catalysts for these units as well as replacement catalysts for others. Recent developments include the introduction of ICR 432.

We’re an operating company just like you! We know the value of Operational Excellence, we know how to extract maximum value from complex hydroprocessing units, and how to employ safe operating practices. Combining our own first-hand operating expertise with our rich history of catalyst developments—and knowledge gained from over a hundred new unit process designs—provides our customers with unparalleled technology and support.

CONTACT INFORMATIONPhone +1.510.242.3177Fax +1.925.842.1412Email [email protected] clg-catalysts.com

CHEVRON LUMMUS GLOBAL

EVER WONDER WHAT MAKES OUR CATALYSTS SO ADVANCED?

INDUSTRY-LEADING MINDS, OF COURSE.Even with a wide range of proven catalysts like CENTERA® in our portfolio and nearly 300 cycles

of commercial ULSD operations around the world, at CRITERION, we know the ultimate key to

performance is our people. Our research and development team represents a select force of obsessively

dedicated thinkers – industry-leading scientists with the ability to transform an idea into a breakthrough

solution. Rest assured, the next generation of catalyst technology is in good hands (and heads).

www.CRITERIONCatalysts.com

CRITERION: Leading minds. Advanced technologies.



CENTERA® CATALYSTS: IMPROVED STRUCTURE AND ACTIVITYJOHN A. SMEGAL, THOMAS T. WEBER and LAWRENCE (LARRY) S. KRAUS

CENTERA® catalysts are the newest commercial hydrotreating cata-lysts from Criterion Catalysts & Technologies and are available in NiMo (DN-3630) and CoMo (DC-2618) versions for Ultra Low Sulfur Diesel Hydrodesulfurization (ULSD HDS) applications. CENTERA® catalysts are more active for ULSD HDS than previous catalyst generations. This paper presents catalyst characterization data identifying the source of CENTERA® activity improvements.

CATALYST CHARACTERIZATIONCommercial CENTERA® DN-3630 catalyst was characterized using

Transmission Electron Microscopy (TEM), Extended X-Ray Absorption Fine Structure (EXAFS), and Fourier Transform Infrared (FTIR)/Nitric Oxide (NO) Adsorption. TEM and EXAFS analyses indicate a reduction of aver-age metal particle size from the 4.5 nm and 3.5 nm values measured for Criterion CENTINEL and CENTINEL GOLD NiMo Type II commercial catalysts, respectively, to 2.5–3.5 nm for CENTERA® catalysts.

TEM measurements done at the Technical University of Delft show that CENTERA® consists of supported (75%) and unsupported (25%) domains, each having particle sizes around 3.5 nm. Analyses of CEN-TINEL GOLD and CENTINEL TEM images yield average particle sizes of 3.5 nm and 4.5 nm, respectively. The degree of stacking is greater with the CENTERA® catalyst, indicating a greater degree of Type II character.

The extent of the Mo-S interactions can be detailed utilizing EXAFS. The Mo K edge full EXAFS spectra of the catalyst samples studied were measured at the SuperXAS beamline of SLS at the Paul Scherrer Institute, Villigen, Switzerland.

The first shell at about 2 Å is due to Mo-S contributions. It is identical with that of bulk MoS2 and corresponds to the ideal coordination number (CN) of 6, indicating complete Mo sulfidation. Mo-S distances (R) in sul-fided DN-3630 are very close to that of 2H-MoS2 (2.415 Å). The second shell is due to Mo-Mo contributions and reflects a coordination number of 4.4 (6.0 in 2H-MoS2), corresponding to the typical 3.16 Å Mo-Mo dis-tance. Using the size-correlation correction suggested by Shido and Prins(1), the diameter of the MoS2 slabs in DN-3630 is determined to be ~2.5 nm. This compares favorably to the average diameter of 3.5 nm from TEM.

FTIR analysis of NO adsorption on DN-3630 and a CENTINEL NiMo catalyst was used to characterize the surface of the sulfided catalysts. The N-O stretching vibrational frequency of NO shows char-acteristic differences when adsorbed on Ni, Co, or Mo. Figure 1 depicts MoS2 edge surface models consistent with FTIR/Adsorbed NO spectra of sulfided DN-3630 and CENTINEL NiMo catalysts.

The DN-3630 spectrum (top) shows only coordinately unsaturated Ni centers on the edge of DN-3630 active metal particles as indicated by the single peak indicative of NO adsorbed on nickel (pink area) and the lack of a peak indicative of NO adsorbed on Mo (blue area) as found in the CENTINEL NiMo spectrum (bottom).

This finding leads to the conclusion that the edge surface of sulfided DN-3630 contains only coordinatively unsaturated Ni and does not contain any coordinatively unsaturated Mo. This is in contrast to the CENTINEL NiMo spectrum that shows NO adsorption on unsaturated Mo and therefore less efficient edge decoration of the MoS2 crystallites with the promoter nickel.

Further, an unusually high N-O stretching vibration associated with the nickel edge in DN-3630 suggests unique surface structural properties as compared to CENTINEL. DFT molecular modeling calculations indicate that this can be explained by the presence of two to three adjacent unsaturated Ni centers (Figure 1). The full presence of these specific active structures is believed responsible for the increased activity of the CENTERA® catalysts.

CATALYST ACTIVITY TESTINGCriterion CENTERA® catalysts have been tested extensively in straight

run and cracked distillate HDS at low and high pressure. CENTERA®

catalysts show up to 20°F (11°C) ULSD HDS activity improvements over previous catalyst generations. Detailed CENTERA® activity test results can be found elsewhere(2).

CONCLUSIONSCriterion CENTERA® catalysts show significant activity improve-

ments over previous catalyst generations. TEM, EXAFS, and FTIR/NO Adsorption show that these improvements are due to increased active metal dispersion, complete Mo sulfiding, and more efficient active site decoration with promoter atoms.

REFERENCES(1) Shido, T. and Prins, R., J. Phys. Chem B, 1998, 102, 8426.(2) Smegal, J.A., Weber, T.T., and Kraus, L.S., Prepr. Pap.-Am. Chem.

Soc., Div. Pet. Chem., 2010, 5 (2), 21

CONTACT INFORMATIONJohn Smegal—Senior Research ChemistCriterion Catalysts & TechnologiesE-Mail: [email protected]: http://www.criterioncatalysts.com

Figure 1. CENTERA® DN-3630 and Centinel NiMo NO Adsorption FTIR Spectra

CRITERION

Rare-earth price inflation is a serious issue facing the global refining industry.

Grace, with our long history of innovation and strong R&D, leads the industry

with the first line of commercially successful zero/low rare-earth FCC catalysts:

the REpLaCeR® family.

Launched in the first quarter of 2011, the REpLaCeR® family includes five new

catalysts for both hydrotreated and resid feed processing with zero and low

rare-earth content. The REpLaCeR® family of catalysts utilizes proprietary

zeolites and state-of-the-art stabilization methods to deliver performance similar

to current rare-earth-based FCC technologies.

We’re also investing in our plants to bring these products to the refining industry

quickly and globally.

So if you’re concerned about rare-earth pricing and availability, but need optimal

FCC performance, call the technical experts at Grace. We’ll customize a solution

using one of our new zero/low rare-earth catalysts that delivers the yields you expect.

REp R®

Worried about the cost of rare earth?Grace has the solution:

Grace Catalysts Technologies7500 Grace DriveColumbia, MD USA 21044+1.410.531.4000

www.grace.comwww.e-catalysts.com



GRACE DAVISON

INNOVATIVE CATALYSTS SOLUTIONS FROM THE INDUSTRY’S BROADEST PORTFOLIO

Grace is dedicated to helping refiners achieve success with innova-tive catalytic solutions from our broad catalyst portfolio. We help refiners stay competitive in various ways, such as reducing exposure to rare-earth pricing, using our products to reduce commodity spend, or maximizing the yield of diesel in the refinery.

MEETING CURRENT CUSTOMER NEEDSRare-earth price inflation is a serious issue facing the global refining

industry. Launched in the first quarter of 2011, the REpLaCeR® family includes five new catalysts for both hydrotreated and resid feed pro-cessing with zero and low rare-earth content. The REpLaCeR® family of catalysts utilizes proprietary zeolites and state-of-the-art stabilization methods to deliver performance similar to current rare-earth based FCC technologies.

In response to shrinking supplies of equilibrium catalyst, Grace has introduced TITANTM, a unique catalyst solution for removing contaminant metals from refining operations. Unlike traditional equilibrium catalysts, TITANTM is completely free of nickel, vanadium and additives.

Grace has multiple catalyst solutions to maximize LCO yield in your FCC. MIDAS® is our benchmark bottoms conversion catalyst with commercial success well-documented in over 100 refineries around the world. The same conversion capability can now be achieved without rare earth, which is available in the new REBELTM technology. Now in nine applications and growing, REBEL™ delivers similar activity and bottoms cracking conversion to MIDAS®. For those units desiring deep bottoms conversion, but without sacrificing in-unit activity to get there, Grace offers ALCYON® M catalyst. Designed for short contact time units desiring deep bottoms conversion, ALCYON® M will crack the bottom of the barrel without giving up activity or violating unit constraints such as circulation rate.

SUPPORTED BY TECHNICAL SERVICEOur world-class Technical Service engineers support refiners so they

realize the maximum value from our products. Catalyst performance partnered with industry-leading technical serviceis what differentiates Grace from its competitors. The best catalyst in one unit may not be the best catalytic fit for another application. Grace’s Technical Service team has the knowledge, experience, and application expertise to thoroughly understand a refiner’s FCCU configuration, operation, constraints, and objectives and then match that to the catalyst technology that delivers optimal performance.

Regular operational reviews with the refiner to assess catalyst perfor-mance versus changing unit objectives, constraints and feedstock are standard practice ensuring the refiner is always using the best catalyst technology available. Grace’s highly specialized Technical Service engineers, with experience in both catalyst application and FCCU operations, are ready to assist refinery engineers with unit optimization.

By working closely with refinery technical staff, our Technical Service team can help the unit engineers maintain a profitable reliable operation of the FCCU in even the difficult circumstances.

A WIDE ARRAY OF FCC ADDITIVES TO MEET SPECIFIC CHALLENGESOur current portfolio of FCC additives allows refiners to reduce

SOx, NOx, and CO emissions from their FCC units, as well as lower sulfur content in gasoline and diesel fuel. Grace also offers additives to maximize propylene yield from the FCC unit such as our leading ZSM-5 additive technologies, OlefinsMax® and OlefinsUltra®. We have commercialized Super DESOX® MCD, a high efficiency, low rare-earth environmental additive, that at modest SOx reduction levels makes an economically attractive option to reduce wet gas scrubber caustic consumption.

Grace offers a broad portfolio of state-of-the-art catalytic solutions to meet refiners’ needs. Our experience, backed by manufacturing excellence, has made us the world’s leading supplier of FCC catalysts and additives. We are the only global producer of FCC catalysts and additives with manufacturing facilities in three countries and sales in 63 countries. We look forward to joining with you to help you optimize your operations.

CONTACT INFORMATION7500 Grace Drive, Columbia, MD 21044 USAPhone: +1-410-531-4000Fax: +1-410-531-4540E-mail: [email protected]: www.grace.com

Launched in the first quarter of 2011, the REpLaCeR® family is in use in over 80 units worldwide.

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HALDOR TOPSØE

CATALYSING YOUR BUSINESSThrough half a century’s dedication to heterogeneous catalysis,

Topsøe has developed and strengthened its position as a leading market player in catalysts, and technologies for process design.

Topsøe’s markets include oil refineries, chemical plants and the energy sector, where the catalysts and technologies ensure smooth-running and cost-efficient operations with optimal production results.

HYDROPROCESSING WORLDWIDETopsøe has developed process design and catalysts for virtually all

areas of hydroprocessing and the catalysts and technologies are in operation in plants worldwide.

Topsøe’s hydroprocessing expertise offers integrated solutions including reactor internals, grading material, catalysts, process design and detailed reactor engineering. The supply of catalysts and technology offers clients a single point of expertise and responsibility.

In the design of new hydroprocessing units, Topsøe’s research and test facilities offer clients testing opportunities including detailed feedstock and process analyses, which form the basis of tailor-made solutions.

TOPSØE’S REFINING COMPETENCIESThrough extensive hydroprocessing research and development

Topsøe offers– a broad hydroprocessing catalyst portfolio and tailor-made

technologies for revamps and grassroots units meeting all specific needs of the refiner

– in-depth knowledge of hydroprocessing reactor fluid dynamics and in-house developed designs for reactor internals ensuring efficient catalyst usage

– more than 20 years of experience with graded bed catalyst design based on particle size, shape, void and catalytic activity for pressure drop abatement

RESEARCH BASED CATALYSTS AND TECHNOLOGIESA fundamental understanding of catalyst behaviour at the nano scale

enables Topsøe to continuously develop new and improved products to meet clients’ needs. One recent development was Topsøe’s BRIM™ catalyst preparation technology, which has led to a whole new generation of unmatched activity hydrotreating catalysts with great stability.

MARKET EXPERIENCETopsøe has extensive market experience with all aspects of

hydrotreating ranging from naphtha to heavy residue. More than 200 hydrotreating units have been licensed using Topsøe hydrotreating technology of which a large number are designed for production of ultra-low sulphur diesel with less than 10 wt ppm sulphur.

Topsøe has more than 180 references in operation or projected for the production of ultra-low sulphur diesel having less than 50 wt ppm sulphur, corresponding to 5 MMBPD. 150 of these references use catalysts produced with Topsøe’s BRIM™ technology.

RENEWABLES FUELTopsøe has developed hydroprocessing catalysts and technology for

processing a wide range of renewable feedstocks to gasoline, jet and

diesel. Feedstocks include vegetable and animal oils, fatty acid methyl esters, waste oils and greases, tall oil and other forest waste products, algae and plastics. These feeds can be converted to transport fuels, either in stand-alone plants or by co-processing with normal refinery feedstocks.

RELATED INDUSTRIESTopsøe’s refining experience extends to related industries offering

solutions for hydrogen supply, sulphur management and NOx emission.Efficient hydrogen technology and catalysts from Topsøe ensure

optimised processes with low energy consumption to capacities from 5,000 to more than 200,000 Nm3/h hydrogen.

Topsøe’s WSA and SNOX™ technologies remove sulphur and nitrogen oxides from flue gases, recover the sulphur oxides as concentrated sulphuric acid and reduce the nitrogen oxides to free nitrogen. The SNOX™ process is particularly suited for purification of flue gas from combustion of high-sulphur petcoke and other petroleum residues such as heavy fuel oil and tars as well as sour gases.

Topsøe’s SCR (Selective Catalytic Reduction) DeNOx process is the most efficient process for removing nitrogen oxides from gases and is suitable for treating off-gases from a wide range of different industries and applications including fossil-fuel and biomass fired utility boilers, gas turbines, oil refining and chemical plants, stationary diesel engines and waste incinerators.

CONTACT INFORMATIONNymoellevej 55, DK-2800 Lyngby, DenmarkPhone: +45 4527 2000Fax: +45 4527 2999Email: [email protected]: www.topsoe.com

Experience the Sabin difference for PGM catalyst recovery and refining.

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The “science” of recovering and refining precious metal catalysts is straightforward: state of the art technology. The “art” of this process, however, is what makes Sabin different from all others: that’s the knowledge, experience, and expertise gained from seven decades of successfully serving thousands of organizations around the world. We’d

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RECOVERING PRECIOUS METALS FROM SPENT PROCESSING CATALYSTS

SABIN METAL CORPORATION

Sabin Metal Corporation is the largest secondary precious met-als refiner in North America, serving a worldwide customer base. We recover and refine PGMs from spent catalysts used for hydrocar-bon processing and end-of-pipe pollution control equipment. PGMs (Platinum Group Metals) include platinum, palladium, ruthenium and rhodium. Sabin Metal also recovers rhenium, gold, silver, and other precious metals from spent catalysts that typically are configured as pellets, beads, extrudates, and monolithic structures. Sabin recovers remaining precious metals from spent catalysts from soluble and insol-uble alumina, silica-alumina, zeolite, and carbon supports. Precious metals are also recoverable from waste byproducts associated with catalyst materials. We handle all details from suggestions on packag-ing and shipping/logistics through accurate materials tracking to final settlement with many options.

Advance labs. Sabin Metal offers the industry’s most advanced ana-lytical and processing capabilities, along with fair, straightforward treatment and high standards of service that we’ve provided to our customers for more than 65 years. These include detailed weights and analyses of their materials, and the ability to follow their shipments throughout the entire recovery and refining process. Catalyst samples are assayed in triplicate to assure accuracy and fairness.

Sabin Metal is unique in that it is one of the only precious metals refiners in the world to provide “full service” and full “in-house” capa-bilities (from door-to-door shipping/handling) through pre-burning, sampling, and assaying to prompt return of refined materials instead of employing outside subcontractors for one or more of these activities. Use of these outside services can reduce returns, increase process turnaround time, and negatively impact the environment. These outside services may also introduce possibilities of materials loss, which can result from third-party handling (repackaging, shipping, etc.).

Meets international rules. Sabin Metal’s analytical and processing facilities are the most advanced in the industry, along with fastest pos-sible processing turnaround time to reduce metals costs. We provide full documentation with regard to environmentally responsible handling and disposal of solids, liquids, or gaseous byproducts from our facilities. Because of complex rules, regulations, and laws (both internationally and domestically), Sabin Metal’s subsidiary, Sabin International Logistics Corp. (SILC) specializes in transporting large quantities of spent catalyst materials in compliance with the rules and regulations of the exporting country as well as the materials’ importation into the U.S.A. SILC oper-ates on every continent except Antarctica, and holds all required permits needed to transport materials to and from its refining facilities.

Refining at our processing facilities is accomplished through a wide variety of equipment including rotary, crucible and electric arc furnaces, kilns, roasters, thermal processors, pulverizers, granulators, screens, blenders, auto samplers, reactors, dissolvers, precipitators, electrolytic cells, and filter presses. Pyrometallurgical and hydrometallurgical tech-nologies are employed to achieve the highest possible metal recovery at the lowest possible processing costs.

Sabin’s analytical laboratory uses advanced X-ray fluorescence equipment, atomic absorption (AA) and inductively coupled plasma

(ICP) emission spectroscopy instrumentation and also employs classic volumetric, gravimetric, and fire assay techniques.

Our new 120,000-sq-ft. refining facility in Williston, North Dakota U.S.A. is specially equipped to sample and process precious-metal-bear-ing catalysts from hydrocarbon processes such as petroleum catalysts, vinyl acetate monomer (VAM) catalysts, and chemical catalysts. In-house “pre-burn” capability and electric arc furnace technology provide total-capability refining services for lower costs and faster turnaround. For full technical details about our facilities, capabilities, and services for recovering and refining precious metals from spent catalysts, please visit us at www.sabinmetal.com.

CONTACT INFORMATIONCorporate Headquarters: 300 Pantigo Place, Suite 102

East Hampton, NY 11937 Phone: 631-329-1717

Fax: 631-329-1985

Main Plant/Sales Office: 1647 Wheatland Center Road

Scottsville, NY 14546 Phone: 585-538-2194/Fax: 585-538-2593Web: www.sabinmetal.comEmail: [email protected]

Additional Facilities: Williston, ND; Cobalt, Ontario, Canada; Europe; Asia; Mexico; Latin America

This electric arc furnace represents the latest technology for recov-ering PGMs from spent catalysts.



Saint-Gobain NorPro has served the refining, petrochemical/chemical, environmental, and oil and gas production industries for more than 100 years, providing technology-driven ceramic solutions for process and manufacturing challenges. The company offers product solutions for fixed bed reactor processing, heat and mass transfer applications, drilling and exploration. We are the leading supplier of custom catalyst carriers, bed support media and proppants.

Processing feedstocks different from design presents unique challenges for today’s refiners. Maintaining desired unit cycle length is critical. As a result, the catalyst must be protected from contaminants that can cause increased pressure drop and fouling.

Saint-Gobain NorPro leads the industry with its MacroTrap® guard bed media—technology that “traps” contaminants. Use of the MacroTrap media leads to improved operational stability.

The key to MacroTrap® guard bed media filtration capability is the tortuous path created by the internal macropore structure that efficiently “traps” particulates inside the body of the ceramic media, thus extending unit performance.

MacroTrap® XPore 80 is the next generation of bed media protection. MacroTrap XPore 80 media has increased macroporosity with >80% internal void capacity, resulting in greater “trapping” capacity.

Saint-Gobain NorPro also introduces its newest innovation in bed topping media—Next Generation Bed Topping (NGBT) media. The NGBT media’s shape offers substantial gains in void fraction and surface area when compared to conventional sphere-shaped media, Raschig rings or other competing media. The immediate benefit of NGBT media is enhanced flow distribution, which in turn facilitates uniform distribution of feedstock.

Saint-Gobain NorPro is a wholly-owned subsidiary of Compagnie de Saint-Gobain, a multinational corporation with headquarters in Paris. Saint-Gobain transforms raw materials into advanced products for use in our daily lives, as well as developing tomorrow’s new materials.

CONTACT INFORMATIONPhone: +1 330-673-5860Email: [email protected]: www.norpro.saint-gobain.com

CERAMIC MEDIA TECHNOLOGY FOR IMPROVED FIXED BED REACTOR PROCESSING

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MacroTrap® XPore 80 guard bed media maximizes catalyst protection with increased macroporosity and interconnecting pore structure benefits.

Next Generation Bed Topping (NGBT) Media, a hold-down media that enhances flow distribution.

Have We Entered the Golden Age for Gas?The Gastech London conference begins with an exclusive opening address from Sir Frank Chapman, Chief Executive of BG Group, before opening out with a fascinating panel debate examining: “Have we entered the Golden Age for Gas?”

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• Hamad Rashid Al-Mohannadi, Managing Director – RasGas Company Limited & Vice-Chairman – Qatar Petroleum

• Bill Dudley, President & Chief Operating Officer – Bechtel Corporation

• Abdelhamid Zerguine, Chief Executive Officer – Sonatrach

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G as and vapor venting to the atmosphere from tanks and equipment may provoke hamful effects due to the flam-mable, toxic and corrosive properties of the released sub-

stances. Venting lines are generally connected to flaring or treat-ment systems, where they are burned or processed with the aim of preventing harm to personnel and the environment. Nevertheless, cold vents may not always be avoided, and, when they are feasible and environmentally acceptable, they offer significant advantages over alternative methods.

Cold venting is frequent in both onshore and offshore installa-tions, despite efforts made in the design phase to prevent or prop-erly manage the emissions. In these cases, applicable regulations and standards require identification of the quantitative features of the released streams. This narrows the engineering choices to consider the acceptability of a safe, open discharge by implementing the necessary protection. A general reference is given by API RP 521,1 which says that “disposal can be accomplished without creating a potential hazard or causing other problems, such as the formation of flammable mixtures at grade level or on elevated structures.” Also, NORSOK standards2 require that cold vents be based on dis-persion calculation results to prove that explosive mixtures are not created in the installation vicinity and to ensure that the concentra-tion therein does not exceed a fraction of the lower flammable limit.

Background. Open discharges should be considered when:• Safety valve releases from atmospheric tanks storing hydro-

carbons or organic compounds, in case of process offset or instru-ment failure

• Releases from rupture disks or emergency-relief valves (ERVs) from atmospheric tanks storing hydrocarbons or organic substances, in case of external fire

• Emissions from pressure equipment in onshore and offshore facilities; examples include methane emissions from common vent stacks or low-boiling, pressurized compounds.

Release from atmospheric tanks. Flammable and combus-tible liquids stored in atmospheric tanks are assumed to be blanketed with nitrogen working at a low relative pressure, as shown in Fig. 1. The working conditions are the operating temperature (TOP ) and the operating pressure (POP). The relieving scenario assumed for the pressure relief valve (PRV) is a control valve failure, with a set-ting pressure (PS1 ) and a corresponding temperature equal to TOP . Vapor pressure is given by the Antoine equation:

(1) PVAP -OP = 10

A - BC +TOP

The gas molar fraction corresponding to the set pressure can be calculated as:

(2) XS1 =

PVAP−OP

PS1

and the nitrogen molar fraction as:

(3) X N 2

= 1−PVAP−OP

PS1

The assumed relieving scenario for the ERVs is external fire, with a setting pressure (PS2 ). The nitrogen content in the tank head space is assumed to remain the same, whereas the gas amount will increase due to heating from fire. Accordingly, if the head-space volume does not change significantly, the second law of Gay Lussac may be applied:

(4) T fire =TOP ×

PS 2

POP

and the gas molar fraction (XS2 ) corresponding to PS2 is:

(5) PVAP−T fire

= 10A−

BC +T fire

Venting vapor streams: Predicting the outcomeLaminar and turbulent jet theories provide strong support when addressing cold venting situations

R. BENINTENDI, Foster Wheeler Energy Ltd., Reading, UK

To atmosphere at safe location

Emergencyrelief valve

PC

Nitrogen

Atmospheric tank relief scenarios.FIG. 1



(6) XS 2 =

PVAP−T fire

PS 2

where PVAP-Tfire is the vapor pressure at Tfire .

The gas outlet characteristics have now been completely iden-tified. For the purpose of this work, the released mass flowrate is essential information, being a venting design issue covered by the standard API 520.3 The described scenario has been sum-marized in Table 1, where input design data and calculated values have been included. The gas stripping from a solution can be approached in the same manner, using gas-liquid equilibrium equations, such as the Henry formula.

Release from pressure vessels. Cold venting from pres-sure vessels is much less frequent than atmospheric venting, and it consists of a pressurized gas or a vapor in equilibrium with its liq-uid. The first case, natural gas in offshore facilities, is completely defined by the pressure and the geometrical characteristics of the jet, and the second case can be treated as atmospheric blanketed storage, being that the substance in both of these cases is formed by a single compound under pressure.

Modeling. Modeling aims to describe the concentration con-tour of a gas jet downstream from a nozzle outlet, with reference to specific toxic or fire end points. As the gas leaves the nozzle, it is entrained by air, strongly depending on the fluodynamic features and on the wind velocity and direction. This results in a progressive gas concentration dilution as both the axial and the radial distance from the outlet increase (Fig. 2).

The theory of turbulent and laminar jet is based on the original studies of Ricou and Spalding4 and Schlichting,5 respectively. Momentum driven turbulent jets from relief valves are also cov-ered by the API 521 standard, and its conclusions fit well with the Ricou and Spalding theory of entrainment approach.

A full development of the jet air dispersion model relative to both turbulent and laminar regimes has been carried out by the author,6,7 with the aim of predicting the endpoint concentration contour of hazardous areas due to flammable substances. This method gives much more realistic results than those provided by the standard IEC 60079-10,8 as confirmed by Webber et al.9 The same models may be used to investigate whether (and to what extent) gas cold venting is harmful.

Turbulent jet. According to literature data6 and to the standard API RP 521, the fully turbulent regime exists from the Reynolds number of 104 upward. If it is verified, air entrainment works reducing the jet gas concentration according to the following general equation:

(7)

M ( y)Me

= Ce ×yD

Within the equation, Me and M(y) are the initial and the overall entrained gas mass flowrates at a distance y from the exit, D is the outlet diameter and Ce is the coefficient of entrainment, which is 0.32 according to Ricou and Spalding4 and 0.264 according to the standard API RP 521. This approach has been followed6 in order to define the distance along the axis, where the lower flammable or toxic endpoint is reached. Assuming a cross sectional average gas concentration, the jet development is as outlined in Fig. 3. Indicat-ing with EP the flammable or toxic endpoint, with MWG and MWA as the gas and air molecular weight, and XMo as the initial gas mass fraction, the mentioned distance is given by the following equation:

(8) yEP = X Mo×

1EP×MWG

−1

MWG

⎛

⎝⎜⎜⎜⎜

⎞

⎠⎟⎟⎟⎟⎟×MWA +1

⎡

⎣

⎢⎢⎢

⎤

⎦

⎥⎥⎥

Ce×D

Laminar jet. The laminar jet theory is based on the original work of Schlichting.5 Accordingly, the same calculation carried out for turbulent jet has been developed7 for the laminar regime, resolving the mass and momentum equations and obtaining an exact solution for the axial and radial concentration gradient. The jet surface, as defined by the points of space where the concentra-tion is the end point, is given by the following formula:

Core

D�

Transition

r(y) C(0,y)

y

C(r,y)

Fully developed flow

Jet flow showing gas concentration distribution.FIG. 2

y

Flammable/toxicendpoint

D

yEP

Turbulent discharge illustrating distance to flammable or toxic endpoint.

FIG. 3

TABLE 1. Atmospheric tank relief scenario

Design CalculationVariable Relief case Symbol input output

Operating temperature – TOP •

Operating pressure – POP •

PRV set pressure Control failure PS1 •

ERV set pressure External fire PS2 •

Fire temperature External fire Tfire • •

Gas concentration at PS1 Control failure XS1 •

Gas concentration at PS2 External fire XS2 •

PRV/ERV diameter – D •

Mass flow rate – •



(9) REP ( y) = y×

3×Xo×ve ×D2

32×EP×Δ× y−1× 64×π

3×ρe×Me

×μ

Within the formula, Δ is the gas diffusivity in air; ve is the gas velocity at the outlet; μ is the gas viscosity; Xo is the initial gas mass fraction; EP is expressed in the same unit; and Me is the initial average momentum. As for the turbulent jet, the distance along the axis, where the lower flammable or toxic end point is reached, has been determined as:

(10) yEP = Xo×

3×ve ×D2

32×Δ×EPMeanwhile, the maximum transversal distance REP is calcu-

lated as:

(11) REPMAX

= Xo×27×ve ×D2

512×EP×ΔIn Fig. 4, the endpoint contour has been depicted for a typical

application. In the previous equations, XMo and Xo are equal to 1 for pure gases.

End points for venting. Flammable and toxic endpoints must be defined for the substances under investigation. For fire and explosion cases, the lower explosion limit (LEL) is entered into Eq. 8 or Eq. 10, depending on the existing regime. Toxic clouds can be described in terms of immediately dangerous to life and health (IDLH), temporary emergency evaluation levels (TEELs), emergency response planning guides (ERPGs) and acute emergency guidance levels (AEGLs) or, in accordance with the applicable safety philosophy, more stringent values can

be assumed. Basic information can also be obtained relative to the occupational impact of venting, considering TLV-TWA and TLV-STEL indices.

The model can easily be adjusted in the case of a gas mixture containing more than one substance, other than the inerting gas only. In this case, with reference to the flammable endpoint, a mixture limit can be calculated using the Le Chatelier equation:

(12)

LELmix =1Xi

LELii∑

Within this equation, Xi is the single component molar fraction.The same additive mixture formula applies, as per the ACGIH

guidelines,10 to two or more hazardous substances having a similar toxicological effect on the same target organs or systems.

Applications. Table 2 includes data relative to an ethyl acrylate storage tank blanketed with nitrogen. The Reynolds number is higher than 10.000, so the turbulent model is to be used. The calculation has been carried out considering both the LEL and the IDLH, obtaining two very different results. Roughly, it could be concluded that fire and explosion hazards are unlikely, whereas the toxic scenario does not seem negligible. A further confirmation of the accuracy of the method may be found in the volume of J. L. Woodward edited by the CCPS.11 Here, the concentration profile drawn for a methane turbulent jet would fit very well with the values calculated through the model.

Final analysis. An exact method has been presented with the aim of predicting the outcome of an open discharge from tanks and equipment. The method has been split into two different equations,

REPmax

REP(y)

yEP y

R(y)

Laminar discharge illustrating distance to flammable or toxic endpoint.

FIG. 4

TABLE 2. Ethyl acrylate cold venting

Substance Relief Relief rate Discharge Calculation Refer. Set pressure, Vap. pressure, OutletItem Location released case kg/hr destination scenario temp., K mbarg mbar concent., %

PRV Atmospheric Nitrogen ethyl Control valve 500 Atmosphere Equilibrium @ 313 107 105 9.48 tank acrylate failure max. operating temperature

ERV Atmospheric Nitrogen ethyl External 35,000 Atmosphere Equilibrium @ 319 143 115 10.06 tank acrylate fire ERV set pressure

Outlet Outlet Mass flow Average Mass flow concentr., concentr., rate, IDLH, PVRV or ERV Outlet velocity, LEL, molecular weight Distance to Distance torate, kg/h ppm mg/m3 kg/h ppm diameter, m m/sec % at the outlet LFL, m IDLH, m

112.29 94,850.9 369,532.62 136.28 300 0.1016 12.64234 2 34.84 0.15 11.46

9,061.98 100,612.4 384,606.28 9,999.98 300 0.4572 44.01475 2 35.25 0.79 58.08

Wind

Hemispherical approach to endpoint contour. FIG. 5



depending on the fluodynamic regime existing at the jet outlet. The equations can be used in a very flexible way, since the contour describes the concentration field of the specific endpoint used, whatever it is. The results expected could be considered satisfacto-rily reliable, provided that the following boundary conditions exist:

• A steady state can be assumed• The jet does not impinge over adjacent obstacles and barriers• The equipment under investigation is not installed in a

congested zone, where closed spaces and a cul-de-sac can provoke hazardous gas accumulations and significant modifications of the concentration profile obtained using the entrainment equations

• Borderline cases or specific lay outing and spacing concerns should be further investigated through CFD and more accurate dispersion models; the method is very useful in giving a first esti-mate of the predictable outcome.

A specific mention must be made relative to the action of the wind, both on the laminar and the turbulent jets. Even if it results in an increased air entrainment, an uncertainty might exist about the direction of the plume and its profile. This is the case even if the standard API 521 states that, for high Reynolds numbers, the turbulent equation is valid anyway, provided that jet velocity is higher than about 12 m/s or the jet-to-wind velocity ratio is more than 10. The same standard shows how the effect of the wind, in terms of wind velocity to initial jet velocity ratio, is effective in reducing the endpoint vertical downwind distance; whereas, the horizontal distance is much less affected.

As a conservative application of the presented model, engi-neering judgment suggests extending the hazardous zone to the whole hemispherical volume of radius equal to the endpoint

distance (Fig. 5), and to use an endpoint concentration equal to 25% of its real value. HP

LITERATURE CITED 1 ANSI/API Standard 521, Pressure-Relieving and Depressuring Systems, Fifth

Edition, January 2007 (addendum May 2008). 2 NORSOK Standard S-001, Technical Safety, Fourth Edition, February 2008. 3 API Standard 520, Sizing, Selection and Installation of Pressure-Relieving

Devices in Refineries, Eighth Edition, December 2008. 4 Ricou, F. P. and D. B. Spalding, “Measurements of entrainment by axisym-

metrical turbulent jets,” Journal of Fluid Mechanics, 11(1), 21 e 32, Cambridge University Press, 1961.

5 Schlichting, H., Boundary Layer Theory, Sixth Edition, McGraw Hill, New York, 1968.

6 Benintendi, R., “Turbulent jet modeling for hazardous area classifica-tion,” Journal of Loss Prevention in the Process Industries, Vol. 23, Issue 3, pp. 373–378, May 2010.

7 Benintendi, R., “Laminar jet modelling for hazardous area classifica-tion,” Journal of Loss Prevention in the Process Industries, Vol. 24, Issue 2, pp. 123–130, March 2011.

8 IEC 60079-10-1 ed 1.0, Explosive atmospheres, Part 10-1: Classification of areas—Explosive gas atmospheres.

9 Webber, D. M., Ivings, M. J. and R. C. Santon, “Ventilation theory and dis-persion modeling applied to hazardous area classification,” Health and Safety Laboratory, Journal of Loss Prevention in the Process Industries, Vol. 24, Issue 5, pp. 612–621, September 2011.

10 ACGIH, Threshold limits values for chemical substances and physical agents and biological exposure indices, 2008.

11 Woodward, J. L., “Estimating the flammable mass of a vapor cloud,” CCPS, American Institute of Chemical Engineers, 1998.

Renato Benintendi is a loss prevention and process specialist at Foster Wheeler Energy Ltd. in Reading, UK. He holds a degree in chemical engineering from the University of Naples Federico II in Italy. He has been working for 25 years in process safety and environmental projects and has been a lecturer and a professor of process safety and environmental engineering at Salerno University and Naples University.


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I n the hydrocarbon industry’s early days, processes were rela-tively simple, and societal expectations regarding safety were low by current standards. With the development of newer process

technologies, complexity increased while societal expectations for safety in all industrial activities also rose. Since accidental loss of containment can result in unacceptable process safety incidents such as fire, explosion or toxic release, a robust system for manag-ing safety should be in place. Such a system should address safety vulnerabilities and employ focused safety audits that help identify physical conditions in need of corrective measures.

Hazards. Refining is challenging because of the large number of processing units at each plant (Fig. 1). Crude and vacuum distilla-tion units (CDU/VDUs) require attention, along with a number of complex, second-ary units like fluidized catalytic crackers, delayed cokers and visbreaking units. Refin-eries also have to manage hydrogen alloca-tion and the catalysts used to maximize dis-tillates and improve stream qualities. Each of these elements intensify potential hazards.

Audits. A quality plant safety manage-ment program embraces audits of all stripes. These include leadership and management evaluation, risk identification, risk manage-ment and monitoring procedures. These evaluations should determine if management actions prevent human injury, limit equip-ment and property damage, protect the envi-ronment, comply with legislative regulations, reduce risk and minimize loss exposure. As a part of the audit’s verification phase, the plant’s process safety culture should be scru-tinized to determine management’s ability to prevent catastrophic accidents, explosions, fires and toxic releases. Such competence is verified by auditors through discussions and field checks/inspections of the facilities, comparisons with best practices, evaluation of safe design standards, and observation of operating and maintenance practices.

Risk identification. Risk identification requires the participation of all employees.

Safety committees should be deployed at every employment level, from the bottom to the top. Each safety committee needs to carry out internal health, safety and environment (HSE) audits and inspections through focused inspection checklists. Each of the disparate units in a refinery presents its own set of challenges, but all audits of each unit should focus on operation control systems, work permit system implementation, written procedures and standing instructions. Within this common framework, though, are different audit strategies for specific units. What follows is an itemization of such strategies.

Crude and vacuum distillation units. CDU/VDUs (Fig. 2) are the primary units in a refinery, and, in certain facilities, these units are likely to be the oldest and most debottlenecked. The units,

Apply audits to reexamine safety proceduresRecognizing distinctive vulnerabilities in various refinery units

S. L. CHAKRAVORTY, Oil Industry Safety Directorate, New Delhi, India

ATU-I

ATU-II

SR LPG treater I

SR LPG treater Il

Amine reg.

Amine reg.

SWS

SWSFuel gas

Sulfur

LPG

Naphtha

PX feed

Gasoline

ATF

Kero

HSD

HPS

Bitumen

IFO

Coke

SRU

SRU

LPG

Gasoline

DHDS

DHDT

HCU

OHCU

RFCCU

CCRHGU-I

HGU-II

NSU-I

NSU-II

Kero

VISbreaker

BBU

DCU LPG

Naphtha

KeroLGO

HGOAVU-I

AVU-II

&

CrudeVGO

Vac.diesel

Vac. residue

Layout of a typical refinery. FIG. 1



which run at high temperatures of up to 434°C, have some typical vulnerabilities. For instance, column operating temperatures are generally above auto-ignition temperatures for the heavier product fractions (kerosine, gasoils, reduced crude, vacuum distillates and all residues including short residues), and any leak will invariably result in a fire incident.

The plant design must employ the correct metallurgy for the range of sour and sweet crudes typically processed. Plant corrosion mitiga-tion programs are essential, along with a good desalter operation.

Small air leaks in VDUs can result in combustion within a fuel-rich environment. Vacuum-hold testing during unit commissioning is, therefore, very important to make sure all eqipment conforms to the stipulated test norms. Inadequate lockouts, de-energizing and energizing the rotating equipment provide other possible pitfalls.

Operation of a VDU under abnormal or emergency conditions, especially during startup, is a concern. Both rotary and station-ary equipment will be under stress. Clearly written instructions enumerating approved procedures for unit operation are essential.

A history of incidents at these units should be compiled. Some common incidents in CDU/VDUs include explosions inside the furnace during startup, a fire due to a leak through piping in column bottom pumps, mechanical seal leaks in pumps and overhead system leakage. The absence of clear-cut instructions and deviations from written procedures have also led to accidents.

Other units. Catalytic reforming units, naphtha hydrotreaters and isomerization units all involve the handling of hydrogen under high pressures and temperatures. Since hydrogen has explosive lim-its of 4%–74%, very little energy is required to ignite it. Hydrogen mishaps can stem from procedural deficiencies, material failures or material incompatibility. Operational and work area deficiencies and design flaws are other common causes of trouble. Since these units operate at a high temperature involving hydrogen and cata-lysts, the equipment must withstand mechanical stress from internal pressure and thermal excess. Policies should be in place, to address hydrogen leaks from flanges, tube ruptures or process upsets.

Legend: Preheat exchangers

Vac bottompump

Columnbottompump

Vac. furnacepump

Crudefurnace Vac.

column

Crudecolumn

To ejectors

Crude oil SR topreheatcircuit

A typical crude and vacuum distillation unit.FIG. 2

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Delayed coker. Events that contribute to hazardous delayed coker unit (DCU) operations include coke drum switching, coke drum head removal and coke cutting. Coke transfer, processing, and storage can also lead to safety incidents. Because of these fac-tors, emergency evacuation policies should be reviewed regularly. Workers at a DCU run the risk of toxic exposures, dust irritants and burn trauma.

Fluidized catalytic cracker units (FCCUs). FCCUs upgrade heavy hydrocarbons to lighter, more valuable products by cracking at high temperature in the presence of catalysts. Safety vulnerabili-ties specific to FCCUs are numerous (Fig. 3). Risk can escalate when the operation is nonroutine (especially during startup and shutdown), and when equipment maintenance is taking place or utility disruption has occurred. There is significantly more wear and tear on the process equipment during these intervals.

Unstable catalyst circulation in FCCUs can lead to surges in the pressure and temperature balance. During these activities, a significant amount of expansion and contraction occurs and exces-sive stress is placed on the equipment. This can lead to the opening of process flanges and subsequent hydrocarbon leaks and fires.

The bottom of the main fractionator is also vulnerable because it handles high temperature oil above the flash point. Vigilant maintenance is required to prevent fouling. Yet another high haz-ard operation involves changing the reactor vapor blind. Exposure to toxic gases during deblinding and blinding is a preventable error.

Hydrocracker unit. Many refineries employ hydrocracking technology to convert heavy hydrocarbon oils into lighter and more valuable products. One safety concern with hydrocrackers is the possibility that the heat generated in the reaction will raise the tem-

perature of the catalyst bed, leading to increased reaction rates and more heat generation. This effect can spiral out of control and result in a potential loss of integrity of the reactor vessel or piping due to excessive temperature. In an emergency situation, depressurization can stop the reaction. When depressurizing, the reactor pressure and partial pressure of the hydrogen decrease and the reaction rate quickly falls off. However, a delay in depressurizing the reactor can result in a temperature excursion leading to a major catastrophe.

Improper reactor pressurization, heating or cooling can lead to embrittlement in a hydrocracker. The unit handles large amounts of hydrogen sulfide in its high-pressure and sour water system

Column bottompump

Vaporblind

FeedCombustion air

Main fractionator

Reactor

Catalystregenerator

Spentcatalyst

Reg.catalyst

Typical FCC unit at a refinery.FIG. 3

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and any sour water system leak can be extremely dangerous.Offsite storage and handling. Petroleum products are nor-

mally stored above ground at atmospheric pressure, within low pressure storage tanks or in underground tanks. Distribution of petroleum products from storage is executed via truck, pipeline, tanker or barge. Fire and explosions are a potential danger result-ing from leaks or overflow of the storage tanks. During loading and unloading activities, these dangers are particularly acute. Pos-sible ignition sources include sparks associated with the buildup of static electricity, lightning and open flames. Pipes and other ancillary equipment are also potential sources for an incident.

Sulfur block. This section of the refinery usually includes the sulfur recovery unit, sour water stripper and amine units. One source of possible trouble here involves the offgas from the sour water stripper and amine regeneration unit. This offgas contains a high percentage of toxic hydrogen sulfide, and any leak from the system can result in toxic exposure to operating personnel.

The sulfur recovery unit is prone to chokage. Dechoking can happen by shifting the unit to fuel gas mode, but this might result in a runaway reaction that leads to auto-ignition of sulfur deposits which opens process lines and thus exposes hydrogen sulfide. It should also be noted that the sour water containing hydrogen sul-fide cannot be released to an open sewer, which otherwise would cause flashing of dissolved hydrogen sulfide into the atmosphere.

Flaring. A flare is a pressure safety relief device used to ensure that the equipment does not exceed the safety limits set to maintain the process unit’s integrity. A flare’s function is to eliminate excess process gas by burning it off. However, a flare ignition failure may lead to unburned venting of dangerous gases, creating an explosion

hazard. The effectiveness of flaring is dependent upon one or more continuously burning pilots for immediate and sustained ignition of gases exiting the flare burner. Since pilot failure can compromise safety and effectiveness, it should be detected quickly and accurately to allow for prompt response from an operator.

Air entry into the flare header system can be catastrophic. A safety rule of thumb here is to allow no flow conditions that can lead to a vacuum in the flare header. Another common malady is the abnormal loading of flare headers due to the sudden release of a flare discharge during a plant emergency.

Know the vulnerabilities. Hazard audits and risk identifi-cations are key to maintaining a safe plant. Process and personal safety incidents should lead to a variety of thorough examinations. The work permit system for maintenance activities should include confined space entry and hot jobs. Standard operating procedures at the facility must be clearly spelled out, especially with regard to startups, shutdowns and abnormal situations. Electrical safety (including static electricity) should not be overlooked. Ample personal protective equipment needs to always be available.

Management needs to carry out HSE reviews at all levels, focusing on agenda items such as near-miss incidents and root causes. The internal audit recommendations should assign respon-sibilities for each action item. The progress of these HSE reviews should be monitored through safety meetings. Top management also needs to provide financial and technical support for risk minimization. By recognizing vulnerabilities and taking action to address such weaknesses, management and employees can run a safe and incident-free plant. HP

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CLEAN FUELS


Methanol contamination of naphtha: A case studyCreative problem solving was used to upgrade off-spec export products while minimizing tank storage

F. OVAICI, Al-Ghurair Energy, Dubai, United Arab Emirates

I n this article, a refiner needed a solution to recover export-ori-ented naphtha contaminated by methanol (MeOH). This is an actual case in which one of three 30,000-m3 capacity tanks used

to store naphtha export was found to be severely contaminated with MeOH. A water-washing solution was applied to reprocess the naphtha in-situ and to remove MeOH from the naphtha, along with returning the storage tank back to continuous operations.

Problem-solving approach. The approach to solving prob-lems such as this type is threefold. First, understand the root cause of the incident and rectify it. Second, develop a theoretical basis to resolve the problem and validate it. Third, evaluate and imple-ment a practical solution.

Contamination mishap. Naphtha contamination with oxygenates, such as MeOH, is a costly problem for any refinery. Reprocessing or re-blending naphtha is a risky proposition, espe-cially when only limited storage is available. A creative and scien-tific water-washing solution was identified to remove oxygenates from the naphtha. Understanding the chemistry of the problem is only the first step. Substantial laboratory and engineering work was necessary to successfully identify and to validate the solution.

PROBLEM: MeOH CONTAMINATION IN NAPHTHA TANKThis Middle East refinery exports straight-run naphtha (SRN)

from the crude distillation unit (CDU). There are three storage tanks available to store, blend and certify the naphtha prior to shipping. The refinery also operates a tertiary amyl methyl ether unit that uses imported MeOH as a feedstock.

Following a routine MeOH unloading at the refinery, 25,000 m3 of SRN product in an export 30,000-m3 storage tank was later found to be contaminated. This naphtha failed a product-certification test. Contamination results were further confirmed by a third-party laboratory.

Test results of the SRN showed an oxygenate content of 240 ppm against the maximum acceptable level of 50 ppm to obtain a quality certificate. Unfortunately, the SRN of this tank could not be exported. Now, there were only two naphtha tanks left in operation. The quantity of material and oxygenates prevented meaningful re-blending and reprocessing. Contamination of the other two tanks remained a real and immediate threat to plant operations. During the incident, naphtha rundown from the process plant was continuously showing acceptable oxygenate content that was less than 50 ppm.

Step 1: Identify and rectify root cause. The investigat-ing team successfully determined the root cause for the MeOH contamination. The investigation revealed that both the meters installed on the line to the jetty for naphtha export and the meter on the MeOH import/unloading line share the same meter prover. A single cross valve on the meter prover was mistakenly left open. Pressure differential allowed imported MeOH from the vessel to flow unimpeded to the naphtha-product line from the CDU to the storage tank during unloading of the cargo vessel.

Rectification of the problem involved strict new operating procedures for the meter and meter prover. Operator training was improved, and it focused on careful handling of equipment with checklists and verification by foremen. For the long-term solution, a separate meter and meter prover would be installed.

Different ways of disposing the off-spec naphtha were stud-ied. However, disposal could impose higher financial losses to the company due to contamination of the naphtha lines to the jetty. Moving the material to other tanks had a higher inherent risk of cross-contamination for the remaining product-storage tanks. At that time, no buyer could be found to purchase this

8+

+ +

Oxygen atoms

More negative changes–

–

– –

– –

–

––

–

Hydrogen atoms

More positive charges

Water is a polar molecule with positive charges on one side and negative charges on the other.1

FIG. 1

CLEAN FUELS


batch of off-spec naphtha. Unfortunately, the MeOH-contam-inated naphtha remained in the tank for several months as vari-ous options were considered.

Step 2: Theory and validation. The rule for determining if a mixture becomes a solution is that polar molecules will mix to form solutions and nonpolar molecules will form solutions, but a polar and nonpolar combination will not form a solution. Both MeOH and water are polar. So extraction of MeOH in an aqueous solution is a feasible pathway. The geometry of the atoms in polar molecules is such that one end of the molecule has a positive electrical charge and the other side has a negative charge. Nonpolar molecules do not have charges at their ends. Mixing

molecules of the same polarity usually results in the molecules forming a solution.

Low-molecular-weight alcohols, such as MeOH, are com-pletely soluble in water. Because of their polar structure, the alcohol molecules actively associate with water molecules through the hydrogen bonds. The hydrogen bonds are strong enough to prevent separation of the water/alcohol mixture by distillation, as shown in Fig. 2.2

Various molecules may mix and dissolve in each other if they have approximately the same polarity. In the case of water and MeOH, this is the situation. The hydrogen of the –OH group on the alcohol is polar in the same manners as the water molecule.

Solubility of MeOH in naphtha. In terms of polarity, MeOH is a strong polar molecule, and aromatics, such as toluene, are slightly polar. Paraffins, such as hexane, are nonpolar. Aromat-ics will be temporarily polarized within the vicinity of a polar molecule (MeOH), and the induced and permanent dipoles will be mutually attracted (Debye Interactions). However, MeOH is not completely soluble in streams, such as SRN that contain low levels of aromatic compounds. Paraffinic/naphthenic hydrocar-bons (HCs) comprise 90 wt% of the SRN, and the remaining

TABLE 1. SRN water-washing effects on T6217C

Mixing with magnetic stirrer Without mixing Water inject, Oxygenates Methanol Moisture, Water inject, Oxygenates Methanol vol % content, wt ppm content, wt ppm ppm Remark vol % content, wt ppm content, wt ppm Remark

0 220.4 196.5 140.7 Top/Mid/Btm: 190.4/ 0 220.4 196.5 188.8/151.5 (MeOH)

1 44.1 22.7 147.8 Color: No change – – –

5 30.9 12.8 165.7 Color: No change 5 160.9 141.6

10 18.2 1.4 170.8 Color: No change 10 90.2 72.6

20 17.1 1.8 177.0 Color: No change 20 98.0 80.5

• Magnetic Stirring Duration 10 min• Settling Duration 1 hour (end table 1)

TABLE 2. Effect of MeOH removal from naphtha at different water addition rates with/without mixing

SR naphtha (T6217C) water-wash oxygenate result Sample date: Feb. 15, 2008

With H2O wash With H2O Wash Before H2O wash (10 mins mixing/1 hour standby) (no mixing)

Case 1, Case 2, Case 3, Case 4, Case 5, Case 6, Case 7, 1 vol% 5 vol% 10 vol% 20 vol% 5 vol% 15 vol% 25 vol%Component, wt ppm Top Mid Bot Comp H2O H2O H2O H2O H2O H2O H2O

Ethyl methyl ether 3.0 2.7 2.7 2.7 2.3 2.4 2.3 2.4 2.2 2.3 2.3

MTBE 1.8 1.8 1.8 1.8 1.4 1.4 1.4 1.5 1.3 1.3 1.4

Isopropyl ether 0.0 0.8 0.8 0.9 0.0 0.0 0.0 0.0 0.8 0.0 0.0

Butyl methyl ether 0.9 0.9 0.8 0.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Methanol 190.4 188.8 151.5 196.5 22.7 12.8 1.4 1.8 141.6 72.6 80.5

Acetone 1.0 1.0 0.9 1.0 0.8 0.6 0.4 0.3 0.8 0.6 0.7

2-Butanone 8.6 8.3 8.1 8.3 7.0 6.8 6.2 5.5 7.1 6.6 6.6

Methyl butyrate 1.7 1.5 1.5 1.6 1.4 1.3 1.3 1.3 1.4 1.3 1.3

Hexanol 1.6 1.4 1.4 1.4 1.2 1.2 1.2 1.1 1.2 1.2 1.1

2-Pentanone 3.1 3.0 2.9 2.9 2.5 2.5 2.5 2.4 2.5 2.5 2.4

2-Butanol 1.5 1.5 1.5 1.5 1.2 1.0 0.7 0.0 1.2 1.1 1.0

Tertiary amyl methyl ether/alcohol 1.0 1.0 1.0 1.0 0.8 0.8 0.8 0.8 0.8 0.8 0.8

Total oxygenates 214.5 212.6 174.9 220.4 41.1 30.9 18.2 17.1 160.9 90.2 98.0

TABLE 3. Water requirement for each water-wash cycle

Basis—Based on Option 1Description Remarks

Contaminated naphtha in T6217C 25,000, m3

Demin. water for water wash 1%

Demin. water for water wash 250, m3 ~ 10 m3/hr will be required

CLEAN FUELS


10% are aromatic HCs. Therefore, the MeOH and naphtha are not soluble in any large ratios.

SRN, depending on the crude type processed, normally con-tains 8 wt%–10 wt% of aromatics. MeOH solubility in aromat-ics is temperature dependent. Essentially above 0°C, for every percentage of aromatics present, 0.5% of MeOH will be soluble. Following this rule, it is expected that the SRN can dissolve up to a maximum of 4 wt%–5 wt% MeOH.

Laboratory testing was proposed and arranged. Test samples with different water concentrations were added to known volumes of the off-spec naphtha—0% water content in naphtha was the control sample with 1%, 5%, 10% and 20% water concentration standards tested. To investigate the effect of thorough mixing, the samples were analyzed with and without a magnetic stirrer used. Table 1 summarizes the lab results.

Another set of tests was done on the samples from the con-taminated tank to measure the effect of water washing at different vol% of water to remove the various oxygenates from the con-taminated naphtha. Test results show that water washing removed the majority of the MeOH content from the naphtha while other oxygenates were not affected. Table 2 lists these test results at dif-

ferent water-wash volumes with and without mixing. Fig. 4 shows the appearance of the SRN after water washing at different vol% of water with a one-hour settlement time and the settled water drained from the sample. These tests showed that there was not much difference in haziness of the naphtha when different volumes of wash water were used. The lab report can be summarized as:

• MeOH and total oxygenate content decrease dramatically to within specs (50-wppm maximum) when the contaminated naphtha was water-washed with subsequent mixing (by a mag-netic stirrer similar to actual tank mixing). The MeOH content remained high when mixing was not done.

• There was no change in color and the product was not hazy.• There is only a slight increase in water content after the

sample remains stagnant if water is not drained.

H

H

H

H

H

H

H

H

H H

H

H

H

H

H

H

CC

C

C

C

C

= hydrogen bonding

Source: C. Ophardt © 2003

MeOH-hydrogen bonding

C C

MeOH hydrogen bonds and polarity.2FIG. 2

250

200

150

Oxyg

enat

es, p

pm100

50

00 1 5

Water content, vol%

Oxygenates contentMethanol contentMoisture

10 20

Lab results of water washing of contaminated SRN.FIG. 3

Haziness of treated naphtha after water washing with different water volumes.

FIG. 4

TABLE 4. Estimated time for each activity during each water-wash cycle

TimelineNo. Activity Remarks

1 Time for filling water, @ 10 m3/hr 25 hr

2 Mixing by tank mixer 24 hr

3 Settling time, maximum 24 hr

4 Water draining time, @ 25 m3/hr 10 hr

5 Sampling and analysis 0 hr Sampling and analysis to be done during settling and draining

Total time 83 hr 3.5 days

DW tanker

DW was pumpedusing the pump of

a water tankerNaphtha tank

T6217C

30 ft

4-in.

200 m offire hose

Process scheme for Option 1: Direct water injection to tank.

FIG. 5

CLEAN FUELS


The tests also confirmed the understanding that, if water wash-ing is done together with mixing, MeOH removal would be more efficient. Based on these results and the lab report, it was also decided that the contaminated naphtha should be washed with demineralized (DM) water.

Lab results showed that 10% water addition to the naphtha with mixing would reduce the MeOH content from 190 ppm to 1.4 ppm, while 1% water can reduce it from 190 ppm to 22.7 ppm. Subsequently, it was decided to inject only 1% of water wash and to drain after mixing, and repeat several times, until the total oxygenate concentration dropped to less than 50 ppm. Using this method, less DM water would be used, thus, limiting cleanup costs and time to recover the product naphtha.

Step 3: Effective implementation. Now that a lab-scale solution was available, the emphasis shifted to execution. Several ideas were considered, with three of the most viable choices listed here:

Option 1. Direct water injection to tank. Water can be pumped directly into the tank T6217C. After injection, the SRN could be mixed with the aid of an available tank mixer. Advantages of this process were:

• Water can be introduced through a larger nozzle (4-in. size).

TABLE 6. Moisture content of naphtha water settlement

Moisture content Top Middle Bottom

Feb. 28 @ 11:30 H 194 200 200

Feb. 29 @ 11:00 H 171 187 184

March 1 @ 08:10 H 194 200 215

March 4 @ 13:45 H 1,640 1,700 1660 Free water was detected

March 4 @ 20:45 H 181.3 182.5 176.2 After 7 hr settling @ lab

March 4 @ 22:45 H 1,82.7 187 187.8 After 9 hr settling @ lab

TABLE 5. Water-washing effect on SRN in T6217C SRN

Test parameterDate T6217 SRN Oxygenates, ppm MeOH, ppm Chlorine, ppm Remarks

Feb. 26 @ 0400 H Top 242 219 < 1 Before water washing Middle 242 220 < 1 DM water 3.4/1.7/Nil(4) Cl ppm Bottom 245 223 < 1 Composite 242 220 < 1

Feb. 28 @ 11:30 H Top 64 47 1st water washing Middle 48 30 Bottom 53 36 Composite 54 36

Feb. 29 @ 11:00 H Top 61 42 1st water washing Middle 61 43 Bottom 58 41 Composite 60 41

March 1 @ 08:10 H Top 59 41 1st water washing Middle 60 42 Bottom 62 44 Composite 60 41

March 4 @ 13:45 H Top 46 23 2nd water washing Middle 37 16 9 hr settling @ lab Bottom 41 17 Composite 41 19

March 5 Top Middle Bottom Composite

Tank mixing patterns for Option 1: A and B.FIG. 6

9 hours

6 hours

3 hours

Tank mixing pattern

CLEAN FUELS


• The associated lines would not be contaminated.• The procedure can be done several times. In case of failure,

the other two naphtha tanks would remain available for rundown and dispatch.

The disadvantages included:• Mixing will require a longer time. • Mixing may not be as effective as circulating the SRN to

and from the tank.The tentative time required for each cycle of water, assuming

1% DW will be mixed to the naphtha tank and drained after mix-ing and settlement, are summarized Tables 3 and 4.

Option 2. Water injection via export piping. Naphtha inven-tory of the tank can be circulated by way of marine-loading pump. Water can be put into the suction line of the pump—0.75-in. nozzle with two nozzles with a capacity of 3 m3/hr per nozzle. The resulting mixing could be done by the pump itself and would not rely on the effectiveness of the tank mixer. The advantages of this option include:

• There is thorough mixing of SRN and water• The mixing time will be shorter• The experiment can be carried out several times. In case of

failure, the other two tanks will be available for rundown and dispatch.

However, the disadvantages are:• Associated pipelines will have to be flushed thoroughly with

on-spec naphtha• Limitations would have to be imposed on the scheduling of

naphtha shipments.Option 3. Water injection and mixing using remaining

tanks. Water can be sent to one of the other tanks (T6217 A/B. The T6217C can be transferred to it. The advantages from this option include:

• There is thorough mixing of SRN• The mixing time will be less, as the SRN can mix while it

is filling the tank.Conversely, the disadvantages are:• Only one tank will be available for operation.• If the procedure fails for any reason, then the additional tank

also contains contaminated naphtha.• Associated pipelines will have to be flushed thoroughly with

on-spec naphtha• Naphtha shipment schedules would be affected.

SOLUTIONOption 1 was selected as the preferred method. As per the plan,

1% DW or 250 m3 of DW would be injected directly to the tank. The tank mixer would be used to mix the SRN and DW, followed by tank settling and draining of settled water. This procedure would be repeated as required until the naphtha is completely washed and meets all oxygenate specifications.

Successful water-washing plan. Water injection to the tank started on Feb. 26 during the day shift. Table 5 shows the result of oxygenates, MeOH and chlorine content of the naphtha before and after the water washing. Water draining started right after nine hours of settling. After the first water wash, the oxygen-ate level dropped to 60 ppm, close to spec, from the average result of 240 ppm. Therefore, after the water was drained, a second water-wash operation started on March 4, after which the total oxygenates dropped to 40 ppm; both were acceptable and on-spec. Fig. 8 shows how the oxygenate level changed with water washing.

Table 6 summarizes the moisture content of the SRN before and after the water-washing operations. The SRN then received a qual-ity certificate and it was successfully exported. The refinery contin-ues to successfully operate with all three naphtha tanks in service, and with no further incidents of MeOH contamination. HP

LITERATURE CITED 1 http://www.school-for-champions.com/chemistry/polar_molecules.htm. 2 http://www.elmhurst.edu/~chm/vchembook/162othermolecules.html.

Farzad Ovaici received his MSc degree in chemical engineering from Shiraz University in 1978. In 1979, he began his career with Bandar Imam Petrochemical Co. in Iran. In 1980, he moved to the Isfahan refinery. Mr. Ovaici was later responsible for reconstruction and rehabilitation of Abadan refinery, a 630,000-bpd refinery. This refinery severely damaged due to the Iran-Iraq War. In 1992, he

joined Tabriz Petrochemical Co., and was assigned as project director for EB/SM, and different polystyrene plants. Later, he was assigned as chairman and managing director of Tabriz Petrochemical Co. In 2000, he became the managing director of Kala Naft Canada Ltd. Mr. Ovaici received an M. Sc. degree in engineering from the Chemical and Petroleum Engineering School of University of Calgary. He is a member of the Association of Professional Engineers Geologists and Geophysicist of Alberta Canada. In 2005, he moved from Canada to Oman and joined Oman Refinery Co. as the general manager, of the Mina Al-Fahal Refinery. Later, he was promoted to general manager of the two refineries in Oman Refineries and Petrochemical Co. Mr. Ovaici joined Al-Ghurair Energy as the managing director, of refining and petrochemi-cals and is based in Dubai, UAE. In addition to his position in Al-Ghurair Energy, Mr. Ovaici is currently chief executive officer of Libyan Emirates Oil Refining Co.

DM water

Naphtha tank

18 in.

30 in.

0.75 in.

To jetty

Processing scheme for Option 2: Water injection via export piping.

FIG. 7

0 0

1

2

3

4

50

100

150

Oxyg

enat

es, p

pm

Chlo

rine,

ppm200

250

300

Feb. 26 Feb. 28Date

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WILLIAM GOBLE, CONTRIBUTING EDITOR

HPIN AUTOMATION SAFETY

[email protected]

Under recent economic conditions, it is understandable that a control-system cyber-security audit is not the top priority for many plant operators. Less staff due to layoffs and deferred maintenance can present a clear, tangible threat to operations. Too often, “the imaginary hacker,” discussed in many papers and blogs, is often considered as a non-credible threat. No matter how many blogs, magazine articles and white papers are written, a real credible threat to a refinery or petrochemical facility from some vague person or organization seems “imaginary” to those controlling plant budgets.

Stuxnet—The structure of cyber-attacks. Some believed that control-system cyber-security threats would be clearly credible after the 2010 Stuxnet incident. Stuxnet is rogue software; it was created to penetrate and breech Sie-mens programmable logic controllers (PLCs) in Iran. The rogue software actually infiltrated the system. Stuxnet reached the controllers and modified the programmed control logic. This code was very specific and targeted nuclear-fuel process-ing. The allegations are that a well-financed organization was responsible for the attack. I recall first reading about this event and thinking “this is no real problem for anyone not making nuclear fuel.” The real threat to the hydrocarbon processing industry (HPI) is negligible.

Later, I learned that the Stuxnet code was completely reverse engineered and, more importantly, posted on hackers websites. Now, these techniques, created with all that engineering effort and funding, were available to every individual or organization that had a web browser. The true problem is that this software/code can now provide “evil groups” the tools to facilitate attacks on any manufacturers’ control/automation products for any application—not just nuclear-fuel processing. All HPI facilities are vulnerable, and it is time to worry.

Control systems—The new market for ‘security researchers.’ Again, control-system cyber-attack risk levels have increased. I read articles describing how many individu-als, and even companies, are working to discover the vulner-abilities present in industrial controllers. Since Stuxnet, these researchers have realized that there is a whole new category of potential customers. Some researchers publish, and even pres-ent, this information at hackers’ conferences. Others contact the compromized controller manufacturer and offer to sell the vulnerability information. If no sale is made, then they publish and/or present it to the world. In conversations with my IT friends, I understand that this is a normal practice in the personal computer/server world. Finding the attack points within systems is the latest path to fame and glory in the hacker community. Something about this business model is most unethical.

All this news means that the industrial control community is now a target. Gone are the days of flying below the radar of the imaginary hacker. Although the Repository of Industrial Security Incidents (www.risi.org) has recorded hundreds of incidents, few were caused by deliberate malicious hackers. It’s too bad that things have changed. Today, tremendous volumes of information are being published addressing how to cause trouble in process control/automation systems.

Defensive actions. Fortunately, a number of very practical defense techniques have also been published. The ISA SP99 zone and conduit concepts, combined with a systems-level audit, is a simple and effective technique that provides some protection. Some control-system vendors are upgrading their software to meet requirements of the ISA Security Compliance Institute for embedded systems. That will provide more layers of protection.

Although we have much to learn about cyber-security protec-tion, I believe that some protection is a whole lot better than none. I am reminded about an old story. Two hikers were out in the woods when they suddenly encountered a grizzly bear. The bear spots them and rises up on its hind legs and roars. The first hiker yelled, “I’m sure glad I wore my running shoes today.” The second hiker replied, “It doesn’t matter what kind of shoes you’re wearing; you are not going to outrun that bear.” “I don’t have to outrun the bear, I just have to outrun YOU,” the first hiker answers back.

I can imagine a hacker trolling the Internet looking for vul-nerable control systems. Systems that are easier to hack are the most likely targets. So, I am thinking that the basic, cost-effective cyber security measures are good prevention options, at least for now. The best policy is to “outrun” other control systems and, hopefully, avoid being cyber attacked. HP

The imaginary hacker


The author is a principal partner of exida.com, a company that does consult-ing, training and support for safety-critical and high-availability process automa-tion. He has over 25 years of experience in automation systems, doing analog and digital circuit design, software development, engineering management and mar-keting. Dr. Goble is the author of the ISA book Control Systems Safety Evaluation and Reliability. He is a fellow member of ISA and a member of ISA’s SP84 commit-tee on safety systems. Dr. Goble can be reached by e-mail at: [email protected].

■ There are ‘boogey’ monsters

trolling the Internet with the intent

to cause chaos and possibly harm

HPI facilities

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