RENTECH breaks new trails in the boiler industry with its focus on custom engineering and design. There’s no “on the shelf” inventory at RENTECH because we design and build each and every boiler to operate at peak efficiency in its own unique conditions. As an industry leader, RENTECH provides solutions to your most demanding specifications for safe, reliable boilers. From design and manufacture to installation and service, we are breaking new trails.
APRIL 2012
HPIMPACT
SPECIALREPORT
BONUSREPORT
Energy for economic growth
PETROCHEMICAL DEVELOPMENTS
ROTATING EQUIPMENT
Canadian oil sands alliance
Innovative chemistry and catalysts improve profitability
New seal designs enhance operations and reliability
www.HydrocarbonProcessing.com
Unlike a phony cowboy who is all hat with no cattle, a boiler from RENTECH will pass muster. Each boiler is designed and built to meet its demanding specifications and operate in its unique conditions in a variety of industries, including refining, petro-chemical and power generation. Our quality control system assures you that RENTECH boilers are safe, reliable and efficient. For a real, genuine, original boiler, you can depend on RENTECH. Honestly.
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APRIL 2012 • VOL. 91 NO. 4 www.HydrocarbonProcessing.com
SPECIAL REPORT: PETROCHEMICAL DEVELOPMENTS
41 47 55 59 67
Optimize olefin operations This operating company used process models to find solutions to poor separation performance K. Romero
Alternate feedstock options for petrochemicals: A roadmap New hydrocarbons will be needed to meet future demand S. K. Ganguly, S. Sen and M. O. Garg
Improve catalyst management at the FCC unit System revamp reduces unloading time, boosts refinery operations M. L. Sargenti, N. Ergonul, M. Scherer, H. Upadhyay, R. McClung and T. S. W. Al Rawahi
Operational optimization for mixed-refrigerant systems Use rigorous simulation to improve process efficiency J. Zhang, Q. Xu and K. Li
Consider new economics for purification on a small scale For smaller methanol units, new designs balance energy cost against capital cost for long-term profitability K. Patwardhan, G. Satishbabu, S. Rajyalakshmi and P. Balaramkrishna
BONUS REPORT: ROTATING EQUIPMENT
73
Cover Night view of 25,000-metrictpy ethylene plant built in Texas circa 1948. Project awarded to The Lummus Co. (now CB&I) in 1945. Photo courtesy of CB&I.
HPIMPACT 19
Energy for economic growth
20
Medium-voltage AC drives surge, thanks to energy market
22
Canadian oil sands alliance
23
Polyurethane news from Riyadh
9
HPINSIGHT All hydrocarbons have a place in the global market; timing depends on economics
13
HPIN RELIABILITY Pump alignment saves power
17
HPINTEGRATION STRATEGIES The journey to supplychain excellence in the refining and petrochemical industries
Use better designed turboexpanders to handle flashing fluids New models eliminate vibration problems and improve reliability K. Kaupert
79
Understand multi-stage pumps and sealing options: Part 2 Designing for dirty service involves many factors L. Gooch
CATALYST 2012—SUPPLEMENT
C-84 Perspectives on the 2012 energy industry Here are several thoughts on how companies can adapt to— and profit from—the uncertain environment V. Doshi, A. Clyde and C. Click
COLUMNS
ENVIRONMENT AND SAFETY
103
Venting vapor streams: Predicting the outcome Laminar and turbulent jet theories provide strong support when addressing cold venting situations R. Benintendi
109
Apply audits to reexamine safety procedures Recognizing distinctive vulnerabilities in various refinery units S. L. Chakravorty
CLEAN FUELS
117
Methanol contamination of naphtha: A case study Creative problem solving was used to upgrade off-spec export products while minimizing tank storage F. Ovaici
DEPARTMENTS 7 29 38 122
HPIN BRIEF • 25 HPINNOVATIONS HPIN CONTRUCTION • 37 HPIN CONSTRUCTION PROFILE HPINCONSTRUCTION BOXSCORE UPDATE HPI MARKETPLACE • 125 ADVERTISER INDEX
126 HPIN AUTOMATION SAFETY The imaginary hacker
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Designed specifically to meet the requirement of API 610, the API Maxum Series is available in 35 sizes to handle flows up to 9,900 GPM and 720 feet of head. Standard materials include S-4, S-6, C-6 and D-1. A wide range of options makes this the API 610 pump for you!
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[email protected]. HYDROCARBON PROCESSING (ISSN 0018-8190) is published monthly by Gulf Publishing Co., 2 Greenway Plaza, Suite 1020, Houston, Texas 77046. Periodicals postage paid at Houston, Texas, and at additional mailing office. POSTMASTER: Send address changes to Hydrocarbon Processing, P.O. Box 2608, Houston, Texas 77252. Copyright © 2012 by Gulf Publishing Co. All rights reserved. Permission is granted by the copyright owner to libraries and others registered with the Copyright Clearance Center (CCC) to photocopy any articles herein for the base fee of $3 per copy per page. Payment should be sent directly to the CCC, 21 Congress St., Salem, Mass. 01970. Copying for other than personal or internal reference use without express permission is prohibited. Requests for special permission or bulk orders should be addressed to the Editor. ISSN 0018-8190/01. www.HydrocarbonProcessing.com
Creating Value. Carver Pump Company 2415 Park Avenue Muscatine, IA 52761 563.263.3410 Fax: 563.262.0510 www.carverpump.com
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I APRIL 2012 HydrocarbonProcessing.com
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Get more out of your coal. Only too often do we fail to see the treasures that are right in front of us. With our solids gasification technology you can make more out of any feedstock. Why not contact us: you might just be surprised! As a leading EPC contractor, we also have a proprietary portfolio of technologies. And we network intelligently within the ThyssenKrupp Uhde group based on our business philosophy Engineering with ideas. Visit us at Frankfurt a.M., June 18 - 22, 2012 Hall 9.1, Stand B4
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HPIN BRIEF BILLY THINNES, TECHNICAL EDITOR
[email protected]
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 terminal 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 multiple 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 company. 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 within 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 The international availability of massive US shale gas resources could determine the fate of global gas prices 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 oillinked 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 security, 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 marketplace uncertainties. As such, Mr. Scaroni said it can be difficult for companies to gauge the viability of largescale 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 transportation 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 HYDROCARBON PROCESSING APRIL 2012
I7
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The Emerson logo is a trademark and a service mark of Emerson Electric Co. © 2012 Emerson Electric Co.
HPINSIGHT All hydrocarbons have a place in the global market; timing depends on economics Remaining profitable continues to be a critical issue for hydrocarbon processing facilities. Balancing new technology with government 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 diesel 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 legislation 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.
Synthetic rubber demand on the rise. Recovery in the global synthetic rubber (SR) market is anticipated. Worldwide consumption of SR and natural rubber will increase over the next five years (1991–1996) to 15.8 million tons, thus having an average 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 Occupational 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.
Headlines from Hydrocarbon Processing, April 1982: 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.
Headlines from Hydrocarbon Processing, April 1992: 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 reference 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.
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. HYDROCARBON PROCESSING APRIL 2012
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HPINSIGHT Synfuels viability boils down to economics. A coal gasification plant’s product would have to net $17/MMBtu in 1988 (as compared 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.
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.
Natural gas price decontrol? Decontrol of the US natural gas (NG) market remains a controversial subject. As a major consumer, 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.
New desulfurization process available. Chisso Engineering of Japan has developed a new desulfurization process that can compete 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.
Headlines from Hydrocarbon Processing, April 1972: 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 KelloggPhillips HOC Process disposes of high-sulfur residuals by extending 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 pollutioncontrol projects will bump $12.7 billion by 1976.
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. 10
I APRIL 2012 HydrocarbonProcessing.com
Takahax process recovers sulfur dioxide directly from gases with very low hydrogen sulfide (H 2S) 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.
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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HPIN RELIABILITY HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR
[email protected]
Pump alignment saves power Power consumption, %
Power consumption, %
8 6 4 2 0 0
50 20 30 40 Horizontal offset, thousandth
10
60
9 8 7 6 5 4 3 2 1 0 0
70
Effect of parallel offset on power consumption of a pin coupling at 3,000 rpm.
FIG. 3
50
60
Effect of parallel offset on power consumption of a toroidal (tire-type) coupling at 3,000 rpm.
6 Power consumption, %
10 Power consumption, %
20 30 40 Horizontal offset, thousandth
Accuracy +/– 3% of value Source: ICI
Accuracy +/– 3% of value Source: ICI
FIG. 1
10
8 6 4 2
5 4 3 2 1 0
0 0
5
10 Gap, thou./in.
15
20
Effect of angular misalignment on power consumption of a pin coupling at 3,000 rpm.
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) Rocksavage 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 recirculated in a suitably instrumented closedloop arrangement. Prueftechnik GmbH loaned Lambley a modern laser-optic alignment instrument.
5
10
15 20 Gap, thou./in.
25
30
35
Accuracy +/– 3% of value Source: ICI
Accuracy +/– 3% of value Source: ICI
FIG. 2
0
FIG. 4
Effect of angular misalignment on power consumption of a toroidal (tire-type) coupling at 3,000 rpm.
Background. As an undergraduate student, Lambley had learned how misalignment 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. Properly executed, reverse-dial-indicator methods 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 misalignment consisted of 0.02 in./0.5 mm vertical and horizontal offset and 0.002 in./in. vertical 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 HYDROCARBON PROCESSING APRIL 2012
I 13
HPIN RELIABILITY 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 documented that adhering to these recommendations would reduce ICI’s power consumption by about 1%. He confirmed that laser alignment was faster and superbly more accurate. Lambley determined that laser alignment technology was bottomline 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 benefit is 8 man-hours of time-saving credit per alignment job. For gathering more data, thermography and infrared monitoring techniques are possible options. These methods have been used to quantify significant temperature increases in a coupling located between misaligned pump and driver shafts. You could compare 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 improvement 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 processing industry facilities in the industrialized world, your worker and technician resources are probably stretched to the limit. Understandably, you may be looking for ways to simplify some of your traditional work processes and procedures. You may have had an experience that reinforces 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, misaligned machines absorb more energy than they consume more power. So, it’s always advantageous to update one’s knowledge of shaft alignment and alignment tolerances. 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 topics. 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. Select 152 at www.HydrocarbonProcessing.com/RS 14
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HPINTEGRATION STRATEGIES PETER REYNOLDS, CONTRIBUTING EDITOR
[email protected]
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 marketing is often performed in a sub-optimal manner. Most process manufacturing companies claim supply chain as a core competency, 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 distribution 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 manufacturing 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 technology. All often offer opportunities to streamline business operations. 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. Terminal 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 projects 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 projects. Many business end users use a host of manual business processes 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 industry-standard process reference model to help companies improve supply-chain operations. The SCC created the Supply Chain Operations Reference (SCOR) model; now companies can evaluate 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 membership. 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-standard 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 management. 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 developed, 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 companies 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 technology 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. HYDROCARBON PROCESSING APRIL 2012
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The life cycles of my critical service valves are already pushed to the max. And now they want to extend the time between turnarounds?
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The Emerson logo is a trademark and a service mark of Emerson Electric Co. © 2011 Emerson Electric Co. D351992X012 MX11 (H:)
HPIMPACT BILLY 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 recovery, 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 economy. Fig. 1 shows the energy sector’s share of business-sector gross domestic product (GDP) along with other industries in several Organization for Economic Cooperation 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 economic 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, capital 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 compensation 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 industries, 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
2.5
Germany
6.5 8.8
Mexico
Norway
11.8
8.5
28
4.5
5.9
United States 0
5
10
Energy-related industries
15 Percent
20
Manufacturing
25
South Korea
30
FIG. 1
Share of business-sector GDP and energy compared to other industries.
27.8
0.9 11.1 1.2
15.7
18 16.9 5
10
Energy-related industries
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.
18.6
2.6
0
Health and social work
14.3
0.6
United States
21.2
10.4
2.3
United Kingdom
18.2
6.3
11.9
2.7 Norway
2.8
United Kingdom
0.8
Mexico
19.1
3.5
South Korea
22.1
9.5
24.4
3.2
Energy prices. As the key input for most goods and services in the economy, lower energy prices reduce expenses for consumers and businesses and increase the disposable 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
1.4
Germany
22.3
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, software and non-residential construction sectors 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 Economic Forum. “But we were still surprised when the data uncovered the magnitude of the sector’s multiplier effects.”
15 Percent
20
Manufacturing
25
30
Health and social 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.
FIG. 2
Share of business-sector employment and energy compared to other industries. HYDROCARBON PROCESSING APRIL 2012
I 19
HPIMPACT 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. “Maximizing 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, promoting steady and reasonable energy prices through stable tax and fiscal schemes, and encouraging of industrial diversification 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.
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Select 153 at www.HydrocarbonProcessing.com/RS 20
Medium-voltage AC drives surge, thanks to energy market While large project orders helped maintain the market size of medium-voltage AC drives in 2009, it also resulted in low growth in 2010 compared to other automation 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 infrastructure 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 automation solutions and AC drives is expected to improve, emerging markets will remain significant drivers of growth as they build up their electrical power-generation capacity and expand industrial production with a major focus on improving energy efficiency 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 solutions 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
remoteness loves proximity Gas treatment plants are often located in the loneliest corners of the planet. We at BASF ensure that all plants working with our gas treatment technology run smoothly, regardless of where they are. Under its new OASE® brand, BASF provides gas treatment solutions consisting of technology, services and products. We at BASF combine the experience of more than 40 years and about 300 distinct references with the latest innovations to provide you with your unique solution. So if going to the ends of the earth results in us being your best neighbor, it’s because at BASF we create chemistry. www.oase.basf.com
GAS TREATING EXCELLENCE
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HPIMPACT 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 infrastructure 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 covered in the report.
Select 154 at www.HydrocarbonProcessing.com/RS 22
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 collaborative action and innovation.” The creation of COSIA as an independent 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 environmental 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 environmental performance in the oil sands continues to evolve; we want to meet those expectations, 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 important 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 environmental science and was selected following a national search. The organization said that his scientific qualifications and leadership 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 Canadians 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 producers and other stakeholders can work together for the benefit of the environment. The alliance will identify, develop and apply solutions-oriented innovations around the most pressing oil sands environmental challenges (specifically water, land, greenhouse gases and tailings), and will communicate COSIA’s efforts and successes 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, promoting new approaches for intellectual property management of environmental technology and better working relationships with universities, research agencies, technology providers, 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 development of new environmental solutions,” Mr. Gires said. “We have seen what can be achieved when we work together and multiply 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, officials 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, academia 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 AlMady, SABIC vice chairman and chief executive 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 competitive advantage of our customers for the long term,” he said. “It will also enable a fast development of polyurethane application 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 Mitsui Chemicals has lengthy experience as a manufacturer of TDI and MDI and has developed pioneering manufacturing processes. “Through this technology license agreement, we will strengthen our product 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 committed to its success. I hope that it will be just the first step in a future business partnership with SABIC, which may include the establishment of a strategic supply base for competitive TDI/MDI.” HP
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[email protected] FIG. 3
Executives from SABIC and Mitsui Chemicals ink a deal in Riyadh, Saudi Arabia.
Egellsstrasse 21, D-13507 Berlin/Germany Select 155 at www.HydrocarbonProcessing.com/RS
Flexible H2S Removal
Sweet Solutions.®
LO CAT
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HPINNOVATIONS SELECTED BY HYDROCARBON PROCESSING EDITORS
[email protected]
Vessel monitoring system uses thermal cameras The Critical Vessel Monitoring System from Land Instruments International Ltd., a unit of AMETEK Inc., uses industrial-strength thermal-imaging cameras to provide higher measurement density than traditional systems based on thermocouples. The system measures surface temperature once every 16 cm2, as compared with one measurement every 250 cm2 in thermocouple systems. Each camera records over 110,000 individual measurements, ensuring that even the smallest degradation can be detected. By measuring temperatures in more locations, the system allows for earlier detection of refractory wear or breakdown. Measurements 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 support 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 petrochemical production, power generation, chemical and coal processing, waste management, and fertilizer and plastics production. Benefits include greater protection 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 implemented 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
FIG. 1
This vessel monitoring software shows the exact locations of imaging cameras.
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 catalyst 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 CONSISTA C601, the catalyst demonstrated excellent operability and process performance 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 reinforced seal can be determined at any time, it offers significant reliability and aboveaverage mean time between maintenance (MTBM) for cooling water pumps. The high MTBM improves grip on the pumping 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 communications 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 Frequency Hopping technology to avoid interAs 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.
HYDROCARBON PROCESSING APRIL 2012
I 25
HPINNOVATIONS 13 14
7,600 hr/ year (yr)
8,000 hr/ yr = 100%
Pit region
CCS region
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.
17 18
15 19
Select 5 at www.HydrocarbonProcessing.com/RS
Cycle time, hours (hr)
16 20
17
21
18 19
23
20 21
Example: Cycle time (actual) = 19 hr Cycle time (target) = 17 hr Expected profit up to €32 MM/y when changing from pit to CCS system
22
24
Two-drum coker, 250 ton/hr of fresh feed Uplift = €100/ton of fresh feed €25,000/y One turnaround/y = 800 hr Run length of CCS = 8,000 hr = 100% pit = 7,600 hr = 95%
22 23 24 0 5 10 15 20 25 30 35 40 45 50 55 60 Earnings, €MM/y
FIG. 2
Attractive economics are achievable with the CCS system.
Clean CCS process replaces ‘coal-mining’ steps
FIG. 3
The water-lubricated pump seal extends mean time between maintenance.
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 System, as well as with other supervisory control and data acquisition (SCADA) and distributed input/output systems. WNM models are available for data communications networks that use Ethernet and serial (RS-485) communications. Select 4 at www.HydrocarbonProcessing.com/RS 26
I APRIL 2012 HydrocarbonProcessing.com
Refineries with delayed coker technology and open-pit or pad solids handling resemble a coal-mining operation. However, 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 reliability and reduces costs. The CCS system is technically a closed system, improving mechanical, environmental 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 separation 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, allowing 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 controlled operation, and it enables the console operator to view a complete status of the process at any time. The typical payout time for a CCS system 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-
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 converted to biocoke and carbonization gas. The second process stage comprises the partial oxidation of the carbonization gas that takes place in a high-temperature gasifier (HTG), and, during the third process stage, the biocoke is blown into the hot gas stream of the HTG. After adequate preconditioning, 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 directread 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 concentrations 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 measurements and require extra analysis and calculations to determine the correct water vapor level. For a precise methanol measurement, 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
HPINNOVATIONS 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 coating, Macropoxy 80, combats steel corrosion caused by immersion in saltwater and freshwater, as well as by atmospheric exposures. A modified phenalkamine epoxy with high surface tolerance, Macropoxy 80 is recommended for use in coastal areas, saltwater and freshwater immersion, bilges and wet void areas, water and wastewater tanks, underwater hulls, and decks and superstructures. It can also be used as an anti-corrosive 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, Macropoxy 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).
Dräger Safety AG & Co.’s PSS 3000 self-contained breathing apparatus (SCBA) is designed for use in plant maintenance, plant and operational safety, and emergency 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 styrenebutadiene 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
Select 8 at www.HydrocarbonProcessing.com/RS
Dräger unveils new industrial breathing apparatus line Two new National Institute for Occupational 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.
This bench top analyzer tops all others in its price range for features and performance. It’s equipped with an intuitive user interface, full-color touch screen and on-board Windows XP computer. Ethernet electronics that permit remote access for calibration, diagnostics or service support. Plus, the Phoenix II has a large sample compartment that accommodates spinners and special holders yet requires little or no sample preparation. It all adds up to the lowest cost of ownership, backed by AMETEK’s reputation for reliability and world class customer support. Visit: ametekpi.com
FIG. 4
The Dräger PSS 3000 breathing apparatus is more durable than traditional equipment. Select 156 at www.HydrocarbonProcessing.com/RS
27
Reliability has no quitting time. Think about ITT.
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HPIN CONSTRUCTION HELEN MECHE, ASSOCIATE EDITOR
[email protected]
North America Boardwalk Pipeline Partners, L.P. has selected Exterran to design, manufacture and construct a natural gas-processing plant in South Texas. The project includes engineering, procurement and construction (EPC) of a cryogenic gasprocessing 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 Exterran 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 support Green Energy’s oil production customers within a 100-mile radius of Fairfield, in the Freestone oil region of Central Texas. The trucks are anticipated to use approximately 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-producing areas of Texas. Fluor Corp. has an engineering, procurement and construction management (EPCM) contract from Joule Unlimited, Inc., to design and build a biofuels demonstration 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 sunlight to convert proprietary organisms and carbon dioxide into liquid hydrocarbons and ethanol. Fluor’s Greenville, South Carolina office is leading the EPCM services project. Engineering, procurement and site mobilization is underway.
Freeport LNG Expansion, L.P. and a joint venture comprising Zachry Industrial, 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 development and a two-train initial development. This optionally enables Freeport LNG to choose the optimum size of the initial phase of the project based upon customer demand and financing considerations. In addition, the three-train project’s design will allow for expansion of additional liquefaction trains and pretreatment facilities after the initial development has commenced. M D U Re s o u rc e s Gro u p , In c . , 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 facility would process Bakken crude and market 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 Refining, 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 operational in October of 1999, and the second in February of 2000. Formosa Plastics Corp. will be investing 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 material 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-density 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 operational flexibility. The addition of the coun-
Trend analysis forecasting Hydrocarbon Processing maintains an extensive database of historical HPI project information. The Boxscore Database is a 35-year compilation of projects by type, operating company, licensor, engineering/constructor, location, etc. Many companies use the historical data for trending or sales forecasting. The historical information is available in comma-delimited or Excel® and can be custom sorted to suit your needs. The cost depends on the size and complexity of the sort requested. You can focus on a narrow request, such as the history of a particular type of project, or you can obtain the entire 35-year Boxscore database or portions thereof. Simply send a clear description of the data needed and receive a prompt cost quotation. Contact: Lee Nichols P.O. Box 2608, Houston, Texas 77252-2608 713-525-4626 •
[email protected] HYDROCARBON PROCESSING APRIL 2012
I 29
HPIN CONSTRUCTION try’s newest LDPE resin plant will complement the company’s existing product line of Formolene polyethylene (PE) and polypropylene (PP), and Formolon polyvinyl chloride (PVC) and specialty PVC.
Europe
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-modernization project.
CB&I’s Lummus Technology business sector has been awarded two separate contracts by a client in Russia. The combined value of the contracts is approxi-
Sibur and Reliance Industries Ltd. (RIL) have formed a joint venture (JV) named Reliance Sibur Elastomers Pri-
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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 technology 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 engineering design and also train the JV’s personnel 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 provide the license, basic-engineering package and other services for TAIF’s VCCbased 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 petrochemical 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 provide American Petroleum Institute (API) centrifugal pumps to support Shell operations worldwide. Under the agreement, Goulds Pumps will supply these pumps in several configurations 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 conditions, 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-
Select 157 at www.HydrocarbonProcessing.com/RS 30
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Decades of experience in the oil and gas industry, leading technical expertise, and our own product development and production facilities are the solid foundation for a wide range of high-performance products and services. We offer comprehensive solutions for the entire life cycle of a plant and along the entire oil and gas value chain. The basis is our global engineering and project manage-
ment expertise as well as extensive experience in turnkey projects. Siemens’ early involvement in the concept phase results in the best possible technical solutions and limits project risks. And packages for entire functionalities reduce interface conflicts to help optimize a plant’s CAPEX and OPEX.
www.siemens.com/oilandgas Select 101 at www.HydrocarbonProcessing.com/RS
HPIN CONSTRUCTION morsk region of Russia, has selected Axens’ AlphaButol and AlphaHexol technologies for producing high-purity linear alphaolefins. 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 highpurity 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 downstream polyolefin applications. A subsidiary of Foster Wheeler AG’s Global Engineering and Construction Group has a contract from a subsidiary of JSC LUKOIL for the supply
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of a waste-heat boiler for the LUKOIL Nizhegorodnefteorgsintez refiner y, 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 scheduled to be completed by March 2013.
Middle East Siemens Industr y Automation Division is providing Abu Dhabi Oil Refining Co. (TAKREER) with a Zimpro 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 produce 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 international environmental standards. The Zimpro 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 engineering, procurement and construction management (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, Kingdom 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 Chemicals, Inc., in keeping with the company’s
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HPIN CONSTRUCTION strategic plan to be a global leader in polyurethane (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 technology development in TDI/MDI. Mohamed Al-Mady, SABIC vice chairman and CEO, pointed out that Mitsui
Chemicals has a long experience as a manufacturer of TDI and MDI, and has, over the years, developed pioneering manufacturing processes. “Through this technology license agreement, we will strengthen our product capabilities with high-quality TDI and MDI and expand into the polyurethane business,” he said. Toshikazu Tanaka, Mitsui Chemicals president and CEO, commented, “For Mitsui Chemicals, this license agreement
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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 business partnership with SABIC, which may include the establishment of a strategic supply base for competitive TDI/MDI.”
Asia Pacific The 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 reactor-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 groundbreaking ceremony for its new solutionstyrene-butadiene rubber (S-SBR) manufacturing plant to be constructed in Merbau area, Jurong Island, Singapore, by its group company Sumitomo Chemical Asia PTE LTD. In November 2010, the company decided to construct the new 40,000-tpy S-SBR plant in Singapore because of its geographical advantage 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. Commercial operations are planned to begin during the fourth quarter of 2013. The company, expecting further demand growth, is working on a plan to build an additional plant to increase production. Sumitomo Chemical’s S-SBR is manufactured by its proprietary production process technology. With its advanced polymer-modification technology, it is a key to achieving higher product performance. The company continues to enhance its S-SBR business globally through increased production with the new plant in Singapore and future expansions, along with its existing 10,000-tpy plant in Japan.
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SINCE 1921... AND WE STILL LOVE IT For more than eighty years, we at Costacurta have been constantly and resolutely committed to the development and manufacture of special steel wire and plate components used in many different industrial processes. Every day at Costacurta, we work to improve the quality of our products and services and the safety of all our collaborators, paying ever-greater attention to the protection of the environment. Within the wide range of Costacurta products you will also find some, described below, that are used specifically in the oil, petrochemical and chemical industries: - RADIAL FLOW AND DOWN FLOW REACTOR INTERNALS; - GAS-LIQUID AND LIQUID-LIQUID SEPARATORS; - ARMOURING OF REFRACTORY, ANTI-ABRASIVE AND ANTI-CORROSIVE LININGS. For more information visit our website or contact the division 'C' components for the oil, petrochemical and chemical industries at
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Radial Flow and Down Flow reactor internals
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HPIN CONSTRUCTION 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-reforming process will be initially started with natural gas as feedstock, but it is also prepared to run with liquefied petroleum 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 supervise on the plant’s erection site, commissioning and startup. INEOS Technologies has licensed its Innovene PP process to Zhong Tian He Chuang Energy Co., Ltd. Located in Ordos City, Inner Mongolia Autonomous Region, the 350-kiloton/yr plant will manufacture a full line of polypropylene resins, including homopolymers, random copolymers and impact copolymers. It will serve the rapidly growing Chinese PP markets. Zhong Tian He Chuang is a joint venture between Sinopec and China Coal Energy Group Co., Ltd. The final selection of Innovene PP in their MethanolTo-Olefin Complex demonstrates a growing appreciation for Innovene PP in the Chinese coal industry.
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 feasibility of building an integrated refining and petrochemical project in Tuban, East Java, Republic of Indonesia. The project represents an opportunity for Saudi Aramco to partner with Pertamina, and to capitalize on investment opportunities in Indonesia’s growing 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 project’s next phase, which will include a joint scoping study comprising market research, configuration studies and economic 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 target, PETRONAS adopted a dual-FEED scheme, wherein two contractors are contracted 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
Jacobs Engineering Group Inc. is executing four contracts from Arkema France for basic-engineering services to support the provision of Arkema’s proprietary suspension and emulsion technology to four of its clients in China. Arkema’s technology is being used in four new polyvinyl 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. Select 160 at www.HydrocarbonProcessing.com/RS 35
Select 81 at www.HydrocarbonProcessing.com/RS
HPIN CONSTRUCTION PROFILE BEN DUBOSE, ONLINE EDITOR
[email protected]
Methanex targets US for relocation of capacity Methanex 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 capacities 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 completed 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 attractive 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 environment in which to do business. “We have a number of parallel work paths ongoing and expect to make a final
FIG. 2
investment decision on this project in the third quarter of [2012].”
It plans to restart production in the first half 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 Geismar 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.
Methanol in transportation fuels mix. Rising US prices for crude-based
US shale boom sparks interest.
Recent shale gas discoveries, however, have made natural gas feedstocks available and affordable. Last year, Egypt-based Orascom Construction Industries acquired an idled 750,000 tpy methanol plant in Beaumont, Texas, formerly run by Eastman Chemical.
Methanol can be produced from four plants at the Punta Arenas, Chile, site. Photo courtesy of Google Earth.
gasoline could also play a role. Tom Ridge, former Secretary of Homeland Security, argued in a February editorial 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 gasoline, 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 methanol globally and there is little new production capacity being added to the industry over the next several years.” HP
FIG. 1
The Methanex methanol complex in Punta Arenas, Chile.
FIG. 3
Bruce Aitken, Methanex president and CEO.
HYDROCARBON PROCESSING APRIL 2012
I 37
HPI CONSTRUCTION BOXSCORE UPDATE Company
City
Project
Ex Capacity Unit
Cost Status Yr Cmpl Licensor
Engineering
Constructor
AFRICA Algeria
Sonatrach
Arzew
LNG Liquefaction Plant
4.7 m-tpy
2400
U
2012
Angola Nigeria
Angola LNG Ltd Nigeria LNG Ltd
Soyo Bonny Island
LNG Storage LNG (7)
5.2 MMtpy 8.5 MMtpy
4000
U U
2012 2012
Nigeria Nigeria
Nigeria LNG Ltd Chevron Nigeria\ Nigerian Natl Pet Corp Chevron Nigeria\ Nigerian Natl Pet Corp PetroSA Undefined
Bonny Island Escravos
LNG (8) GTL (2)
U U
2012 2012
Escravos
GTL (3)
P
2012
Coega Hoima
Refinery Refinery
F P
2016 2015
Dalian West Pacific Petrochem Henan Jinkai Chemical Group Zhong Tian He Chuang Energy Co. Ltd. Sinopec Mangalore Rfg & Petrochemicals SAAC/Persero Caloric
Dalian Henan Ordos Xinjiang Mangalore Tuban Undisclosed
Wet Sulfuric Acid (WSA) Wet Sulfuric Acid (WSA) Methanol-to-Olefins (MTO) Refinery EX Refinery EX Refinery Hydrogen Generation
U U U P U S U
2012 2012
Conoco Phillips Co TAIF NK Shell UK Ltd\Esso E & P Shell UK Ltd\Esso E & P
Cork Tatarstan Mossmorran St Fergus
Wet Sulfuric Acid (WSA) Cracker Natural Gas Plant Gas Plant
Pernambuco Rio de Janeiro Tula, Miguel Hidalgo Refinery San Juan de Marcona Talara
Refinery Petrochemical Complex Amine Regeneration Unit Ammonia Wet Sulfuric Acid (WSA)
Ras Laffan Al Jubail Jubail Ind City
Ethylene Petrochemical Complex Propylene Oxide
Undisclosed Eagle Ford Shale Freeport Glasscock Co Port Arthur
Diesel Natural Gas Plant LNG Natural Gas Plant Desalter (2)
Nigeria Repub S Africa Uganda
EX
8 MMtpy 17 Mbpd Mbpd 400 Mbpd 200 bpd
10500 2000
ConocoPhillips
Haldor Topsøe Chevron|Saso Haldor Topsøe Chevron |Sasol
Saipem|Chiyoda Snamprogetti Bechtel|Saipem|KJT Technip|FW|JGC|KBR Chiyoda|Snamprogetti Chiyoda|TSKJ JGC|KBR Snamprogetti JGC|KBR Snamprogetti KBR
Bechtel
KBR|JGC Snamprogetti JGC|KBR Snamprogetti
FW
ASIA/PACIFIC China China China China India Indonesia Indonesia
30 122 350 200 9.69 300 1000
Mtpd m-tpd kty bpd MMtpy bpd Nm3/h
8.41 2400
2015 2012
Haldor Topsøe Haldor Topsøe INEOS EIL|Toyo Japan
EIL
EIL
EUROPE Ireland Russian Federation Scotland Scotland
RE RE
30 m-tpd 2.7 m-tpy None None
U U E E
2012 2014 2014
U U E U E
2014 2013 2013 2013 2015
P F F
2018 2015 2015
S U F P U
2013 2013 2013 2013
Haldor Topsøe KBR
KBR Wood Group Wood Group
LATIN AMERICA Brazil Brazil Mexico Peru Peru
Petr Brasileiro SA Petrobras Pemex CF Industries Inc Petroperu
TO
230 bpd 165 bpd None 2.6 Mtpy 460 t/a
12000
1.4 m-tpy t/a None
5000 15000
800 2000
Haldor Topsøe Haldor Topsøe
Saipem Technip
MIDDLE EAST Qatar Saudi Arabia Saudi Arabia
QP/QAPCO Sadara Chemical Co. Sadara Chemical Co.
TO
FW FW
UNITED STATES North Dakota Texas Texas Texas Texas
WBI Holdings/Calumet Refining Boardwalk Pipeline Partners, LP Zachry DCP Midstream Valero Refining Co
EX RE
20 150 4.4 75 260
bpd MMcfd Mtpy MMcfd Mbpd
180
Exterran CB&I Cameron
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I APRIL 2012 HydrocarbonProcessing.com
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PETROCHEMICAL DEVELOPMENTS
SPECIALREPORT
Optimize olefin operations This 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.
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 process 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 section consists of a demethanizer, ethane/ethylene and propane/ propylene splitters, and a debutanizer, as shown in Fig. 3.
Propane/propylene splitter study. The olefin plant’s
performance had deteriorated. The conditions resulted in significant 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 operating 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 Feedstocks distillation columns. Ethane
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 ranging 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
Propane
Pyrolysis
FIG. 1
Effluent water scrubbing
Pequiven’s Ana Maria Campos petrochemical complex.
Process gas compression stages
Chilling section
Splitting section
Ethylene Propylene
I II III IV V
Acetylene conversion
Caustic and water wash
Process gas drying
Ethane/propane recycle FIG. 2
Process flow diagram of Olefins I plant.
HYDROCARBON PROCESSING APRIL 2012
I 41
SPECIALREPORT
PETROCHEMICAL DEVELOPMENTS
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 C 3 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
Chilling section
Deethanizer C2 splitter Demethanizer Methane Ethane and ethylene Ethylene
Compressed gas Separators Propane,Ethane propylene and heavier components
Propylene Propane and butane
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 operated 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 product, 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 system) depropanizer Feed flowrate, metric tph
C3 splitter section (2 trains each with 2 columns) C5+/pygas Propane and heavier components FIG. 3
Debutanizer
Separation section of the Olefins I plant.
Secondary splitter system C3/C3=/C4+ deethanizer bottoms
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
0.0007
0.992
Top pressure, bar
18.9
18.9
Reflux rate, metric tph
22.7
146
2.9
12.3
Mol purity propane, bottom
Primary splitter system
Reboiler duty, MW Propylene
Propylene
TABLE 2. Results from the Revamp Proposal B simulation modeling study Column D (from secondary system) depropanizer
Primary propane/ propylene splitter1
16.9
14.2
Stages
88
277
Feed stream stage
36
171
Feed flowrate, metric tph Propane and butane to pyrolysis furnaces Propane and C4+
Debutanizer
C5+ FIG. 4
Propane/propylene splitter section of the existing unit.
Distillate rate, metric tph
14.2
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
0.0007
0.992
18.9
18.9
Mol purity propane, bottom Top pressure, bar Reflux rate, metric tph Reboiler duty, MW
42
I APRIL 2012 HydrocarbonProcessing.com
Primary propane/ propylene splitter1
22
146
2.85
12.3
PETROCHEMICAL DEVELOPMENTS • 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 column geometries and tray efficiencies. This distillation model is a core element. It helped predict column performance and ensured
SPECIALREPORT
robust initialization and convergence. The rate-based algorithm also significantly improved the model’s accuracy compared to the equilibrium-based and first-generation rate-based distillation models. Simulation results—such as column pressure, operating temperature, 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 column for this purpose. Tables 1 and 2 summarize the study results. Findings for Proposals A and B. The operating conditions 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 propanesplitter (depropanizer) propylene splitter1 Feed flowrate, metric tph Stages Feed stream stage
17
14.4
198
277
37
172
Distillate rate, metric tph
14.4
6.8
Mol purity propylene, top
0.489
0.999
Mol purity propane, top
0.494
0.0002
Bottom rate, metric tph Mol purity propane, bottom Top pressure, bar
2.6
7.6
0
0.996
18.9
18.9
Reflux rate, metric tph
23
182
Reboiler duty, MW
2.9
60.9
TABLE 4. Results from the revamp proposal D simulation modeling study* Primary propane/propylene system LP steam Required temperature, °C Required pressure, bar
128.7
Secondary propane/ propylene system LP steam1
2.75
2.75
0.9985
0.9985
Required flowrate, metric tph
24,366
19,035
1.41
1.102
*Based on the original design with propylene losses of less than 1%
Simulation model of the propane/propylene splitter system.
Secondary splitter system
=
Primary splitter system
C3/C3
C3/C3=/C4+ deethanizer bottoms
Propylene
Depropanizer Propane to pyrolysis furnaces
Revamp Proposals A and B C4+
128.7
Propylene recovery composition Total cost, $ million/yr
FIG. 5
Butane to pyrolysis furnaces Debutanizer
C5+ FIG. 6
Proposals A and B: Use one column in the secondary C3 splitter as a depropanizer. HYDROCARBON PROCESSING APRIL 2012
I 43
SPECIALREPORT
PETROCHEMICAL DEVELOPMENTS
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 multidowncomer 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-downcomer 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 Secondary splitter system Depropanizer
C3/C3=/C4+ deethanizer bottoms
Primary splitter system Propylene
C3/C3=
Revamp Proposal C
Propane to pyrolysis furnaces Butane to pyrolysis furnaces
C4+ Debutanizer
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 original 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
TABLE 5. Pequiven C3 splitter revamp proposal D economic analysis1
C5+ FIG. 7
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 approximately $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 earlier. These process improvements are expected to result in 8,915 metric tpy of incremental propylene production. At $1,080/metric ton, the increased production represents $9.62 million of additional 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.
Proposal C: Use the secondary splitter system as a depropanizer.
Cost estimates Basic and detailed engineering Reboiler modification, process oily water to LP steam
Propylene
Condensate removal system TG
LP steam Propane/ propylene splitters
TC
Process water return Propane and C4+ Revamp Proposal D FIG. 8
44
Condensate return
Proposal D: Using LP steam as the heating medium in reboilers.
I APRIL 2012 HydrocarbonProcessing.com
500 250 1,200
Stainless steel pipe, 16 in.
18.5
Stainless steel pipe, 14 in.
13.7
Stainless steel pipe, 12 in.
10.8
Stainless steel pipe, 2 in.
5.3
Isolation Process water
USD, thousand
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%
PETROCHEMICAL DEVELOPMENTS 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 system 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 possible 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 optimal 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
SPECIALREPORT
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 ACKNOWLEDGMENT The author thanks Sanjeev Mullick of AspenTech for his help in preparing this article for publication. LITERATURE CITED 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. 1
Karen Romero is a process engineer at Pequiven. She has over 10 years of experience in oil and gas and petrochemicals, with a focus on design, development, management 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.
Select 162 at www.HydrocarbonProcessing.com/RS
HYDROCARBON PROCESSING APRIL 2012
I 45
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PETROCHEMICAL DEVELOPMENTS
SPECIALREPORT
Alternate feedstock options for petrochemicals: A roadmap New 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 significant driver in India’s economy and supports new petrochemical/chemical consumption. This young population with rising incomes is responsible for growing demand for consumer durable goods, such as automobiles and packaging. Petrochemicals constitute 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. Construction costs for Indian manufacturing facilities are 30%–40% cheaper.1–3 The present growth rate of the Indian chemical, industry 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 packaging industry.3 Table 1 lists growth rates of several polymeric materials. 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 petrochemical 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 dynamics. 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 bioethanol 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 investing 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, sugarcanederived 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 atmosphere. The green plastics have identical properties and application characteristics to a hydrocarbon-derived plastic. The green TABLE 1. End-user sector demand in India, thousand tpy Sector Fiber and filament Film and sheet
Market size, 2006
Demand, 2011
Increase, %
59
117
98.3
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
HYDROCARBON PROCESSING APRIL 2012
I 47
SPECIALREPORT
PETROCHEMICAL DEVELOPMENTS
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 Russia’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 business 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. Strategic ports must be built so that the HPI products can be distributed and exported. Pipelines to supply feedstock and products are urgently needed. The Ministry of Energy is formulating comprehensive 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 construction 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 consumer-goods industries. Petrochemical production growth will be led by Sibur. The company’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 dehydrogenation (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 ethylene 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 deliberating 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, respectively. The abundance of Russian reserves, with its close proximity to Asia, is a good reason for synergy and collaboration.6,7,11 48
I APRIL 2012 HydrocarbonProcessing.com
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 petrochemicals, 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 gasification technology to 15 units in China. Due to the volatility associated 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 materials such as methanol, olefins and mono-ethylene glycol (MEG). Responding to this demand growth, the Chinese methanol industry 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 combined capacity of 4 MMtpy. However, China plans to manage its total methanol capacity to be less than 50 MMtpy, with a maximum 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 coalto-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-
PETROCHEMICAL DEVELOPMENTS
SPECIALREPORT
TABLE 2. Recent coal-to-chemicals project in China Company
Location
SNCG and Air Liquide
Ningxia
Ningbo Heyuan Shenhua Baotou
Startup
Technology
Capacity, MMtpy
2012–2013
MTP
0.50
Guangdong
2012
MTO
1.80
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
Sinopec and Syntroleum
Zhejiang
2010
Coal, asphalt, petroleum coke to petrochemicals
0.80 80 bpd
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
–
CNOOC
Hainan
Shaanxi Changqing Energy Chemicals, Xuzhou Mining Group and Shaanxi Coal Field Geological Expl. Dev. Co.
Shaanxi
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 coalchemical industry in China has made it possible to supplement and partially substitute traditional naphtha feedstocks. Developing 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 petrochemical 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 Petrochemical 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 facility; 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 ethylenepropylene market. The anticipated annual growth rate of ethylene over the next decade is 4%. During the same period, the expected
MTA (fluidized bed)
–
2010
Coal-to-methanol
–
2013
Coal-to-methanol
1.50
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 economies 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 markets in the US and Europe. US data showed that the petrochemical 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 consuming 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 reductions 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, ChevHYDROCARBON PROCESSING APRIL 2012
I 49
SPECIALREPORT
PETROCHEMICAL DEVELOPMENTS TABLE 4. Global refinery utilization rates5
Refinery utilization rates, %
95 90 85 80 75 Non-OECD nations OECD nations
70 65 ’01
’02
’03
’04
’05 ’06 Year
’07
’08
’09
’10
FIG. 1
TABLE 3. Recent ME petrochemical projects Country
Project
Startup
Ethylene, Propylene, MMtpy MMtpy
Saudi Arabia PetroRabigh
2009
1.3
0.6
Saudi Arabia Saudi Ethylene and Polyethylene Co.
2009
1.3
–
Saudi Arabia SABIC Eastern Petrochemical Co. (Shark III)
2010
1.3
–
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 (MIC complex)
2011
–
0.18
Qatar
Ras Laffan Olefin Complex, Exxon
2015
1.6
–
Qatar
Ras Laffan Olefin Complex, Shell
2018
1.3–1.6
–
UAE
Borouge 2 Petrochemical Co.
2011
1.4
–
UAE
Borouge 3 Petrochemical Co.
2012
0.6
–
Kuwait
Equate Petrochemical Co.
2010
0.8
–
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 position, 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 50
I APRIL 2012 HydrocarbonProcessing.com
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
80
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 management 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 petrochemical production purposes.6,7,21 Lignocellulosic biomass. India is a favorable place to
develop residual biomass into ethanol, lignin, olefins and phenolics due to the abundance of raw materials from forest and agricultural residues. About 800 MMtpy of forest and agricultural 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 convert 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 petrochemical industries for biopolymer production.6,7,22
You are Invited to Attend
Milan, Italy | 12–14 June | www.HPIRPC.com International Refining & Petrochemical Conference
Register by 30 April and SAVE 15% with our Early Bird Discount Organized by:
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Dear Readers, You are cordially invited to attend the third annual Hydrocarbon Processing International Refining 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 afforded by a gathering like IRPC 2012 provide the personal contact necessary for the free-flowing 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 refining 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:
Giacomo Rispoli Executive Vice President, Research & Development and Projects IRPC Advisory Board Chair eni–Refining & Marketing Division John Baric Licensing Technology Manager Shell Global Solutions International B.V. Eric Benazzi Marketing Director Axens Carlos Cabrera Executive Co-Chairman Ivanhoe Energy Dr. Charles Cameron Head of Research & Technology BP Antonio Di Pasquale Vice President Refining Product Line Technip Giacomo Fossataro General Manager Walter Tosto S.p.A.
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Dr. Madhukar Onkarnath Garg FNAE Director Indian Institute of Petroleum in Dehradun Rajkumar Ghosh Executive Director Indian Oil Andrea Gragnani Refining Product Line Director Technip Dr. Syamal Poddar President Poddar & Associates Andrea Amoroso Vice President Process Technology eni Stephany Romanow Editor Hydrocarbon Processing Michael Stockle Chief Engineer Refining Technology Foster Wheeler
MILAN, ITALY | 12–14 JUNE
About IRPC 2012 Hydrocarbon Processing’s International Refining 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 refining 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 officials 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 efficient and profitable. This is your chance to take part in the discussion. IRPC offers 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 benefit their organization or plant. This year’s conference will feature a dual-track program with topical sessions on heavy oil, hydrogen, environment/safety, energy efficiency, petrochemical/refinery integration and biofuels/clean fuels.
eni Plant Tour By registering to attend IRPC 2012, you will have the chance to reserve your spot on an exclusive tour of eni’s Sannazzaro de’ Burgondi Refinery in Pavia, Italy. A short bus drive from Milan, the refinery is home to the first-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.
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 benefit 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-specific topics
Who will be at IRPC 2012? • HPI professionals looking to discover the field’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
IRPC 2012 Sponsors:
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For sponsorship opportunities, contact Bill Wageneck, Vice President and Publisher, Hydrocarbon Processing at +1 (713) 520-4421 or
[email protected].
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IRPC 2012 Agenda |
Day 1: Tuesday, 12 June
eni PLANT TOUR 2:15 p.m.
Depart from MiCo – Milano Congressi
3:30 pm
Arrival at eni’s Sannazzaro de’ Burgondi Refinery 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 Refinery EST Project
7:00 pm
Arrive Back at MiCo – Milano Congressi
IRPC 2012 Agenda |
Day 2: Wednesday, 13 June
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.
Coffee Break TRACK 1: HEAVY OIL
TRACK 2: HYDROGEN
Session 1 Session Chair: Michael Stockle, Chief Engineer—Refining 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 Refineries—Shri Susobhan Sarkar & Shri Tapan Kumar Basak of Indian Oil Corporation Limited
Balancing Hydrogen Demand and Production: Optimising the Lifeblood of a Refinery—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
Efficient Hydrogen Management in Refinery—Debangsu Ray & Mukesh Mohan of Indian Oil Corporation Limited
12–12:30 p.m.
Latest Improvements in VGO Based Hydrocracking Technologies—Axens
Hydrogen-Creep Resistant 9% Chromium Heavy Plates for Future High Temperature Refining Reactors—Cedric Chauvy (speaker), S. Pillot & L. Coudreuse of Industeel, ArcelorMittal Group
12:30– 1 p.m.
Commercial Experience in Difficult Feedstock Upgrading with Criterion/Zeolyst’s Catalysts—Gert Meijburg of CRI/Criterion Catalyst Company Ltd.
Simulate Your Refinery 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 Coffee & Desserts in Exhibit Hall TRACK 1: HEAVY OIL
TRACK 2: ENVIRONMENT & SAFETY
Session 3 Session Chair: Eric Benazzi, Marketing Director, Axens
Session 4 Session Chair: Madhukar Onkarnath Garg, FNAE, Director, Indian Institute of Petroleum
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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 Refineries 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
Effluence & 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 Profitable 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 Efficiency in Oil Refineries—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 CanmetENERGY
Energy Efficiency Monitoring and Improvement in Refinery 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
IRPC 2012 Agenda |
Day 3: Thursday, 14 June
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.
Coffee 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, Refining Product Line Director, Technip
11–11:30 a.m.
The First EST Industrial Plant—the EST Project at Sannazzaro Refinery 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 Profits—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 Gasifier Design to Convert the Bottom of the Barrel—Dev Barot of KBR
Sulfur 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 Refinery Product Blending—Alan Munns of ABB Ltd.
Effect 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 Coffee & Desserts in Exhibit Hall TRACK 1: HEAVY OIL
TRACK 2: PETROCHEMICAL/ REFINING INTEGRATION
Session 9 Session Chair: Antonio di Pasquale, VP Refining 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 Polyolefins—Sanat Kumar, H U Khan, Manisha Sahai, Ajay Kumar, S M Nanoti & M O Garg of CSIR-Indian Institute of Petroleum, Dehradun
Refinery & 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—Refining & 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 Refining 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
www.HPIRPC.com
MILAN, ITALY | 12–14 JUNE
How to Register for IRPC 2012 To 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].
IRPC 2012 Registration Rates: 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
Registration Type
*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.
Registration By 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 Refinery
Location IRPC 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
Accommodations Enterprise Hotel | Corso Sempione 91 | 20149 Milano | +39 02 31818 1 Please 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 023492151 Please visit www.AdmiralHotel.it to check room availability for 12–14 June 2012. Click on the International Refining and Petrochemical Conference link under offers to receive the special per-night rates of €199 (Single), €119 (Double Single Use) or €149 (Double)—subject to availability.
www.HPIRPC.com
MILAN, ITALY | 12–14 JUNE
How to Feature Your Company at IRPC 2012 There 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].
IRPC 2012 Exhibitors: Ametek Ansaldo Auma Italiana S.r.l. Carpenteria Corsi Curtiss-Wright Flow Control EIDOS
Foster Wheeler Hiller GmbH Intergraph ONIS Pilosio S.p.A. SCAME Sistemi
Shin Nippon Machinery Co. Sicelub Iberico Servizi Integrati di Sicurezza West Virginia, USA
Conference Exhibit Floor at MiCo–Milano Congressi in Milan, Italy:
1
3m
2
3
4
5
6
7
8
9
10
11
3m
5.5 m
5.5 m 3m
12
13
17 14
15
18
16
3m 3m
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Exhibition Booths Sold To Date
Available* Sold
1 5 6 7 8 9, 10 11 14 15
Carpenteria Corsi Sicelub Iberico Pilosio S.p.A. Hiller GmbH ONIS Invensys Auma Italiana Srl ABB eni
16 19 24 25 26 27 28 29
Walter Tosto Catapano S.r.E. West Virginia, USA Intergraph Italia L.L.C. Ametek Ansaldo Shin Nippon SIS SERVIZI INTEGRATI DI SICUREZ
30, 31 32 33 34 35
Curtiss-Wright Scame Sistemi S.r.L GTC Technology Foster Wheeler Eidos
* As of March 19.
www.HPIRPC.com
PETROCHEMICAL DEVELOPMENTS Carbon dioxide. With climate-change policies in place, reducing greenhouse gas (GHG) emissions is a key issue. Petrochemical/chemical facilities are major GHG sources through CO2 emissions. 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 partially addressed by reusing sequestered CO 2. Using CO 2 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 developing 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.
SPECIALREPORT
TABLE 5. Commonly available biomass residues in India Agricultural residues
Forest residues
Byproducts— Agro-based industries
Rice straw
Mahua flowers
Sugarcane bagasse
Cassava
Tree tops
Molasses
Sweet sorghum
Leaves
Jute plant
Oil seeds Sawdust
Wheat straw Cotton stalk Sugarcane tops
Recent prospecting of shale gas shows that India possesses 300 Tcf of shale gas that is methane rich. Low conversion levels (10%–20%) of methane sourced from shale gas or NG to petrochemicals require more process improvement before commercialization. However, R&D efforts will certainly make it more affordable and profitable. Considering the necessary government policies and technology 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 ACKNOWLEDGMENTS This 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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HYDROCARBON PROCESSING APRIL 2012
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SPECIALREPORT
PETROCHEMICAL DEVELOPMENTS
LITERATURE CITED 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. 1
18 Tallman,
M. J. and C. Eng, “Consider new catalytic routes for olefins production,” 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 Petroleum 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 interests 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 Technology 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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Select 164 at www.HydrocarbonProcessing.com/RS
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EBARA CORPORATION
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PETROCHEMICAL DEVELOPMENTS
SPECIALREPORT
Improve catalyst management at the FCC unit System 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 minimize 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, equilibrium 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 (gasoline, 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 rejuvenated with fresh material every day. Between 20 metric tons per day (mtpd) and 30 mtpd of fresh catalyst combined with additives and/or Ecat (depending on the operational requirements) are injected daily.
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 catalyst, weighing 1,000 kilograms each, were unloaded every day into
FIG. 1
Design schematic of catalyst and additive injection system.
FIG. 2
Sohar refinery catalyst and additive injection system.
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 specifically 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 flexibility 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 multicomponent DAIS system units be installed, for operation on a standby basis. With this solution, it is possible to constantly maintain an uninterrupted dosage of fresh catalyst into the FCC unit.
HYDROCARBON PROCESSING APRIL 2012
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SPECIALREPORT
PETROCHEMICAL DEVELOPMENTS
FIG. 5 FIG. 3
Sohar refinery vacuum piping system.
Super sacks previously used to unload fresh catalyst.
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
FIG. 4
Design schematic of container trailer tipper facility.
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, without 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 56
I APRIL 2012 HydrocarbonProcessing.com
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-component DAIS system and the custom-built container offloading facilities at the Sohar refinery allowed the plant to operate at maximum 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.
Maria Luisa Sargenti holds the position of technology coordination manager at Grace Catalysts Technologies.
Nathan Ergonul is a technical sales manager at Grace Catalysts Technologies. Matthias Scherer is director of sales for administration and logistics at Grace Catalysts Technologies.
Hemant Upadhyay works as 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.
Talal Said Wasser Al Rawahi is a senior process engineer at the Orpic Sohar refinery in Oman.
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PETROCHEMICAL DEVELOPMENTS
SPECIALREPORT
Operational optimization for mixed-refrigerant systems Use 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
system (MRS) provides refrigeration over a range of temperatures, with smaller temperature differences at the lower temperatures. 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 temperatures ranging from +40°C to –140°C. In the conventional refrigeration method, this broad temperature range is accomplished by a cascade refrigeration system, where three singlecomponent 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
efrigeration systems are among the most critical operating systems in the chemical processing industry. A refrigeration system generally works by removing heat from low-temperature 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 environmentally safe (e.g., nontoxic), thermodynamically desirable (e.g., having a sufficiently low boiling point, high latent vaporization heat and high critical temperature), and operationally feasible (e.g., noncorrosive). A multi-component mixture can also be used as the refrigerant.2 From a thermodynamic viewpoint, a mixed-refrigerant
EC-7 EC-4
SPL2 V-1 EC-1
EE-13 V-11
V-2 EC-2 MIX6
EC-5
MIX3 SPL3 FD-1
FD-3
FD-2
V-10 FD-4 V-12 EC-3 EC-2
C-1
MIX5
EC-3 EC-4
EC-6
C-2
C-3
FD-5
V-1
EE-5
V-4
EE-6
V-3
EE-7
V-6
EE-8
MIX1
EE-9
EC-8 SPL4
V-8 MIX2 EC-9 EC-10 SPL5 V-9
V-7 EC-11 EC-12
EC-1 FIG. 1
Flowsheet of an MRS.
HYDROCARBON PROCESSING APRIL 2012
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PETROCHEMICAL DEVELOPMENTS
reduced from three to one, and over 25 pieces of equipment are saved. It has been reported that the introduction of a mixedrefrigerant system can reduce the capital cost of the entire ethylene plant by 7%.5 This article describes the operating performance of an MRS used in an ethylene plant that was studied through rigorous simulation. Insights on the MRS working mechanism are presented. Based on the simulation, optimization strategies have been developed 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
TABLE 1. Statuses of process streams in MRS evaporators and coolers
Type
Heat duty, GJ/hr
Input temp., °C
Output temp., °C
Description
EE-1
Evaporator
12.4
−102
−127
Charge gas condenser
EE-2
Evaporator
4.0
−102
−123
Charge gas condenser
EE-3
Evaporator
84.7
−43
−102
Charge gas condenser
EE-4
Evaporator
9.0
−21
−40
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
EE-9
Evaporator
28.8
37
11
EE-10
Evaporator
15.7
2
−20
Depropanizer condenser
EE-11
Evaporator
0.2
−14
−19
Charge gas 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
EC-10
Cooler
1.6
−27
−15
Name
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Refrigerant inter-cooler
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 output. 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 system, 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 refrigeration system. About 38% of the HP-HMR is used in EE-5, EE-6, EE-7 and EE-9 to refrigerate the charge gas, hydrogen 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.
Methane cooler
Refrigerant internal heater Ethylene product heater
100 MR in condensers
MR in compressors
50 Temperature, °C
SPECIALREPORT
Cold process flows
Cooling water
0 Pinch point
-50 MR in evaporators Hot process flows
-100
Theoretical power needed from the compressor
-150 0
FIG. 2
50
100 150 200 250 300 350 400 450 500 550 Enthalpy, GJ/hr
Temperature-enthalpy diagram of the MRS.
PETROCHEMICAL DEVELOPMENTS
simulation model has been developed based on the aforementioned 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 simulation, 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 temperature-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.
47,000
3.3
46,000 3.2 45,000 44,000
3.1
43,000 3.0 42,000 41,000
2.9
40,000 2.8
Compressor output pressure, MPa
Modeling and operational optimization. A rigorous
However, contrary to the simulation results, the MR cold-flow curve represents the refrigerant as it undergoes evaporating operations 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 temperature. 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
Total compressor work, kW
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 HPLMR 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.
SPECIALREPORT
39,000 38,000 2.7 24.0 24.5 25.0 25.5 26.0 26.5 27.0 27.5 28.0 28.5 29.0 Cooling water temperature, °C FIG. 3
Profiles of total compressor work and compressor outlet pressure under various cooling-water temperatures.
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HYDROCARBON PROCESSING APRIL 2012
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SPECIALREPORT
PETROCHEMICAL DEVELOPMENTS
efficiency is known, the total energy consumption of the compressor 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 46,500
Total compressor work, kW
46,000 45,500 45,000 44,500 44,000 43,500 43,000 42,500 42,000 41,500 2.80 FIG. 4
2.85
2.90 2.95 3.00 3.05 3.10 Compressor output pressure, MPa
3.15
3.20
Simulation results of compressor work consumption and compressor output pressure.
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 operational 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. Therefore, 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 various cooling-water temperatures. The related total compressor work
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SPECIALREPORT
PETROCHEMICAL DEVELOPMENTS
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 outlet 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 consumption and operational cost, it will require lower cooling-water temperature. Therefore, the simulation results provide an effective way to handle this issue. HP ACKNOWLEDGMENT This work was supported in part by the Texas Air Research Center (TARC) and the Texas Hazardous Waste Research Center (THWRC). LITERATURE CITED 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 investment,” Petrotech 2009, New Delhi, India, 2009.
Jian Zhang is a research associate at the Dan F. Smith Department 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 Department 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 optimization, 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.
1
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.
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PETROCHEMICAL DEVELOPMENTS
SPECIALREPORT
Consider new economics for purification on a small scale For 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-pressure (LP) steam consumption is observed in a three-column configuration 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.
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 distillation 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 formation of the MeOH synthesis catalyst and plant capacity. The economics of the purification scheme involves the complex 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.
KEY PETROCHEMICAL
Methanol 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 Single-column configuration. For fuel-grade MeOH as section. The normal criteria for technology selection are capital a blending component, the major demands regarding quality cost and plant efficiency. are water content and dissolved gases. Fuel-grade MeOH should In a conventional natural gas-based MeOH plant with a capacity of 2,500+ metNatural MeOH ric tpd, syngas generation accounts for 55% gas MeOH MeOH Syngas Compression Desulfurization synthesis distillation production of the total capital cost, distillation accounts for 12%, compression and MeOH synthesis accounts for 12%, and utilities and other Reactor Distillation Reforming services account for 24%. technologies technologies technologies 1. Steam 2. Combined 3. Autothermal
Methanol purification. Crude
MeOH, as removed from the synthesis section, contains water, higher alcohols, impurities and light ends. Table 1 summa-
FIG. 1
1. Isothermal 2. Adiabatic
1. Single column 2. Multicolumn
General flow diagram for a natural-gas based MeOH facility.
HYDROCARBON PROCESSING APRIL 2012
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SPECIALREPORT
PETROCHEMICAL DEVELOPMENTS
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 synthesis loop is generally purified in two stages using conventional distillation 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
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
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 refining 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 threecolumn 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 represents 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.
Tail gas
Condenser 1
Condenser 2 Stripped gas
Fuel-grade product
Reflux drum 1
Liquid off steam
Crude MeOH
Raw MeOH
FIG. 2
68
Concentration column
Process gas
LP steam
LP steam Recycle water
Stabilizer MeoH pump Single-column configuration for an MeOH plant.
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FIG. 3
Product MeOH
Higher alcohols Stabilizer column
Process gas
Reflux drum 2
Two-column configuration for an MeOH plant.
PETROCHEMICAL DEVELOPMENTS SIMULATION STUDY
An analysis was conducted for purifying “AA” grade MeOH from crude MeOH through a two-column and three-column configuration using a commercially available process simulator. 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 twocolumn 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 backwardheat 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. Product MeOH Condenser 2
Condenser 1 Stripped gas
Reflux drum 1
TABLE 2. Simulation results for column schemes Two-column scheme Stabilizer column No. of stages
Concentration column
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, metric ton/metric ton of MeOH
LP column
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
132
5.64
2.96
Boil-up ratio
0.64
3.45
9.44
Stabilizer column No. of stages
HP column
LP column
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
0.8265
Recycle water
Reflux drum 1
Condenser 2 Stripped gas
Reflux drum 2
Liquid off steam
Crude MeOH
38
LP steam consumption, metric ton/metric ton of MeOH
Condenser 1
0.934
Three-column (backward integration) scheme
Reboiler 3
FIG. 4A Three-column configuration (forward integration) for an MeOH plant.
3.51
Reflux ratio LP steam consumption, metric ton/metric ton of MeOH
Reboiler 2
Stabilizer MeOH pump
HP column
LP column
LP steam
Reboiler 1
38
Reflux drum 3
Higher alcohols HP column
Process gas
1.3384
Stabilizer column
Reflux drum 2
Liquid off steam
Crude MeOH Topping column
Three-column (forward integration) scheme No. of stages
SPECIALREPORT
Topping column Process gas Reboiler 1
HP column LP steam Reboiler 2
Product MeOH Reflux drum 3
Higher alcohols LP column
Reboiler 3 Recycle water
FIG. 4B Three-column configuration (backward integration) for an MeOH plant. HYDROCARBON PROCESSING APRIL 2012
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SPECIALREPORT
PETROCHEMICAL DEVELOPMENTS
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 column 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 integrated 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 DISTILLATION
An 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 2.56%
0.34% 2.58%
4.23%
to the additional column and associated equipment. It is very important that before adopting any of the listed schemes, a balance 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 ambient 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:
(
)
⎛ M Cp T −T + λ ⎞⎟ ⎜ w( B ref ) ⎟⎟ Cost of steam, $ = ⎜⎜⎜ ⎟⎟(NG unit price) LHV × η ( ) ⎜⎜⎝ ⎟⎠ NG Boiler 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
84.69%
5.61%
3B-column configuration Operating cost Capital cost
(a) 3F-column configuration
3.15%
0.28% 4.27%
7.75%
77.52%
7.04%
2-column configuration 0
20
40
60 80 Relative cost
(b) FIG. 6
7.18%
0.27%
3.36%
9.58%
100
120
140
Relative capital/operating cost for column configuration.
76.68%
2.93%
3B-column configuration LP steam CW
(c) 3F-column configuration
Column Reboiler Condenser drum
Condenser Pump Instrumentation
2-column configuration 0
FIG. 5
70
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.
I APRIL 2012 HydrocarbonProcessing.com
FIG. 7
20
40
60 80 Relative cost
Operating cost contributions.
100
120
PETROCHEMICAL DEVELOPMENTS higher coolant flow is required in forward-integration scheme compared 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.
SPECIALREPORT
7
Liu, B. Z., Y. C. Zhang, P. Chen, and K. J. Yao, “Research on energy saving 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.
New thinking. A comparison of the two- and three-column
Dr. K. V. Patwardhan is a senior Process Engineer at R&D Cen-
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 twocolumn scheme. Although, in the three-column scheme, backward integration offers higher savings as compared to forward integration scheme, column control will be complicated, and more operating attention is necessary. HP
tre of Larsen & Toubro’s Hydrocarbon IC. He has five years of experience in the field of process design, modeling, troubleshooting and optimization of ammonia, hydrogen and methanol process plants.
LITERATURE CITED 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.
G. Satishbabu is a process engineer at R&D centre of Larsen & Toubro’s Hydrocarbon IC. He has been working in process simulation, design and engineering of ammonia and reforming technologies for the last four years.
1
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.
P. V. Balaramakrishna is currently the head of process engineering group at R&D Centre of Larsen & Toubro’s Hydrocarbon IC. He has more than 18 years of experience in the field of process design, advanced process control, commissioning, troubleshooting and optimization of process plants.
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Use better designed turboexpanders to handle flashing fluids New models eliminate vibration problems and improve reliability K. KAUPERT, Energent, Santa Ana, California
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 ethylene 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 compressors 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 existing 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 turbines until their more recent resurgence.
2.8
2.4 Pressure coefficient, (–)
Energy efficiency. For petrochemical/chemical applications,
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 flashing 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-
2.0 Gas content X (–) x = 0.002 1.6 x = 0.001 1.2
x = 0.0005 x=0
0.8 0.8 Efficiency
M
illions of dollars or euros in revenue are creatively found by clever process engineers through flashing liquid turbines. These turbines convert a liquid into a vapor for hydrocarbon processes. A flashing liquid turbine generates electricity and concurrently removes heat from the process fluid. For simple electric-power-generation applications, the obvious 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-heatrecovery systems and geothermal plants where the so-called triangular 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
0.6 0.4 0.2 0.0 0.05
x=0
0.01
x = 0.0005
x = 0.002
x = 0.001
0.15 Flow coefficient, (–)
0.2
0.25
FIG. 1A Performance of three-stage centrifugal pump operating as a radial-inflow centrifugal turbine with water and changing air content.4,5 HYDROCARBON PROCESSING APRIL 2012
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1.3 1.0 bar back pressure 3.45 bar back pressure 5.9 bar back pressure 7.85 bar back pressure
1.2 1.1 1.0
TP Efficiency, ––– SPL
Efficiency, TP/SPL
ciency degradation is summarized in Fig. 1B, as a function of the vapor-volume fraction in the liquid. In Fig. 2, an eight-stage centrifugal 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 centrifugal 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 centrifugal impeller. From a design perspective, this can be reviewed in
1.0 0.8 0.6 0.0
FIG. 1B
0.1
0.2 Void fraction, z
0.3
0.4
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
0.8
0.7
Turbine efficiency,
Measurements with 35%-40% outlet vapor
0.5
0.4
0.3 Single-phase measurements 0.2
0.1 0.04
74
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 recirculation pattern is formed within the liquid-vapor mixture. This causes substantial mixing losses and efficiency degradation. Furthermore, 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
0.6
FIG. 2
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 outlet 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
0.06
0.08 0.10 Flow coefficient,
0.12
Turbine efficiency vs. flowrate coefficient as measured on an eight-stage radial-inflow centrifugal turbine.
I APRIL 2012 HydrocarbonProcessing.com
where Vs is the slip velocity Vv is the vapor velocity Vl 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 generated 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)
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where v is the vapor density Cd is the drag coefficient along a linear direction x l is the liquid density P is the pressure D 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 motivation 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
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 turbine, 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 Molar composition, Molar Methane: 94% Nitrogen: 5% T1
T2
T3
T4
T4
T6
Nozzle inlet Nozzle outlet Impeller inlet
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:
Impeller outlet
0.16 xv 0.52 v 0.29 xv 0.83 v
Enthalpy
Dmax = 12/vVs2
Typical P vs. h diagram for a single-stage radial-inflow centrifugal turbine during a liquid to vapor, flashing expansion with a hydrocarbon liquid.
FIG. 3
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 expansion 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 measured 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 liquidexpander 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
xv = vapor mass fraction v = vapor volume fraction Nozzle inlet 0.00 xv Nozzle outlet/impeller inlet 0.00 v Impeller outlet
Pressure
(0.5vVs 2) (Cd ) (πD2/4) – (πD3/6) (dP/dx) = (l πD3/6) (Vl dVl /dx) Vs 2 = 4D[l (Vl dVl /dx) + (dP/dx)]/(3vCd )
BONUSREPORT
Two-phase jet from nozzle Nozzle
Impeller blades
Vapor
FIG. 4
Liquid
Sketch of a vapor-liquid axial jet flow exiting the nozzle and 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. HYDROCARBON PROCESSING APRIL 2012
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FIG. 7 FIG. 5
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.
New 1-MW flashing liquid expander being commissioned using, hydrocarbon flashing liquid.
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 radialinflow 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 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 decompression 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. 1
FIG. 6
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 welldispersed mist flow, as seen in Fig. 5.
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 impeller 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 tur76
I APRIL 2012 HydrocarbonProcessing.com
Dr. Kevin Kaupert is the director of technology at OC Turboexpanders. 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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ROTATING EQUIPMENT
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Understand multi-stage pumps and sealing options: Part 2 Designing 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 processes 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.
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 designrelated. 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.
Option 1: Single seals for multi-stage pumps. Fortunately, single seals are often a possible option for multi-stage pumps. Unlike dual-mechanical seals, single seals will not require
B FIG. 1
A. common style of mechanical seal often found in PWI water applications. As salt accumulates near A, fretting damage often occurs near B.
Old design FIG. 3
A
FIG. 2
Multiple springs are exposed to the process fluid in this seal.
Modern design
Examples of the older and newer styles of mechanical seals. (Source: AESSEAL Inc., Rotherham, UK, and Rockford, Tennessee.)
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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 cartridge seal, i.e., the spring-loaded face does not rotate—-a generally 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. Unfortunately, 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 company 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 movement 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 nonrotating (“stationary”) seal can move axially. Single-seal options. By addressing the key causes of pre-
FIG. 4
Pump type Service/duty Fluid Temperature Speed Seal pressure Current seal Metal parts Other materials
Pump type Service/duty Fluid Temperature Speed Seal pressure Discharge pressure Seal currently used Metal parts Other materials FIG. 5
80
mature failure, thoughtfully engineered, reliable single-seal solutions 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 hydrogen sulfide (H 2S). Even small amounts (approximately 10 ppm) can cause sulfide6UZDL21 2-stage Water disposal booster stress corrosion in “conventional” metalSalt water lurgies. So, the proper metallurgy must 55°C-80°C be selected. Recall that in H2S-containing 1,450 rpm 10 bar services, the elastomers should be changed UCW-4250-5X4U from the more commonly used Viton to C 276 SiC/SiC/Aflas 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.
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.)
6 x 13 WMSN 5-stg Shipping pumps 20% Crude oil + 80% Formation water 63°C 2,960 rpm 104 psi 1,000 psi Borg Warner (N2031 – 90) Hastelloy C SiC/SiC/Aflas
Two single seals are installed in two pumps. (Source: AESSEAL Inc., Rotherham, UK, and Rockford, Tennessee.)
I APRIL 2012 HydrocarbonProcessing.com
Option 2: Dual-seal option. Conventional 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 service life because the fluid film is controlled and the salt-crystal accumulation is effectively prevented. Yet, dual seals in PWI systems are often impractical because of pump location and
ROTATING EQUIPMENT geography. Much of the Middle East is considered an extreme environment for typical PWI stations. The average daytime temperature 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 drawbacks. 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 crosssectional views from different manufacturers will reveal how the
FIG. 6
Side view of an HP seal offered by a prominent seal manufacturer.
BONUSREPORT
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 manufacturer 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 equipment 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 modern O-ring pusher dual seal, as shown in Fig. 7, has many advantages 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
FIG. 7
Side view of a modern dual mechanical seal. (Source: AESSEAL Inc., Rotherham, UK, and Rockford, Tennessee.)
FIG. 8
An API Plan 54 cooling unit. (Source: AESSEAL Inc., Rotherham, UK, and Rockford, Tennessee.) HYDROCARBON PROCESSING APRIL 2012
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FIG. 10 FIG. 9
A water-circulating API Plan 54 cooling unit operating onsite. (Source: AESSEAL Inc., Rotherham, UK, and Rockford, Tennessee.)
A high-capacity air cooler unit for an API Plan 54 seal support system. (Source: AESSEAL Inc., Rotherham, UK, and Rockford, Tennessee.)
and water-disposal pumps use dual seals per API Plan 54 systems, 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-
FIG. 11
An air blower unit for an API Plan 54 seal support system.
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 selfcontained. 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. Conversely, 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 reliabilityfocused user-purchaser gives equal attention to seals and sealsupport systems. Comments. The intent of this two-part article is to give the reader a basic insight into the many opportunities for well-engineered components offered by highly competent seal manufacturers. 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.
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 development and applications engineering roles for AESSEAL and specializes 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. Select 169 at www.HydrocarbonProcessing.com/RS 82
Special Supplement to
CATALYST 2012 Perspectives on the 2012 energy industry [C–84] CORPORATE PROFILES Axens [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.
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PERSPECTIVES ON THE 2012 ENERGY INDUSTRY Here 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 certainty 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—particularly in the US. A raft of new shale gas production 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 earthquake 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 slowdown in nuclear plant development in virtually every country. Oil will remain extremely sensitive to political 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 electric vehicles will further nibble away demand. All of these factors will contribute to the uncertainty with which energy companies will have to cope. Most energy companies will find that their current operating models, strategy and planning 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 important include: C–84
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• • • •
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, companies 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 depending on results and how the business environment evolves. This involves integrated-option planning. Integrated-option planning is often overlooked 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 routinely 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 operating 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 changing upstream and downstream conditions and redirecting resources, technology, talent and capital to areas of opportunity. For many energy companies, this is an elusive capability. With so many different layers and business operations to manage, few organizations have systems that fuse the right processes, people and data to drive profitable outcomes on a consistent basis. But the lack of integratedoption planning can often lead to missed opportunities. 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 training skilled workers that would be needed. It did not put in place contingency plans for the potential 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 riskmanagement 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 conceptions 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,
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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, multistakeholder 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 companies, pursuing opportunities without a coherent 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 strategic intent and objectives of partners and to ensure that these objectives are aligned. They identify in advance the capabilities that the projects 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 capability can make the difference between earnings and losses, especially where oil products and gas inventories are involved (as in the downstream) or where there is high dependency on third-party suppliers (as in the upstream). Companies that have been diligently pursuing the more traditional paths to prosperity—for example, 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 available 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 coordination 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 processes, authorities, and commercial and technical 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 companies 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 supplychain management improvement. A powerful way to address this shortcoming, particularly in companies with diverse business 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 activities that can deliver cost and value advantages to all of the groups, while customizing supplychain 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 pressurepump 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 outweigh 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 lowpriced 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 business 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 particularly 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.
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 University. Mr. Clyde is a licensed CPA in the State of Texas. 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. HYDROCARBON PROCESSING
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The winning catalyst combination for your hydrocracker )3, )%, ):,TFSJFTUIFFYQFSUUSJPUPNBYJNJ[F DZDMFMFOHUI BDUJWJUZBOENJEEMFEJTUJMMBUFTTFMFDUJWJUZ 4JOHMFTPVSDF*40t*40t0)4"4 www.axens.net Select 53 at www.HydrocarbonProcessing.com/RS
AXENS
THE PERFORMANCE IMPROVEMENT SPECIALISTS 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.
Increasing Middle Distillate Selectivity HRK 658
HDK 776
HDK 786
HDK 766 HYK 762 HYK 752 HYK 742 HYK 732
HYDROCRACKING CATALYSTS Axens’ 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 hydroprocessing 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 hydrogenation 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 CATALYSTS For 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 burning, 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-
Increasing Conversion Activity
Hydrocracking catalyst performance mapping. 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 CATALYSTS Axens has recently completed the acquisition of the Willow Island (West Virginia) manufacturing plant for reforming catalyst and appropriate intellectual property rights to pursue such business from Criterion. This acquisition 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 INFORMATION HR Series
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89, Bd Franklin Roosevelt – BP 50802 92508 Rueil-Malmaison Cedex – France Email:
[email protected] Website: www.axens.net HYDROCARBON PROCESSING
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action loves reaction Chemical 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 Polyolefin Catalysts Refining Catalysts Syngas Catalysts Custom Catalysts
Select 77 at www.HydrocarbonProcessing.com/RS
BASF
BASF—The global leader in catalysis We create chemistry 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 technology through continuous process and product innovation.
Focus of R&D BASF 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 technologies BASF Process Catalysts and Technologies are the leading manufacturer 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 technology 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 catalysts Mobile Emissions Catalysts enable cost-effective regulatory compliance by providing technologies that control emissions from gasoline- and diesel-powered passenger cars, trucks, buses, motorcycles and off-road vehicles.
Precious metal services Precious Metal Services support the catalysts business and BASF customers with services related to precious metals. The business purchases, 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
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CONTACT INFORMATION Americas BASF Corporation Iselin, NJ 08830, USA Tel: +1-732-205-5000 E-mail:
[email protected] Asia Pacific BASF East Asia Regional HQ Ltd. Central, Hong Kong Tel: +852-2731-0191 E-mail:
[email protected] Europe, Middle East, Africa BASF SE Ludwigshafen, Germany Tel: +49-621-60-21153 E-mail:
[email protected] Wesbite: www.catalysts.basf.com
HYDROCARBON PROCESSING
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de use our hydropro i w d l r o w s r cessin e n fi g Re a c t a d l y n s a t s s e t i o g o deliver l techno ts from low-quality f c u d o r p r e eeds. clean you how. (001) ow h s s u t Le
ISOCRACKING VGO
ICR 512 ICR 180 ICR 185 ICR 250
510.242.3 177 www.clg-clean .com
clean transportation fuels ultra-low sulfur diesel (
