HP_2012_09

REFINING DEVELOPMENTS Innovative solutions upgrade heavy oil into ‘cleaner’ transportation fuels ®

HydrocarbonProcessing.com | SEPTEMBER 2012

HEAT TRANSFER DEVELOPMENTS Energy efficiency found through better simulation modeling and maintenance

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SEPTEMBER 2012 | Volume 91 Number 9 HydrocarbonProcessing.com

10

6

94 SPECIAL REPORT: REFINING DEVELOPMENTS

39 Maximize diesel production in an FCC-centered refinery, Part 1 P. K. Niccum

47 Redefining reforming catalyst performance: High selectivity and stability P.-Y. Le-Goff, J. Lopez and J. Ross

55 Upgrade heavy oil more cost-efficiently C. A. Cabrera and M. A. Silverman

63 CO2 capture from SMRs: A demonstration project W. Baade, S. Farnand, R. Hutchison and K. Welch

DEPARTMENTS

4 6 9 13 19 30 120 124

Industry Perspectives Brief Insight Impact Construction Construction Boxscore Update Marketplace Advertiser index

71 Increase FCC processing flexibility with improved catalyst recycling methods M. Lippmann and L. Wolschlag

COLUMNS

33

Reliability When not to use oil rings

35

Engineering Case Histories Case 70: Twenty rules for troubleshooting

37

Viewpoint From mill to wing: How waste materials could become the next green aviation fuel

79 Bio-isobutanol: The next-generation biofuel R. Kolodziej and J. Scheib

87 Successful fouling control hinges on effective monitoring X. Price, C. Teran, A. Vanhove and J. Casanova

BONUS REPORT: HEAT TRANSFER DEVELOPMENTS

95 What are the benefits of rigorous modeling in heat exchanger design?

J. Cazenave

103 Prevent external corrosion of boiler tubes under refractory lining K. Biramov, M. Maity, E. Al-Zahrani and M. A. Kareem

126

Automation Safety ‘Sticktion’: A dangerous failure mode

ENGINEERING AND CONSTRUCTION—SUPPLEMENT

E-109 What you don’t know can hurt you J. Glenney

E-112 Engineering and construction news Cover Image: The Valero Port Arthur Refinery was commissioned in 1901 by Gulf Oil Co. to process Spindletop crude oil. This Gulf Coast refinery has had many process additions and improvements throughout its history. In 2001, nearly $850 million was invested in a delayed coker and hydrocracker to enable the plant to run heavy, sour crude. At present, the Port Arthur Valero refinery has a throughput capacity of 310,000 bpd. See page 20 for more history of this refinery. Photo courtesy of Valero Energy Corp., San Antonio, Texas.

P. O. Box 2608 Houston, Texas 77252-2608, USA Phone: +1 (713) 529-4301 Fax: +1 (713) 520-4433 www.HydrocarbonProcessing.com Editorial@HydrocarbonProcessing.com

Industry Perspectives Key industry officials answer a poll question from HydrocarbonProcessing.com Is it reasonable for 15% fuel ethanol blends (E15) to be used in passenger vehicles during the next decade?

“My answer is only in certain regions. Autos in some countries like Brazil already use 25% ethanol in the gasoline blend. Brazil is also unique in that there is a large portion of the auto fleet that can use 100% ethanol fuel instead of gasoline. In the U.S., we expect the E10 gasoline blend to remain the dominant fuel product and do not expect widespread introduction of E15 for at least another five years. Most U.S. fuel retailers have been reluctant to sell the E15 blend because use of the fuel would void most new car warranties. Another barrier to the introduction of E15 is that state-level fuel specifications would need to be changed; something that took several years when ethanol was first introduced in the late 2000s.”

—ALFRED LUACES, IHS Senior Director of Research and Analysis, Global Petroleum Markets

“After more testing than has ever been completed for a 211(f) fuel waiver, the U.S. Environmental Protection Agency approved the use of E-15 for use in 2001 and newer vehicles. Its use will grow slowly over time as the resistance to its use by the refining industry withers in the face of compelling economics and consumer choice.”

—BOB DINNEEN, President and CEO of the Renewable Fuels Association

“E15 should be made available when the science shows it is safe for consumers and consumers actually demand the fuel. Over 95% of cars and light trucks in the U.S. are currently built to run on gasoline containing 10 percent ethanol, or E10, and today’s auto manufacturers will not warranty their engines for the use of fuel with higher ethanol content. They have good cause; a recent CRC study issued in May shows that even the use of E15 in EPA-approved vehicles can cause significant damage.”

—CHARLES T. DREVNA, President of American Fuel & Petrochemical Manufacturers (AFPM)

HydrocarbonProcessing.com reader response:

EDITORIAL Editor Reliability/Equipment Editor Process Editor Technical Editor Online Editor Associate Editor Contributing Editor Contributing Editor Contributing Editor

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John Royall Ron Higgins Sheryl Stone Pamela Harvey

Yes, within 5 years .................................................................................... 16% Yes, within 10 years ................................................................................... 8% Yes, but only in select regions .............................................................. 6% No, not safe or economical ................................................................. 70%

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| Brief European refiner affirms renewables project Total has reaffirmed its partnership and financial backing to the technology of renewable products company Amyris, the companies said in a recent statement. Total dedicated an $82 million funding budget over the next three years exclusively for the deployment of Amyris’s renewable farnesene and for the production of renewable diesel and jet fuel. Upon completion of the research and development program, Total and Amyris intend to form a joint venture company that would produce and market renewable diesel and/or jet fuel, as well as nonexclusive rights to other specialty products, the companies said.

BILLY THINNES, TECHNICAL EDITOR / Billy.Thinnes@HydrocarbonProcessing.com

Brief BP has agreed to sell its 266,000-bpd Carson refinery in California and related logistics and marketing assets

in the region to Tesoro for $2.5 billion in cash. The deal value includes the estimated value of hydrocarbon inventories and is subject to post-closing adjustments. The company noted that the sale is part of a previously announced plan to reshape BP’s US fuels business. BP also plans to sell its Texas City refinery, in order to focus on its three northern US refineries, which the company says are “feedstock advantaged.” Subject to regulatory and other approvals, Tesoro will acquire the Los Angeles-area refinery as well as the associated logistics network of pipelines and storage terminals and the ARCO-branded retail marketing network in Southern California, Arizona and Nevada. The sale also includes BP’s interests in associated cogeneration and coke calcining operations. The sale is expected to close before mid2013. BP will sell the ARCO retail brand rights and exclusively license those rights from Tesoro for Northern California, Oregon and Washington and continue to produce transportation fuels at its refinery in Cherry Point, Washington.

Chemicals company Celanese said that a jury ruled in its favor in litigation filed by Southern Chemical relating

to the terms of a multi-year methanol supply contract. The jury said the contract, under which Celanese has paid Southern Chemical about $130 million/year, should continue until its expiration, adding that Celanese did not violate the terms of the agreement. The contract, which expires in 2015, is valid for Celanese operations in the US and Mexico. Celanese is the largest methanol consumer in the US, while Southern Chemical is the second-largest supplier (after Methanex). Under the contract, Celanese received about 800,000 tpy of methanol from Southern Chemical. Southern Chemical alleged that Celanese was not using the purchased methanol solely for internal use, and was instead shipping it to other chemical companies for more than the contract price. Celanese officials, however, said they were selling the material as methyl acetate and had been given clearance to do so by the Southern Chemical president. Celanese plans to build a 1.3-million tpy methanol plant in Clear Lake, Texas, which would presumably replace the Southern Chemical supply once the contract expires in 2015.

KBR and Shell Global Solutions plan to expand their hydroprocessing technology alliance. In addition to

hydrocracking and hydrotreating, KBR will now market, sell and provide technology and design packages for Shell’s deepflash, high-vacuum unit distillation and thermal conversion technologies. KBR said the new alliance terms will help refinery operators that want to improve their distillation performance to optimize assets, minimize expenditures and capital investment and debottleneck operations. To meet those goals, refiners can use deep-cut vacuum distillation to maximize the recovery of distillate

from residue. The falling demand for residue fuel oil means that refiners can use thermal conversion technologies to convert the bottom of the barrel to higher value products.

The US Chemical Safety Board (CSB) will pursue a full investigation to determine the causes of the August 6

fire at the Chevron oil refinery in Richmond, California. A CSB team of seven investigators arrived at the refinery several days after the fire and conducted witness interviews while reviewing documents at the site. The fire occurred when gasoil leaked from an 8-in. pipe connected to a crude oil distillation tower in the refinery’s crude unit. Workers initially noted the leak and were in the process of attempting repairs on piping connected to the still-operating crude oil distillation tower when the leak suddenly intensified. The gasoil immediately formed a large flammable vapor cloud. Important issues to resolve in the investigation include understanding why the pipe that later failed was kept in service during a late-2011 maintenance turnaround and what procedures and industry practices exist for responding to a leak of combustible material from a running unit. The CSB anticipates executing a site preservation and evidence testing agreement with Chevron and other investigative groups and arranging for independent testing of the leaking section of pipe to determine the failure mechanism. Both Chevron and the United Steelworkers, which represents hourly workers at the plant, have been cooperating with the CSB team. Chevron has provided assurances that its personnel will freely share their knowledge and investigative information with the Board. Cal/OSHA, Contra Costa County and the US Environmental Protection Agency.

Kuwait’s Equate Petrochemical Co. has shut down one of its ethylene glycol units with a total capacity of

550,000 mtpy after a fire on July 31. The fire resulted from a leak in part of a manufacturing unit. Equate said the fire was contained and extinguished promptly, adding that production operations of other production units were not affected. The company anticipates that the shutdown of the damaged unit will last six weeks.

UOP has been selected by Lukoil to provide technology to produce blending components used to make high-octane

gasoline and petrochemicals at its facility in Nizhny Novgorod, Russia. Lukoil will license an integrated suite of Honeywell’s UOP technologies to produce high-quality gasoline blending components, propylene and other petrochemicals, the company said. Russia is the third largest energy consumer in the world, and demand is growing due to increasing economic activity. The suite of UOP technology will be used in a new integrated fluid catalytic cracking complex. The new units, expected to start up in 2015, will produce more than 1 million tpy of gasoline blending components and more than 170,000 tpy of propylene.

Hydrocarbon Processing | SEPTEMBER 2012 7

Refinery Wash Water Injector Constructed of Inconel® 625, this injector is 6 ft. (1.8 m) long, weighs 2600 lbs. (1179 kg) and has a class 1500 flange.

SUPERIOR SPRAY. SERIOUS RESULTS. Using a quill or injector for water wash or chemical injection? We can help improve performance. Here's how: UÊÊNozzle selection assistance. There are dozens of options and a wrong choice can result in wall wetting, corrosion and unscheduled downtime. Using a quill? Consider a change. A slot in a pipe doesn’t provide the same precise flow and drop size control as an injector U Analyze process conditions to determine spray direction – co- or counter-current. Spray direction affects drop size, wall contact, evaporation rate and more – it’s essential to get it right UÊÊDesign validation using Computational Fluid Dynamics (CFD) and our proprietary drop size data. We simulate your environment to verify spray performance, determine injector placement and ensure the materials of construction can withstand thermal stresses, heat transfer, vortex shedding and more We are uniquely qualified to optimize injector performance: spray expertise, manufacturing capabilities for B31.1 and B31.3 code compliance and a proven track record with customers like Jacobs Engineering, Shaw Group, Bechtel, Shell, Conoco Phillips and dozens more.

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STEPHANY ROMANOW, EDITOR / Stephany.Romanow@HydrocarbonProcessing.com

Insight

Energy crisis: Time and talent wanted Maximizing the energy potential from all hydrocarbon resources is the main goal for all nations. More efficient utilization of energy—natural gas, coal and crude oil—facilitates economic growth. As shown in the headlines from the last 90 years of Hydrocarbon Processing, progress comes in leaps and bounds, and too often, is followed an economic crisis.

Natural gas has always been part of the energy and economic equation. In the early days, this hydrocarbon was originally “stripped” to obtain the natural-gasoline components that were blended into transportation fuels. Now natural gas is a major segment of the global energy mix; its application has morphed as better methods to use this hydrocarbon developed for power generation and transportation fuels.

News about shale oil and shale gas were published back in the 1950s. However, technologies to extract and to process shale oil needed time to advance, as now witnessed in current media. The hydrocarbon processing industry has and continues to attract great talent to unravel the present-day energy problems. New solutions are investigated and researched to discover energy resources for tomorrow.

Headlines from Hydrocarbon Processing, September 2002: Proactive strategies needed to improve petrochemical profits. A recent analysis by SRI Consulting concludes that this industry continues to struggle from poor planning over the past five years. By early 2001, fewer new petrochemical plants were under

New column being raised at the Stanlow (Chershire) refinery. The 240ton and 170-ft long column was constructed by Babcock & Wilcox at the Renfrew works. Construction at the refinery will be completed by January 1952. Petroleum Refiner 1951.

construction. Likewise, large, high-cost producers have shut down. The global petrochemical industry has begun the supplyside rationalization process. Strategies for long-term survival over the next 10 years by global petrochemical producers will involve: 1) Better integration and more flexibility in feedstock selection, 2) Building plants to capitalize on economy of scale 3) Investing in new technologies, 4) Rationalizing or consolidating high-cost operations and 5) Developing new products and processes.

Middle East emerging as dominant force in polypropylene production. Processing capacity of polypropylene (PP) is set to explode over the next five years in the Middle East and Africa regions. Approximately 3 million metric tons of new PP capacity will be built in the Middle East alone.

NSR update. In June 2002, The US Environmental Protection Agency (EPA) announced plans to modify the Clean Air Act’s New Source Review (NSR) program. EPA recommended changes on the clarification for “routine repairs and replacement.” The second set of changes will focus on “emission measurement” policy.

Headlines from Hydrocarbon Processing, September 1992: Natural gas makes an impact on the HPI. Natural gas (NG) continues to increase its role as a plant fuel, petrochemical feedstock, competitor for distillate markets and a motor fuel. The

A 75-ton prefabricated steel column arrives by barge to be installed at the Tidewater Oil Co’s Flying A refinery near Wilmington, Delaware.

The column is a gasoline splitter to be installed at the refinery’s gas plant. Petroleum Refiner 1956.

Hydrocarbon Processing | SEPTEMBER 2012 9

Insight NG supply/demand and pricing trends are important to refiners and petrochemical manufacturers. In 1992, NG prices remained low—averaging $1.06 MMBtu—and failed to climb during the winter heating season. The Energy Information Agency believes that NG consumption will increase 5.5%/yr.

Hydrogen supplies a major focus for refiners. Hydrogen supply is becoming critical as the refining industry adjusts to new environmental regulations and market-driven factors.

In Europe, growing demand for methyl-tertiary butyl ether (MTBE) to sustain higher octane needs due to the lead phaseout will require more hydrogen. In the US, gasoline reformulation and tough diesel specifications will require refiners to also consume more hydrogen. Growing demand for better quality gasoline is placing more pressure on available hydrogen supplies. Approximately 3.6 Tcf of hydrogen is consumed in the US, with the refining industry responsible for half of the hydrogen consumption. With the upcoming changes in the gasoline blending pool, the US refining market will need an additional 1.4 Tcf of hydrogen to meet new clean fuel requirements.

Methanol demand to grow rapidly through 1996. Methanol (MeOH) is forecast to be one of the fastest growing petrochemicals over the next five years. Increased blending of MTBE in gasoline has radically changed MeOH demand patterns. Oxygenate (MTBE) production will account for 60% of the MeOH consumption in the US market. A recent rebound in the formaldehyde market is also increasing MeOH demand.

Headlines from Hydrocarbon Processing, September 1982: Third oil crisis is likely before 1990. Energy champion and economist, Dr. Daniel Yergin has released a new book based on a four-year international research project at Harvard entitled: Global in security, a strategy for energy. Dr. Yergin believes a third oil crisis is likely before 1990, and oil prices will double by 2000. (Oil prices averaged between $27.66/bbl to $33.56/ bbl in July 1982.) These trends are based on rising demand for petroleum and economic recovery.

The North Rincon Gasoline plant raises a 97-ft absorption oil still column. The facility has a design capacity of 35 Mcfd. The new facility is part of the Shell Oil Co. and Cities Services Oil Co. project.

Hydrocarbon Processing and Petroleum Refiner 1961.

10 SEPTEMBER 2012 | HydrocarbonProcessing.com

US refining capacity increasing. According to the American Petroleum Institute (API), US crude oil distillation capacity is forecast to increase to 17.7 million bpd (MMbpd) by March 1983; it is a 227,000 bbl increase over reported 1981 distillation capacity. The API survey also indicated that 2.3 MMbpd of the US capacity was shut down in March 1982—about 12.5% of the US distillation capacity. The increase reflects new refineries and expansion projects under construction and expected to be complete by year end.

Acid rain: A growing controversy. Efforts continue to define “acid rain.” The new debate focuses on EPA’s efforts to roll back sulfur dioxide and nitrogen oxide emissions. It is estimated that the new environmental rules will cost billions to implement.

In addition, the US Congress is reauthorizing the Clean Water Act (CWA) to meet second stage treatment requirements by 1984. Questions still exist on best available technology (BAT) for water treatment. Over 90% of the US chemical industry met the CWA of 1977 rules. Nearly all major industries have reduced discharges of conventional pollutants into navigable waters to practical minimums.

European petrochemical industry looks for upturn. Europe’s petrochemical industry should improve compared to 1981 growth numbers. Yet, many structural problems continue for this industry. Lack of integration continues to plague the European market, especially in taxation, safety standards, and environment and health protection. European petrochemical producers are at a disadvantage when compared to US and Japanese producers. Europe’s present economic systems do not support investment. In addition, studies show that bulkchemical production now exceeds local demand. For example, Europe’s plastic industry suffers from 40% over-capacity production. National expansions have collectively overshot regional demand. The European chemical industry needs structural reorganization to eliminate overcapacity and investment to further develop high-value specialty products.

To see more headlines from 1972 to 1923, visit HydrocarbonProcessing.com.

Side view of the new superheaters constructed at the Neches Butane Products’ Port Neches, Texas facility. Petroleum Refiner 1958.

Our safety experts talk safety.

Our operators talk control. But when it comes to keeping our people and plant safe, we all need to speak the same language.

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refinement redefined

clean fuel, turning “bottom of the barrel” into “top of the line.”

of other residue-upgrading technologies, turning the “bottom of the barrel” into more proven technology that processes low-quality residue streams like vacuum residue into

from every barrel.

For more information, visit www.uop.com/uniflex. © 2012 Honeywell International, Inc. All rights reserved.

BILLY THINNES, TECHNICAL EDITOR / Billy.Thinnes@HydrocarbonProcessing.com

Impact

2Q12

FIG. 1. Refining and marketing M&A deals by value and count.

May-12

1Q12

Jan-12

4Q11

Mar-12

3Q11

Nov-11

2Q11

–,500

Jul-11

1Q11

–1,000 Sept-11

1 0

–500

May-11

2

0

Jan-11

3

500

Mar-11

4

1,000

Nov-10

5

1,500

Jul-10

7 6

the hands of independent rather than integrated companies. Many of these independent operators have benefited over the past two years from rising profits in the US due to advantage-priced crude supplies from Canada and the developing tight oil plays in America, but long-term prospects are more uncertain.

“Gasoline demand in the US is down 5% compared to last year,” said Mr. Ihne.

“Long-term demand for refined products in the US is still uncertain due to stricter corporate average fuel economy and renewable fuel standards, as well as future competition from natural gas-based transportation fuels.”

However, reduced domestic consumption of gasoline and distillate fuels has largely been offset by exports of refined products from US Gulf Coast refiners to Mexico, South America and Northern Europe. Fig. 2 provides an overview of the net exports of US petroleum products from January 2010 to May 2012.

“Without export demand, US refiners would likely be challenged to operate near the 85%-plus capacity they reached this year, and could instead be facing increased rationalization of exiting capacity,” said Mr. Ihne.

The cloudy regulatory and competitive landscape creates an uncertain environment for many of the newly independent players in this segment.

“Refiners now have varying degrees of balance sheet strength,” said Trevear Thomas, another Deloitte Consulting analyst. “The question is whether that is sus-

Sept-10

9 8 7 6 5 4 3 2 1 0

Asset value Corporate value Total deal count

May-10

Asset and corporate value, $ billions

8

Jan-10

and marketing (R&M) deals took place during the first half of 2012, compared to 12 transactions in the first half of 2011 and 13 during the second half of 2011 (Fig. 1).

However, the total value of transactions

Mar-10

Downstream M&A. Only nine refining

From integrated to independent.

Ownership within the R&M segment of the energy industry has been transformed over the past decade as large integrated companies have “high-graded” their portfolios, selling or spinning off their downstream assets to focus on higher-performing upstream operations. Now, over two-thirds of US R&M operations are in

Exports, thousand bpd

Energy price fluctuations present both near-term challenges and interesting opportunities for the oil and gas mergers and acquisitions (M&A) market. As Deloitte Consulting points out in a recently released report, current depressed North American natural gas prices (prices far below the market rates in other continents) will likely continue to attract both domestic and international supermajors that have money to spend on natural gas assets at low prices. Deloitte believes the longterm outlook for US natural gas holds promise, as gas gradually gains domestic market share, and as prospects for LNG exports from the US improve.

The consulting company sees buying interest and E&P activity in liquids-rich shale plays continuing, as well as midstream consolidation and infrastructure investment, as that segment restructures and invests to serve the rapidly changing North American energy landscape. According to Deloitte, a resurgent North American energy market and the investment needs that accompany that resurgence should set the stage for sustained M&A activity over the longer term.

picked up during this year’s first half to $10.6 billion, up 36%, when compared to $7.8 billion in the first half of 2011, and several orders of magnitude larger than the $2.6 billion during the second half of 2011.

“We actually saw a good increase in deal value year over year in this segment,” said Roger Ihne, a principal at Deloitte Consulting. “This was primarily driven by two large deals that took place outside the US: one in Asia and one in Europe.”

One refinery acquisition during this period was notable not for its size but for the industry affiliation of the buyer. A major international airline announced in the second quarter of 2012 that it would buy a Trainer, Pennsylvania, refinery for $180 million. The company intends to upgrade the refinery’s capabilities so that it can produce a much higher proportion of jet fuel, giving the airline a source of fuel in a region of the US that has very little jet fuel production, as well as exchanges to allow jet fuel to be supplied throughout other geographic areas.

“This is certainly a unique situation that has everyone intrigued both within and outside the industry,” said Mr. Ihne.

Total deal count

Taking a glance at mergers and acquisitions

FIG. 2. Net exports of US petroleum products.

Hydrocarbon Processing | SEPTEMBER 2012 13

Impact tainable long-term, or whether that situation will lead to consolidation.”

A crucial issue for refiners located along the Gulf Coast is whether the Keystone pipeline project will be allowed to move forward. Many of the refineries in this region are designed to process heavy, high-sulfur crude oil.

“Refining assets in the Gulf are some of the most sophisticated in the world,” said Mr. Ihne. “They can process heavy crude

14

from Canada and the new tight oil supplied from various US plays, but unless refiners gain access to that oil, we will have assets in the US that have a comparative economic advantage to the rest of the world—but, nonetheless will have to rely on higher cost imported crude from elsewhere.”

Compliance in emerging risk areas Ernst & Young recently held a seminar

Select 151 at www.HydrocarbonProcessing.com/RS

on risk compliance for today’s global oil and gas companies. One session in particular during the seminar focused on emerging risk areas in the energy market, which include antitrust, the Foreign Corrupt Practices Act (FCPA) and financial statement fraud. To avoid such potentially damaging missteps, many energy companies are upping their investment in compliance.

The addition of chief compliance officers and the hiring of compliance professionals to work in key business regions enable companies to better implement formalized risk assessments and audits on a regular basis. Communication between the compliance, internal audit and legal functions occurs on a daily basis, and many companies have a structure process to identify, rank and mitigate emerging risks.

Regardless of size and scope, however, all compliance programs need the support of senior managers and the board of directors, session panelists said.

“Compliance must be taken seriously, and senior management must set the proper expectations,” said Jeff Johnston, a partner at Vinson and Elkins. “Companies must be willing to walk away from business if there is something unethical about the project. You cannot send employees into high-risk countries without significant amounts of training and a structured plan for how they are to operate.”

“The tone at the top is the most important element,” said John Freeman, general counsel for Technip USA. “There has to be more than a formal code of conduct; senior management must talk about compliance in a way that shows commitment to following the law.”

In recent years, the FCPA has become a focal point for international energy companies. Most companies have some level of compliance program in place to train employees on the FCPA as well as auditing behavior in the field.

Yet antitrust issues continue to grow in importance as the energy industry relies more heavily on joint ventures and partnerships that require sharing of information and cooperation among competitors.

“The government certainly has not reduced its antitrust efforts,” Mr. Johnston said. “Last year there were a record number of antitrust cases and a record number of fines. Regulators are very focused on the energy industry. They are on the lookout for collusion, and they aren’t afraid to move in if they suspect anything.”

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compression and variable-speed drive technologies to ensure the adaptation of the gas supply to fluctuating demand, to slash maintenance requirements, and to maximize environmental performance. Highest availability and low power consumption of all units are the best basis for an eco-friendly and successful operation.

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Impact Antitrust issues can also arise during the acquisition process. “We are very concerned about “gun-jumping,”” Mr. Freeman said. “There are still a lot of people who don’t understand that you can’t act as one company prior to the closure of an acquisition. While you can do integration planning, you can’t share competitive information.”

To increase awareness of antitrust regulations, companies should implement

mandatory training for all employees who have any contact with competitors/partners. Because many antitrust violations occur informally, follow-up monitoring and auditing are difficult and the bulk of a company’s efforts must be up front.

“Most violations of this nature don’t have a paper trail,” Mr. Freeman said.

“They happen when people are talking to one another at dinner or after a meeting, and information is shared inadvertently.”

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Roskill recently released a market outlook on molybdenum. The company expects that molybdenum growth rates will exceed global GDP rates to 2016.

Global demand for molybdenum bounced back from the impact of the global economic downturn, growing by just over 11% in 2010 and a further 9% in 2011, according to the report. China now accounts for around 31% of global molybdenum demand and its growth rates continue to outpace those in other countries. While global demand for molybdenum is forecast to grow at an average of 4.6% per year to 2016, Chinese demand is forecast to increase by 7.5% per year.

The principal engines of growth will be increased use of stainless and other steels containing molybdenum in process, power and desalination plants, in oil and gas production and distribution and in motor vehicle components. The greater use of molybdenum steels and high performance alloys and catalysts, combined with robust growth in the economies of the BRIC countries and other countries in Asia and South America, will ensure growing future demand for molybdenum.

Mine capacity sufficient to meet demand until 2015. Primary molybde-

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Future bright for molybdenum

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num mines were the first to respond to the recovery in demand in 2010, but, in 2011, growth in output of byproduct molybdenum from copper mines outpaced growth from primary mines. In 2012, mine capacity is sufficient to meet demand and supply is likely to show a surplus over the next three years. Roskill lists some 60 new projects and expansions that could potentially produce molybdenum, yielding an additional 240 ktpy, indicating that longterm mine supply is assured. Around 33% of new projects identified in 2012 are located in North America, 28% in Central and South America and 10% in China. In the next two years, byproduct output is likely to grow at a higher rate, but, from 2014 on, new Chinese molybdenum-only projects will redress the balance. In the past, insufficient roasting capacity has resulted in a bottleneck, but additional capacity has been installed and further additions are under construction in Chile, China and the US by Codelco, Molymet, China Molybdenum and JDC.

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Construction

North America CB&I has a contract from Enterprise Products Partners L.P. for the license and basic engineering of a propane dehydrogenation unit on the Texas Gulf Coast. The unit will use the CATOFIN propane dehydrogenation process from Lummus Technology that uses SüdChemie’s latest CATOFIN catalyst to produce 1.65 billion lb/yr (approximately 750,000 metric tpy) of polymergrade propylene.

The Carlyle Group L.P. and Sunoco, Inc., have agreed to form Philadelphia Energy Solutions, a joint venture ( JV) that will enable the historic Philadelphia refinery to continue operating. The refinery, reportedly the oldest continuously operating one on the East Coast, processes 330,000 bpd of oil into various refined products and was scheduled for shutdown in August 2012.

Under agreement terms, Sunoco will contribute its Philadelphia refinery assets to the JV in exchange for a nonoperating minority interest. The Carlyle Group’s investment will flow directly to the refinery’s balance sheet to fund future capital projects, facility upgrades and enhance the refinery’s working capital. Carlyle will hold the majority interest, and oversee day-to-day operations of the JV and the refinery.

Philadelphia Energy Solutions, with economic support from The Commonwealth of Pennsylvania, will invest in several capital intensive projects that are critical to the long-term economic viability of the facility. Planned improvements will help the environment through reduced waste and emissions, and will also reduce reliance on foreign oil supplies.

Projects include upgrade of the refinery’s catalytic cracker and the building of a mild hydrocracker and hydrogen plant, as well as the construction of a high-speed train unloading facility at the refinery. The JV is also exploring other significant capital projects, including the

creation of new businesses based on the availability and abundant levels of natural gas from the Marcellus shale.

KBR will provide front-end engineering, detailed engineering and procurement services to DuPont’s Industrial Biosciences Group for what is said to be a first-of-a-kind plant to be constructed in the Midwest US. The facility—which will reportedly be DuPont’s first cellulosic ethanol plant in Nevada, Iowa— will process 1,300 tpd of corn stover and produce 27.5 million gpy of ethanol.

Used as a blending component in gasoline, the ethanol produced will enable fuel manufacturers to meet the US Environmental Protection Agency’s (EPA’s) mandated requirements for ethanol derived from cellulosic sources.

Groundbreaking is scheduled for the second half of 2012, with a 12-month to 18-month construction period.

Braskem has selected Jacobs Engineering Group Inc. to provide professional technical services for portions of the Marcus Hook refinery near Philadelphia, Pennsylvania. The 781-acre refinery’s propylene splitter assets were acquired by Braskem in late June 2012.

Jacobs’ initial scope of work includes retrofitting the new acquisitions so Braskem can more efficiently process propylene for use in its adjacent polypropylene plant. Jacobs’ operations in Mt. Laurel, New Jersey, and Conshohocken, Pennsylvania, are expected to execute the work.

South America Honeywell has been selected to upgrade the safety and control system at Staatsolie Maatschappij Suriname’s refinery to Honeywell’s Integrated Control and Safety System (ICSS) solution. The upgrade, which is being designed and implemented within the context of the Suriname Refinery Expansion Project, will double the refinery’s capacity and expand its range of products and fuels.

The project is being managed by Saipem as the main contractor responsible for engineering, procurement, module prefabrication and construction management.

Developed on the strengths of Honeywell’s Experion Process Knowledge System (PKS) architecture, ICSS offers simplified operations, integrated process control and safety controllers. The solution will equip Staatsolie with best-inclass compliance, reliability and safety for its refinery production units.

The upgrade includes the expansion of Honeywell’s Alarm Management System, Operational Insight Software and OPC Desktop Historian solutions currently installed at the site.

CH-IV International’s president, Jeffrey P. Beale, has congratulated EcoEléctrica L.P. for the safe construction, commissioning and commencement of service of an expansion to its existing liquefied natural gas (LNG) terminal located in Peñuelas, Puerto Rico. The terminal expansion doubles the EcoEléctrica facility’s regasification capacity, allowing it to send natural gas to the Puerto Rico Electric Power Authority for use in its existing power-generating facilities.

CH-IV International provided owner engineering services to EcoEléctrica.

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Construction engineering and design (FEED) used to permit the expansion project; regulatory support during the project’s permitting and construction; negotiation of an engineering, procurement and construction (EPC) contract; and oversight during the project’s construction, commissioning and startup.

A subsidiary of Foster Wheeler AG’s Global Engineering and Construction Group has a contract to provide engineering, procurement services and construction management (EPCm) for PDVSA Petróleo S.A.’s El Palito refinery expansion project in Venezuela. Foster Wheeler will execute the project in consortium with Toyo Engineering Corp. and Y & V Ingeniería y Construcción.

Foster Wheeler and its consortium partners have previously completed the project’s front-end engineering and design (FEED).

The expansion will include a 140,000bpsd crude/vacuum distillation unit, a 24,500-bpsd naphtha hydrotreating/ continuous catalytic-reformer complex, a 58,000-bpsd vacuum gasoil hydrotreater, a 45,000-bpsd diesel hydrotreater, an 80-million-scfd hydrogen-production unit, a 250tpd sulfur-recovery/tail-gas treatment unit, a new flare system, amine regeneration and sour-water stripper facilities, along with relevant utilities, interconnecting units and offsites. These include marine facilities and a new product storage tank farm.

The expansion is intended to double the refinery’s capacity to 280,000 bpsd, processing heavy and extra-heavy crudes from the Orinoco Belt, and increasing production of clean fuels. The project is expected to be completed during 2016.

Europe INEOS Technologies has licensed its Innovene G, Innovene S and Innovene

PP processes to ZAO Vostochnaya Neftechemicheskaya Co. (ZAO VNHK), a subsidiary of OJSC NK Rosneft, for VNHK’s new petrochemical complex in Nakhodka, Russian Federation. All VNHK’s units will incorporate INEOS’ latest polymer technology advances and will ensure a competitive advantage for petrochemical complex customers in both domestic and global markets. Engineering work is now underway.

Royal Vopak, Greenergy and Shell UK Ltd. have reached an agreement with the joint administrators of Petroplus Refining & Marketing Ltd., to purchase assets of the former Coryton refinery, UK. The three companies plan to develop and invest in a state-of-the-art import and distribution terminal to be managed by Vopak. The initial storage capacity will be around 500,000 m3, with potential to expand up to 1 million m3 in later stages.

Texas-based refinery has a long history The Valero Port Arthur Refinery was commissioned in 1901 and has had many process additions and improvements throughout its history (see pg. 38). In 2001, nearly $850 million was invested in a delayed coker and hydrocracker to enable the plant to run heavy, sour crude as shown

20 SEPTEMBER 2012 | HydrocarbonProcessing.com

on the September 2012 cover of HP. Other investments include the recent expansion of the coker to 95,000 bpd from 85,000 bpd. The most recent expansion of the crude and vacuum units has increased the refinery’s ability to process lower-cost, heavy sour crude oil and increased throughput capacity to 310,000 bpd. The refinery is strategically located on the Texas Gulf Coast, approximately 90 miles east of Houston. The refinery’s location accommodates its extensive logistics system, which includes access to Gulf Coast water-borne crude oil via the refinery docks or through the Nederland, Texas, terminals of Sun or Oil Tanking. The milestones of this refinery are: • Commissioned in 1901, with many upgrades since then • One of four refineries acquired in the purchase of Premcor in 2005 • Total throughput capacity of 310,000 bpd • Has ability to process 100% sour crude oil, of which up to 80% can be heavy sour crude oil • Production includes convention-

al, premium and reformulated gasoline before oxygenate blending, as well as diesel, jet fuel, petrochemicals, petroleum coke and sulfur • Strategically located on 4,000 acres on the Port Arthur Ship Channel • Crude oil received from the Valero dock or by pipeline • The Port Neches dock’s crude oil receipts transferred by the Valeroowned Lucas pump station, located about 13 miles from the refinery • Refinery production distributed into the Colonial Pipeline, Explorer Pipeline and Teppco Pipeline or across the refinery docks into ships or barges • Employs approximately 820 individuals.

Awards and honors. This refinery is

one of only two Texas refineries Environmental Management System certified. It is TCEQ Clean Texas Program Bronze member and has received EPA National Partnership for Environmental Priorities, 2008 Pollution Prevention Achievement Award. This refinery has attained more than 1 million hours without a lost-time injury.

Construction Vopak, Greenergy and Shell will be equal shareholders of the new joint venture ( JV), which will acquire and develop the assets and the site. After reaching final agreement on the future design and operational capabilities, Vopak, on behalf of the JV, will execute the new facility’s development and will operate the terminal when the works have been completed. Greenergy and Shell will sign long-term contracts with the JV. The conversion will involve operational, technical, safety and environmental enhancements to the refinery’s current infrastructure, including modern blending technology.

Linde Engineering, a division of the Linde Group, is set to build a new Alpha-SABLIN plant for producing linear alpha olefins (LAOs) in Nizhnekamsk, Russian Federation, which, upon completion, will be operated by OAO Nizhnekamskneftekhim (NKNH). NKNH awarded Linde Engineering contracts for license, basic/detail engineering, and supply of equipment and materials for revamping NKNH’s existing LAO plant.

The plant is expected to come onstream by mid-2014, supplying NKNH with 37.5-kiloton/yr of LAO, with maximized production of C4 and C6 fractions.

The revamp project will partially make use of the existing equipment of NKNH’s former LAO plant with implementation of Alpha-SABLIN technology.

Alpha-SABLIN is a superior and flexible full-range process for producing LAO by selective catalytic oligomerization of polymer-grade ethylene, jointly developed and owned by Linde Engineering and Saudi Basic Industries Corp. (SABIC).

BASF plans to expand its vinylformamide (VFA) plant in Ludwigshafen, Germany. In addition, the company intends to increase the polymerization capacity in Ludwigshafen, and build a new polymerization line for VFA in China, to further process the feedstock from Ludwigshafen. This facility will be built at the Zhenjiang site, Jiangsu Province.

The total investment is in the threedigit million euro range and will create about 40 new jobs worldwide. Production is scheduled by the end of 2014.

ed Burckhardt Compression to deliver one process gas compressor API 618 for the refinery expansion in Nieuwdorp, The Netherlands. The compressor will be used within the diesel-hydrotreating process as a hydrogen makeup gas compressor. The compressor is scheduled to be delivered in mid-2013.

LyondellBasell’s Spheripol process technology has been selected by ZapSib-

Neftekhim L.L.C, a fully owned subsidiary of SIBUR, for a new 500-kiloton/yr single-line polypropylene (PP) plant to be built in Tobolsk, Russian Federation.

Startup is projected after 2017.

Jacobs Engineering Group Inc. has a design and fabrication contract from INEOS Enterprises Ltd. for two gas-gas heat exchangers to be installed in a sulfuric-acid plant at Runcorn, Cheshire, UK.

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21

Construction INEOS Enterprises selected Jacobs’ proprietary Chemetics radial-flow gasgas heat-exchanger design over other available designs on the basis that it provides the most appropriate design and technical solution for INEOS Enterprises’ plant. The equipment is expected to be fabricated at Jacobs’ facility in Pickering, Ontario, Canada.

BASF plans to build a butadieneextraction plant at its Verbund site in Antwerp, Belgium. The plant will have a production capacity of 155,000 metric tpy and is scheduled to start up during 2014. The investment amount will be in the high double-digit million euro range.

Energy Bio-Chemicals has selected the technology of UOP Ltd., a Honeywell company, to boost yields at Romania’s largest synthetic-rubber production facility.

The Romanian company will use Honeywell’s UOP KLP process to purify butadiene, a monomer used to produce synthetic rubber, at its CAROM Onesti styrene-butadiene-rubber facility. The project is part

of the company’s modernization investment program to upgrade its butadiene installation and increase production.

The KLP process increases the yield of butadiene, while also eliminating acetylene, a difficult-to-handle and unwanted byproduct, from the process. UOP will also provide a proprietary caustic Merox unit to remove sulfur from the crude C4 feedstock.

The contract includes licensing, engineering, technical support and catalysts.

Africa Shell Petroleum Development Co. has awarded Saipem with an engineering, procurement and construction (EPC) contract for the Otumara-Saghara-Escravos Pipeline Project, which will be developed approximately 65 km northwest of Warri, Nigeria.

The contract encompasses the engineering, procurement, fabrication and commissioning of a network of pipelines, ranging in diameter from 12 in. to 4 in., for a total length of 40 km, in a swamp area, to connect the client’s flowstations in the Otumara, Saghara and Escravos fields.

The project, scheduled to be completed in 18 months, is strategic for Shell to comply with Nigerian environmental regulation, which targets zero flaring in the country.

Fluor Corp. has started work on a new project for Sasol Technology Pty. Ltd.’s Tar Separator Project in South Africa. The new contract is for engineering, procurement and construction management (EPCm) services for the replacement of 24 duplex stainless-steel separator tanks.

The gas-liquor separation units separate various gaseous, liquid and solid components from the gas-liquor streams that originate in the gasification, gas cooling, Rectisol and phenosolvan units. Engineering is underway, with construction to begin in the fourth quarter of 2012.

The 24 separation units weigh between 80 tons and 100 tons each.

Construction will begin using shifts working 24 hours per day, seven days per week to shorten the construction schedule, and to enable ongoing production while the project is underway. Construction is expected to be complete by mid-2015.

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Saipem has signed a lump-sum engineering, procurement and construction (EPC) contract with Saudi Aramco and Sumitomo Chemical for the naphtha and aromatics package of the PETRORabigh II Project, expanding the integrated refinery and petrochemicals complex in Rabigh, Saudi Arabia.

The scope of work includes the EPC of two processing units: a naphtha reformer unit and an aromatics complex.

The project will be completed by the fourth quarter of 2015.

Once the expansion is complete, the PETRORabigh complex, whose original production was more than 20 million tpy of petroleum and petrochemical products, will process an additional 30 million scfd of ethane and 3 million tpy of naphtha.

Samsung Engineering has an award from Abu Dhabi Oil Refining Co. (TAKREER) to provide a carbon-black unit and a delayed-coker unit. At a value of $2.48 billion, it is the eighth order received in five years from ADNOC, the national oil company of UAE and the parent company of TAKREER.

Construction The units will be located in the refining complex in Ruwais, Abu Dhabi, with a capacity of 40,000 tpy of carbon black and 30,000 bpd of crude oil.

Samsung Engineering will be providing project-management services for the engineering, procurement, construction (EPC) and commissioning processes on a lump-sum turnkey basis and is scheduled for completion by December 2015.

ABB has won a contract worth over $100 million to build a new gas-condensate processing plant for Petroleum Development Oman (PDO) in the Sultanate of Oman.

The new Saih Nihayda condensate stabilization plant will be located near the Saih Nihayda gas plant, and will have the capacity to process 4,500 standard m3/ day of condensate. The new plant, which will be used as a backup for the existing central-processing plant, is scheduled to be complete by the end of 2014.

ABB will be responsible for the engineering, procurement and construction (EPC) of the condensate stabilization facilities, including project management, training, testing and onsite support for operation and maintenance after startup. In addition, ABB will supply power equipment such as low- and mediumvoltage switchgear, power transformers, the electrical control system, as well as continuous emission-monitoring systems and other analytical instrumentation.

Maire Tecnimont S.p.A. has contracts in the amount of approximately €290 million for engineering, procurement and construction (EPC) and other services.

In the Kingdom of Saudi Arabia, its subsidiaries, Tecnimont S.p.A. and Tecnimont Arabia Ltd., have been awarded EPC contracts on a lump-sum turnkey basis to implement a manufacturing plant in Jubail for Sadara Chemical Co., a joint venture between Saudi Aramco and The Dow Chemical Co. Completion is expected by the end of 2014.

In Bulgaria, Maire Tecnimont has signed, through its subsidiary Tecnimont KT S.p.A., an EPC contract on a lumpsum turnkey basis with Lukoil Neftochim Burgas AD for a new sulfur-recovery unit, SRU-4, to be installed in the Burgas refinery. Project completion is expected by the end of October 2014. The scope of the contract is part of the Burgas

refinery development expansion project.

Moreover, Maire Tecnimont has received a series of awards, located in Europe, the Middle East, South Asia and the Far East, for licensing, design and maintenance services, as well as technology packages.

Asia Pacific Reliance Industries Ltd. (RIL) has awarded Technip a contract to supply a

license, basic-engineering package, and engineering and procurement services for the refinery offgas cracker (ROGC) plant. This contract is part of the expansion project being executed at RIL’s world-scale Jamnagar refining and petrochemical complex in Gujarat, India.

The ROGC plant will reportedly be among the largest ethylene crackers in the world, and will be integrated to RIL’s Jamnagar refinery complex, using refin-

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Construction ery offgas as feedstock. The plant’s products will be used as feedstock for the new downstream petrochemical plants.

The ROGC plant will use Technip’s ethylene technology, including its proprietary SMK furnace technology.

ConocoPhillips has approved the development of a second 4.5 milliontpy production train for its Australia Pacific LNG coal-seam gas (CSG) to liquefied natural gas (LNG) project in Queensland, Australia.

LNG exports from the second train are scheduled to commence in early 2016 under binding sales agreements to Sinopec Corp. and Kansai Electric Power Co. Sanction of the second LNG train includes the further development of related upstream gas-gathering and processing infrastructure, as well as the construction of the second production train by Bechtel.

The estimated gross capital cost associated with the second train is $6 billion, with a total two-train project cost of $20 billion. The majority of the scope will be executed under pre-agreed options to ex-

tend existing contracts related to the first LNG train, including the Bechtel International, Inc., and Bechtel Australia Proprietary Ltd. contract for facilities on Curtis Island.

Following the startup of the second train, the project has an anticipated peak production net to ConocoPhillips of 100,000 bpdoe to105,000 bpdoe.

Methanex Corp. has restarted its second methanol plant at its Motunui site in New Zealand, and production has commenced. The addition of the second plant adds 650,000 tpy of capacity and increases the Motunui site capacity to 1.5 million tpy.

Chiyoda Corp. has an engineering, procurement and construction (EPC) contract from Tokyo Gas Engineering Co., Ltd. for the Hitachi liquefied natural gas (LNG) Terminal in Ibaraki port, Hitachi district, Japan.

Tokyo Gas Co., Ltd., the terminal owner, plans to construct this fourth LNG terminal in Ibaraki port, with

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one 230,000-kiloliter LNG tank, one 50,000-kiloliter liquefied petroleum gas (LPG) tank, three LNG vaporizers, as well as a large off-loading facility and a receiving jetty.

The EPC work is scheduled to start in 2012, with operation planned for 2015.

BP and JBF Petrochemicals (a wholly owned subsidiary of JBF Industries Ltd.) have signed an agreement for licensing BP’s latest generation purified terephthalic acid (PTA) technology. JBF intends to build a 1.25 million-tpy unit at the Special Economic Zone in Mangalore, India, to produce PTA, the primary feedstock for polyesters used in textiles and packaging.

JBF expects the Mangalore plant to come onstream at the end of 2014.

PETRONAS has awarded CB&I a contract for the license and engineering design work for five petrochemicals units.

The project is part of the new Refinery and Petrochemicals Integrated Development (RAPID) project to be located in Johor, Malaysia.

Lummus Technology will be providing technology for a world-scale steam cracker complex comprising ethylene, butadiene, benzene, isobutylene and methyl tertiary butyl ether (MTBE) units.

Evonik plans to build a new polyamide-12 (PA12) line in Singapore by 2014 to increase the availability of this specialty plastic.

Following the initial announcement in 2011, the basic planning for the construction of a 20,000-metric-ton plant is now entering the final phase. Subject to the approval of the relevant bodies, the new plant is scheduled to be completed by 2014.

Adding to the capacity of the existing facility in Europe, this second production plant for PA12 in Singapore is designed to substantially increase the availability of the product and its guaranteed delivery. It will also bring Evonik even closer to its customers in Asia’s fastgrowing markets.

Idemitsu Kosan Co., Ltd., and Formosa Petrochemical Corp. (FPCC) have agreed to establish a joint-venture ( JV) company to manufacture and sell hydrogenated hydrocarbon resin (I-MARV)—a colorless, transparent,

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Construction odorless resin with outstanding thermostability and thermal resistance.

Since 1994, Idemitsu Kosan has produced I-MARV, using its own unique technologies at the Tokuyama plant (manufacturing scale: 10,000 metric tpy).

Plans call for finalizing detailed terms in the future, aiming to establish the JV in the second half of 2012 and completing the installation of equipment in 2014.

The planned plant will have a capacity of 40,000 metric tpy and will be built on the site of FPCC’s Mailiao plant in Yunlin County, Taiwan.

A subsidiary of Foster Wheeler AG’s Global Engineering and Construction Group has a contract from Samsung Engineering Co. Ltd. for a waste-heat recovery unit for PTT Public Co., Ltd.’s (PTT’s) power generation and heat re-

covery project at the Map Ta Phut Industrial Complex in Thailand. Samsung is PTT’s engineering, procurement, construction and pre-commissioning contractor for this project.

Foster Wheeler will design, engineer and supply the waste-heat recovery unit, including a selective catalytic-reduction system and other associated equipment.

Delivery of the unit is expected during the third quarter of 2013.

BASF and SINOPEC have signed a memorandum of understanding (MoU) to further strengthen their cooperation by jointly exploring the possibility of building a world-scale isononanol (INA) plant in the Maoming Hi-Tech Industrial Development Zone in Maoming, China.

The final scope of the investment will be determined following the outcome of the joint feasibility study, which is expected by the end of 2012.

Under MoU terms, the two parties will evaluate the technical, commercial and economic viability of jointly owning and operating a world-scale facility for the production of INA under a 50-50 joint-venture agreement.

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!

Creating Value.

Carver Pump Company 2415 Park Avenue Muscatine, IA 52761 563.263.3410 Fax: 563.262.0510 www.carverpump.com

26

Select 157 at www.HydrocarbonProcessing.com/RS

CB&I has a $225 million+ contract from AGL Energy Ltd. for the engineering, procurement, construction and commissioning work on the Newcastle Gas Storage Facility Project (NGSF) at Tomago, New South Wales, Australia. CB&I was contracted in 2010 by AGL to begin front-end engineering and design (FEED) execution planning on the project.

CB&I’s scope of work will include all the civil, structural, mechanical, piping, electrical, instrumentation and commissioning support for construction of a liquefied natural gas (LNG) storage tank, as well as the gas pretreatment, liquefaction, vaporization and associated utilities.

Project completion is scheduled for 2015.

Aker Solutions has been awarded a contract by Technip to supply a monoethylene glycol (MEG) reclamation plant for the Ichthys LNG project in Australia. The contract value is approximately NOK 485 million.

The scope of work includes system engineering and supply of key equipment for the MEG plant, and may include some further options. The equipment deliveries will be in 2013 and 2014.

Scheduled maintenance, inspections, emergency response…Team delivers

LEAK REPAIRS

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eam is a world-class service company with the right people, technology and experience needed to keep your plants online and in production. Our highly skilled technicians work to earn your continued trust and conf idence one job at a time. Å… 6DWLVI\LQJ FXVWRPHU QHHGV VLQFH Å… 7UXH DYDLODELOLW\ Å… 0RUH WKDQ ZRUOGZLGH ORFDWLRQV Å… WUDLQHG DQG FHUWLI LHG VHUYLFH VSHFLDOLVWV Å… :RUOGZLGH VWRFN RI LQ KRXVH VHUYLFH HTXLSPHQW Å… %XQGOHG DSSURDFK KHOSV \RX UHDOL]H FRVW VDYLQJV Å… ,PSURYHG SURGXFWLYLW\ PHHWV RU H[FHHGV \RXU JRDOV | www.teamindustrialservices.com

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EMISSIONS CONTROL

PIPE REPAIR SERVICES

TURNAROUND SERVICES

PIPELINE SERVICES

Construction The MEG reclamation plant will be located on the floating production, storage and offloading (FPSO) unit built by Daewoo Shipbuilding & Marine Engineering. Technip has responsibility for topside engineering.

Toyo Engineering India Ltd. (ToyoIndia) has an engineering, procurement and construction (EPC) contract to build a new multi-business chemical-production site for BASF India at the Dahej Petroleum, Chemicals and Petrochemicals Investment Region (PCPIR) in Gujarat, India. The new site will be an integrated hub for polyurethane manufacturing and will also house production facilities for care chemicals and polymers.

Toyo-India will execute the project under an EPC turnkey contract at a lump-sum price. The plant is expected to become operational in 2014.

The Dahej production site will contribute to BASF’s business expansion in the northern and western regions of India by ensuring local supply of products and solutions for India’s growing markets.

Air Products’ liquefied natural gas (LNG) technology and equipment will be floating on an LNG production platform 180 km off the coast of Malaysia and producing 1.2 million tpy of LNG when the PETRONAS Floating LNG Project 1 (PFLNG 1) comes onstream in late 2015. Air Products has signed an equipment and process license agreement with PETRONAS Floating LNG 1 Ltd., a wholly owned subsidiary of Petroliam Nasional Berhad.

PFLNG 1, to be located off the coast of Bintulu, Sarawak, Malaysia, will use Air Products’ AP-NTM LNG process and equipment. This proprietary equipment includes coil-wound heat exchangers to be built in Wilkes-Barre, Pennsylvania, US; compressor-expanders to be assembled in Fogelsville, Pennsylvania, US; and economizer cold boxes to be built in Tanjung Langsat, Malaysia. The proprietary equipment will be shipped from these three Air Products’ manufacturing facilities for assembly into modules and then installed on the PFLNG 1 vessel.

The AP-NTM LNG process is said to

be the most efficient of all nitrogen-recycle LNG processes in the industry, and is ideally suited for small-scale FLNG applications. This will be the second FLNG project using Air Products’ LNG technology and equipment that has been contractually awarded, and it joins a separate project slated for the Browse Basin off the northwest coast of Western Australia.

Inner Mongolia ChinaCoal Mengda New Energy & Chemical Industry Co., Ltd., a subsidiary of China National Coal Group Corp., has signed a license agreement with Union Carbide Chemicals & Plastics Technology LLC, a subsidiary of The Dow Chemical Co., for its 300-kiloton/yr polypropylene (PP) plant.

ChinaCoal Mengda will license UNIPOL PP process technology from Dow Licensing & Catalysts for the PP plant, part of a 500-kiloton/yr engineering plastics project.

The plant is targeted to start up in 2014 in Ordos City, Inner Mongolia, China, and produce homopolymers, random copolymers and impact copolymers.

DemandPROFESSIONALS SCAN WITH YOUR SMARTPHONE TO VIEW OUR WEBSITE

www.fourquest.com www FourQ FourQuest Energy focuses on servicing the needs of our clients and making a positive impact to thei their business. Motivated people are the most important resource of our company. import We take tak pride in providing safe, quality services to the en energy industry.

A thor thorough understanding of our customers, their processes and issues, is the key to our accurate proces and th thoughtful approach. Having exceptional depth of experience and in-house technical expertise allows us to consistently meet or expert surpass client expectations.

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28 SEPTEMBER 2012 | HydrocarbonProcessing.com

Select 160 at www.HydrocarbonProcessing.com/RS

Tank overfill.

In the best case, you have to clean up.

In the worst case, you end up in court.

Want to sleep well at night?

YOU CAN DO THAT Driving overfill prevention technology forward.

Emerson’s new Rosemount Raptor tank gauging system lets you comply with the reworked overfill protection standard API 2350 (4th edition) for every type of storage tank. The Raptor system includes safety features like SIL certification and a unique radar with two independent gauges (level and overfill) in one housing.

Learn more about Raptor and get the latest API 2350 overfill prevention guidance at www.rosemount-tg.com/safety Select 61 at www.HydrocarbonProcessing.com/RS

The Emerson logo is a trademark and a service mark of Emerson Electric Co. Š 2012 Emerson Electric Co.

CONSTRUCTION BOXSCORE UPDATE / ConstructionBoxscore.com AFRICA Nigeria

COMPANY

CITY

PROJECT

Nigerian Natl Petr Corp

Undisclosed

Refinery (6)

EX CAPACITY UNIT 180 bpd

COST STATUS YR CMPL LICENSOR 4500

P

2015

8 MMtpy

3400

U

2015

4.5 MMtpy None tpy Mbpd Mtpy Mbpd Mm3

2000

200 MMcfd

1500

ENGINEERING

CONSTRUCTOR

ASIA/PACIFIC Australia

Inpex / Total E&P JV

Darwin

LNG

Australia China China India India Indonesia Japan

Conoco Phillips Co BASF BP Zhuhai Chemical Co Indian Oil Corp Ltd Amerind Petroleum Pvt Ltd. Pertamina Inpex

Queensland Zhenjiang Zhuhai Gujarat Visakhapatnam Balikpapan Joetsu

LNG Gasification (2) Polymerizer PTA (3) Refinery Refinery Refinery LNG Receiving Termin

Spectra Energy

Dawson Creek

Gas Processing

Beltransoil Kuwait Petro Corp BASF PCK Raffinerie GmbH Shtokman Development Co Nizhnekamskneftekhim TNK-BP

Brest Antwerp Ludwigshafen Schwedt Murmansk Nizhnekamsk Ryazan

Diesel, ULSD Lube Oil Plant Polymerizer Cracker, HSC (2) LNG Olefins, LinearAlpha Hydrotreater, Vacuum Gas (VGHT) (1)

Barrancabermeja Penuelas El Palito

Hydrocracker LNG Terminal Refinery

Dukan Sohar Izmit

Distillation, Crude Refinery Coker

20 bpsd 187 bpd 8200 tpd

Bakersfield Nevada Alexandria Philadelphia Mont Belvieu

Cogeneration Ethanol Methanol-To-Gasoline Cracker, Catalytic Propylene

20 MW 1300 tpd 3500 bpd None 80.5 bpd

EX EX EX RE

1.25 274 7.5 260 160

1.029 505

P E P H P E

Aker Solutions / Chiyoda JGC Corp / KBR

2016 2014 2014 2014 2014

Bechtel

Technip EIL

2013

Chiyoda

Chiyoda

CANADA British Columbia

C

2012

RE

70 Mtpy 250 MMl/y None 24600 Mbpd 7.5 MMtpy 37.5 kty

C U P U E E

2012 2014 2014 2013 2016 2014

RE

125 t/a

C

2012

EX RE

50 Mbpd None 140 Mbpsd

E C F

2016 2012 2017

U E E

2013 2015 2014

A E E P U

2012 2014

EUROPE Belarus Belgium Germany Germany Russian Federation Russian Federation Russian Federation

EX

UOP / Albemarle

Prokop FW

Toyo Japan

Toyo Japan Technip Linde

Linde

Toyo Japan

LATIN AMERICA Colombia Puerto Rico Venezuela

Ecopetrol CH-IV PDVSA

FW Axens EcoElectronica L.P. FW / Toyo Engineering Corporation Y&V Ingernieria y Construccion C.A

MIDDLE EAST Iraq Oman Turkey

KAT Asphalt & Lub Oil Oman Oil Co TUPRAS

40

FW / Honeywell

Prokop CLG / JGC / UOP / CB&I Tecnicas Reunidas

Prokop UOP / CLG / JGC Tecnicas Reunidas

TJCROSS Engineers KBR

Shaw

UNITED STATES California Iowa Louisiana Pennsylvania Texas

San Joaquin Rfg Co DuPont Co EMRE Philadelphia Energy Solutions Enterprise Products

RE EX

35

Sundrop Fuels Inc.

2013

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Updated daily, our database helps engineers, contractors and marketing personnel identify active HPI construction projects around the world to: • Generate leads • Market research

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PERFORMANCE THROUGH ENGINEERING MaxiFan™ nozzles from BETE Provide FCCU feed injection and gas cooling

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BETE’s DUR O LOK® couplings are all-purpose, lightweight connectors designed to replace standard ANSI flanges and meet the following codes: • ASME Boiler and Pressure Vessel Code, Section VIII • ASME B31.1, Code for Pressure Piping • ASME B31.3, Code for Process Piping

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Reliability

HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR Heinz.Bloch@HydrocarbonProcessing.com

When not to use oil rings For process pumps in particular size and duty categories, oil rings are rarely, if ever, the most reliable means for lubricant application. Oil rings tend to skip and even abrade, as shown in FIG. 1, unless: • The shaft system is truly horizontal.1 Horizontality is very rarely obtained when shims are used to manage shaft centerline alignment.

• Ring immersion in the lubricant is perfect. Consistent depth of immersion can be difficult to maintain over time.

• Ring eccentricity is closely controlled. This is rarely possible unless stress-relief annealing is included as part of the manufacturing steps • Ring bore RMS finish and oil viscosity are maintained within close limits.

Viscosities can change depending on oil temperature and contamination-related oil quality.

• Shaft-surface velocities are within an acceptable range.

Manufacturer’s limits. These various parameters are probably within limits on the pump manufacturer’s test stand, and the manufacturer feels exonerated. However, when considered collectively, these parameters are rarely within the suitably close limits needed in actual operating plants.1 Other vulnerabilities exist and can cause repeat pump failures.2 To avoid premature equipment failure or, alternatively, the need for frequent precautionary replacement of rings and lube oil changes, serious reliability-focused ownerpurchasers often specify and select pumps with flinger discs. Reliability-focused buyers often follow the advice of prominent pump manufacturers whose 1970s-era brochures asked buyers to opt for a superior “anti-friction oil thrower (a disc) to ensure positive lubrication and thus eliminate the problems associated with oil rings.”1 Often, and to accommodate the correct flinger-disc diameter, the pump manufacturer will have to mount the thrust bearing set in a cartridge.

Keen on better pumps. The term “better pumps” describes fluid movers that are designed beyond just soundly engineered hydraulic efficiency and modern metallurgy. Better pumps are units that avoid risk-inducing components or geometries in the mechanical portion commonly called the drive end.

An over-emphasis on (initial) costcutting by some pump manufacturers and many pump purchasers has negatively affected the drive ends of thousands of process pumps. Flawed drive end components contribute to elusive repeat failures that often plague these simple machines. Pump drive end failures represent an issue that has not been addressed with the urgency it deserves.

Remember: Repeat failures can only happen if the true root cause of failure remains hidden, or if the true root cause is known, but no corrective action is taken. Either of these two possibilities will defeat asset preservation and operational excellence goals.

Final word. Reliability specialists should actively track metal wear by oil analysis or by observing the shaft (FIG. 2), or via micrometer measurement of the oil ring width. Active monitoring can move a plant into the best-of-class category.2, 3 LITERATURE CITED Bloch, H. P. and A. Budris, Pump User’s Handbook— Life Extension, 3rd ed., Fairmont Press, Inc., Lilburn, Georgia, 2010.

2 Bloch, H. P., Pump Wisdom: Problem Solving for Operators and Specialists, John Wiley & Sons, New York, New York, 2011.

3 Bradshaw, S., “Investigations into the contamination of lubricating oils in rolling element pump bearing assemblies,” 17th International Pump User’s Symposium, Houston, 2000.

1

FIG. 2. Wear tracking on both equipment shaft and oil ring is of high interest. Note: This oil ring makes contact with housing-internal surfaces. Best practices companies measure and record the ring’s original width as-installed and also its after-removal width.

FIG. 1. Oil rings in as-new (wide and chamfered) condition on the left, and abraded (worn narrow and without chamfer) condition on the right side.1,2

HEINZ P. BLOCH resides in Westminster, Colorado. His professional career began in 1962 and included longterm assignments as Exxon Chemical’s Regional machinery specialist for the US. He has authored over 520 publications, among them 18 comprehensive books on practical machinery management, failure analysis, failure avoidance, compressors, steam turbines, pumps, oil mist lubrication and practical lubrication for industry. Mr. Bloch holds BS and MS degrees in mechanical engineering.

He is an ASME Life Fellow and maintains registration as a Professional Engineer in New Jersey and Texas.

Hydrocarbon Processing | SEPTEMBER 2012 33

Select 78 at www.HydrocarbonProcessing.com/RS

Engineering Case Histories

A. SOFRONAS, CONSULTING ENGINEER http://mechanicalengineeringhelp.com

Case 70: Twenty rules for troubleshooting In previous Engineering Case History columns, I have discussed checklists and their value in avoiding errors during startups. While the rules cannot replace common sense or a logical and methodical approach, they can help avoid embarrassing situations. Here are 20 rules that are most helpful in troubleshooting: Rule 1. Never assume anything. “The new bearings are in stores, and they will be there if there is a failure” is an assumption. The bearings may not be in inventory; likewise, they can be corroded, damaged or, worse, the wrong size.

Rule 2. Follow the data. The shaft failed due to a bending failure, because the bearing failed, because the oil system failed, because the maintenance schedule was extended. This is following the data.

Rule 3. Don’t jump to a cause. Most of us want to come up with the most likely cause for a failure or other situation immediately. Such causes are usually based on our past experience, which may not be valid for this particular failure.

Rule 4. Calculation is better than speculation. A simple analysis is worth more than someone who tries to base the cause on past experiences.

Rule 5. Get input from others but realize they could be wrong. Most individuals want to be helpful and provide input as to the cause. However, such input may not be credible.

Rule 6. When you have conclusive data adhere to your principles. Safety issues are a good example. Your position may not be readily accepted by others because of budget, contract or time constraints. Before taking a stand, have other senior technical people agree with you because it could affect your career.

Rule 7. Management doesn’t want to hear bad news. Do not just discuss the failure and the problems it can cause to management. Present good options that can also be used at other plant locations to avoid similar failures.

Rule 8. Management doesn’t like wish lists. Only present what is needed, not what you would like to have. Adhering to company standards or national codes is usually a good approach.

Rule 9. Management doesn’t like confusing data. Keep technical jargon to a minimum and present the information as clear as possible with illustrations, photos, models and examples.

Rule 10. Management doesn’t like expensive solutions.

Only present one or two cost-effective solutions with options, costs and timing.

Rule 11. Admit when you are wrong and obtain additional data. Admitting to being wrong is one of the most difficult acts. When other data contradicts yours, accepting the truth must be done; otherwise, you will look foolish.

Rule 12. Understand what results you are seeking. The analysis should be done to determine why the rotor cracked— not to redesign the machine. Too often, we get so involved in the analysis that we forget to just solve the problem.

Rule 13. Look for the simplest explanation first. For example, a new drive belt was installed too tight and then broke the shaft.

Rule 14. Look for the least cost and easiest solution. You need to understand what caused the failure first. For example, if a drive belt was too tight, then train the machinists on the correct tightening procedure. Put a placard on the equipment explaining the procedure clearly and include caution areas.

Rule 15. Analytical results, tests or metallurgical results should agree. When the metallurgical analysis says it was a fatigue failure and your analysis says it was a sudden impact, someone is in error. They should both indicate the same failure mode.

Rule 16. Trust your intuition. When you feel something is wrong but can’t prove it, it’s time to do an analysis and get additional data.

Rule 17. Utilize your trusted colleagues to confirm your approach. Talking with my engineering and field colleagues has been the most useful method in finding the true cause of a problem.

Rule 18. Similar failures usually have happened before.

It is your job, as the reliability or maintenance engineer to survey your company and the literature for the cause of similar failures and to determine if it is useful data for troubleshooting this failure.

Rule 19. Always have others involved when analyzing high-profile failures. When safety, legal or major production issues are involved, it is unwise to make critical decisions on your own. This is the time for a team approach so that nothing is missed. Also involve others to develop and implement the final solution.

Rule 20. Someone usually knows the failure cause. It has been my experience from interviewing engineers, operators, machinists and technicians that some of the plant staff usually knew the true cause of a failure. A good interviewing procedure is an important part of the troubleshooting process.

DR. TONY SOFRONAS, P.E., was worldwide lead mechanical engineer for ExxonMobil Chemicals before retiring. He now owns Engineered Products, which provides consulting and engineering seminars on machinery and pressure vessels. Dr. Sofronas has authored two engineering books and numerous technical articles on analytical methods. Early in his career, he worked for General Electric and Bendix, and has extensive knowledge of design and failure analysis for various types of equipment.

Hydrocarbon Processing | SEPTEMBER 2012 35

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Viewpoint

J. HOLMGREN Chief Executive Officer, LanzaTech, Chicago, Illinois

From mill to wing: How waste materials could become the next green aviation fuel

DR. JENNIFER HOLMGREN is the chief executive officer of LanzaTech. She has over 20 years of experience in the energy sector, including a proven track record in the development and commercialization of fuel and chemical technologies. Prior to joining LanzaTech, Dr. Holmgren was vice president and general manager of the Renewable Energy and Chemicals business unit at UOP LLC, a Honeywell Company. In that role, she led UOP’s renewable business from its inception through to the achievement of significant revenues from the commercialization of multiple novel biofuel technologies.

We are in the midst of an energy revolution, with new types of liquid fuels from new sources and an increased supply of traditional fuels unleashed from existing sources thanks to new technologies.

While this is good news, it is tempered by the reality that global demand is forecast to far outpace supply. According to data from industry analysts at Cambridge Energy Research Associates (CERA), we will face a supply gap of 35 million bpd by 2030. That’s even taking into consideration the new supply brought on by the success of hydraulic fracturing in the US, new and forecasted discoveries in the Gulf of Mexico and other areas around the world, and the increased use of electric vehicles and other high fuel efficiency cars and trucks.

The world needs more supply. Period.

And nowhere is this more important than in the aviation fuels market, where alternatives to liquid fuels, such as electricity or fuel cells, are not yet a viable option. While I am sure many in the industry would love to see jets plug in rather than fill up, it’s going to take some time.

Understanding this, the aviation industry has placed a premium on developing sustainable, low-carbon alternative fuel sources that not only address the carbon footprint issue but also review the agro-economic, socio-economic and environmental assessments of next generation fuels. Of course, given the huge volume of consumption, the industry has a strong focus on sustainability, as well as price. The cost for alternatives must be on par with, or better than, petroleum.

My company believes there’s a way to address many of these issues simultaneously by creating new, low-carbon fuels economically, sustainably and without diverting precious land or water resources. LanzaTech uses a proprietary fermentation process to convert gases (including industrial waste gases and gas derived

from any biomass source) into fuels and chemicals. We are one of several companies looking to turn waste into fuel.

This approach is cost effective, as it uses material that has no value; environmentally effective, as it recycles gases that would otherwise be sent freely to the atmosphere; and socially effective, as it can create domestic jobs and foster energy security.

With industry partners such as Swedish Biofuels and Imperium Renewables, along with support from Pacific Northwest National Labs, National Renewable Energy Labs and the Defense Advanced Research Projects Agency (DARPA) and funding from the Federal Aviation Administration and the US Department of Energy, LanzaTech is is working on an “alcohol to jet” (ATJ) pathway. These biofuels will exhibit similar or identical chemical and physical properties to their petroleum counterparts, enabling them to be utilized at blends up to 50% without any modifications to the storage and transportation infrastructure or aircraft engines.

At the successful completion of these projects, LanzaTech will have produced ATJ fuel that can be used for testing purposes by ASTM International as it creates a fuel specification for ATJ. There are a number of co-benefits from all of this, including the relative abundance of industrial gases as a feedstock, the reduction in overall CO2 emissions, and the avoidance of land-use conflicts in feedstock production. Using waste materials as feedstock is helping to reshape the perception of energy sources.

We hope that success in our efforts will breed more interest and partnerships from industries that generate large sources of CO and CO2 (or other waste gases) so they will see the synergies in recycling waste materials and putting them back to work once again powering planes, trains and automobiles.

Hydrocarbon Processing | SEPTEMBER 2012 37

| Special Report REFINING DEVELOPMENTS Over the next 10 years, global demand for refined oil products is forecast to increase at an average rate of 1.2% per year. Developed nations are experiencing flattening or declining demand as biofuels and other renewable energies increasingly displace oil-based products.

In contrast, developing nations will experience continued demand increases for energy in all forms. Changing demand and markets are forcing the refining industry to rethink its long-term goals.

Accordingly, refiners must identify opportunities to maximize their assets against future fuel demand as discussed in this month’s Special Report.

Gulf Oil’s Port Authur, Texas, Refinery Still in 1929. Courtesy of Valero Energy Corp.

Special Report

Refining Developments P. K. NICCUM, KBR Inc., Houston, Texas

Maximize diesel production in an FCC-centered refinery, Part 1

Improving LCO yield and quality. FCC units produce a

significant quantity of high-sulfur, low-cetane-number aromatic distillate—i.e., LCO. Modern diesel quality specifications dictate that LCO must be upgraded in hydrotreating or hydrocracking units to make it an attractive diesel blending component. The disconnect between LCO quality and the specifications demanded for modern automotive diesel can be seen in TABLE 1, which compares the quality of a typical LCO with increasingly stringent diesel specifications.2 Directionally, the yield and quality of the LCO can be improved by lowering FCC conversion and adjusting the FCC catalyst formulation, but the improvement in LCO quality is not sufficient for the LCO to be considered a desirable diesel blending component.

FIG. 2 illustrates US refinery LCO samples from the years 1967 and 1982. The decline in LCO quality over the period would, in part, be the natural result of increasing FCC operat-

ing severity and the completion of the industry’s changeover from amorphous catalyst to highly rare-earth-exchanged zeolite catalyst targeting increased gasoline production.3 These data are included to provide perspective on the range of LCO qualities that have been produced from FCC operations. The reader can see that, while some of the samples have much better diesel qualities than others, they all fall well short of modern specifications.

Strategies for maximizing diesel production. What can

be done to maximize FCC-based refinery diesel production while taking advantage of an existing FCC asset? The simple answer, depicted in FIG. 3, is to avoid the loss of virgin distillate to the FCC feedstock and to maximize the production of hydroprocessed LCO and diesel synthesized from the oligomerization of lower-boiling FCC olefins. The following sections of this article explore how this is accomplished.

TABLE 1. LCO quality vs. diesel specifications Property

Typical LCO

North American diesel

EU (Euro 5) diesel

10,000

≤ 15

≤ 10

Density, kg/m3

900–960

NA

820–845

Cetane number

20–30

≥ 40

≥ 51

Polynuclear aromatics (PNA), wt%

30–60

NA

≤ 11

Total aromatics, vol%

60–85

≤ 35

NA

T90 ≤ 345

T90 ≤ 338

T95 ≤ 360

Sulfur, wppm

D86 distillation, °C 35 30 Demand, million bpd

Global product trends favor increasing production of diesel over gasoline (FIG. 1).1 Consequently, many new refineries have utilized hydrocracking, rather than fluid catalytic cracking (FCC), as the main conversion unit due to the hydrocracker’s higher diesel yield and superior diesel quality.

For refineries that have already invested in an FCC unit as the main conversion vehicle, the question becomes, “How can existing refinery assets be used to economically increase diesel production?” The question is challenging because light cycle oil (LCO) from FCC operations has limited value as a component in modern diesel transportation fuel due to its aromatic, sulfurous character. Furthermore, quality virgin distillate included in the FCC feedstock is essentially destroyed during FCC processing.

This article presents methodologies for maximizing the production of high-quality diesel in a refinery that relies on FCC as its principal means of heavy oil conversion. Such methodologies include: • Preserving straight-run distillates for use in diesel blending by preventing its loss to FCC feed • Increasing yield, quality and recovery of LCO • Upgrading LCO quality through hydrotreating or hydrocracking • Preserving FCC naphtha octane and liquefied petroleum gas (LPG) during maximum LCO FCC operations • Producing synthetic diesel through the oligomerization of lighter olefinic FCC products.

25

World gasoline US gasoline World diesel US diesel

20 15 10 5 0 1990

1995

2000

2005

2010

2015

2020

2025

Year

FIG. 1. Projected gasoline and diesel demand to 2025.

Hydrocarbon Processing | SEPTEMBER 2012 39

Refining Developments

50 1967 1982

45

Cetane number

40 35 30 25 20 15

10

15

20 25 API gravity, degree

30

35

FIG. 2. Results from typical LCO inspections at US refineries.

High-severity FCC strategies Ä‘ĆŤ * .! /!ĆŤ.%/!.ĆŤ+10(!0ĆŤ0!),!. 01.! Ä‘ĆŤ !#!*!. 0+.ĆŤ$! 0ĆŤ.!)+2 ( Ä‘ĆŤ ! +00(!*! 'ĆŤ +'!ĆŤ 1.*%*#ĆŤ * ĆŤ

Remove SR diesel from FCC feed

Oligomerize FCC oleďŹ ns

Common FCC strategies Ä‘ĆŤ +3!.ĆŤ ĆŤ* ,$0$ ĆŤ!* ,+%*0 Ä‘ĆŤ * .! /!ĆŤ 0 (5/0ĆŤ) 0.%4ĆŤ 0%2%05 Ä‘ĆŤ ! 1 !ĆŤ 0 (5/0ĆŤ$5 .+#!*ĆŤ0. */"!.

Diesel Hydroprocess LCO

Low-severity FCC strategies Ä‘ĆŤ +3!.ĆŤ.%/!.ĆŤ+10(!0ĆŤ0!),!. 01.!ĆŤ * ĆŤ Ä‘ĆŤ * .! /!ĆŤ"!! ĆŤ0!),!. 01.! Ä‘ĆŤ ! 5 (!ĆŤ/(1..5ĆŤ+%(ĆŤ * ÄĽ+.ĆŤ Ä‘ĆŤ ),.+2!ĆŤ ÄĽ/(1..5ĆŤ". 0%+* 0%+*

FIG. 3. Strategies for FCC diesel maximization.

40 SEPTEMBER 2012 | HydrocarbonProcessing.com

background, the low-severity and high-severity routes to increasing refinery diesel production are contrasted.

Reducing FCC cracking severity. Low-severity FCC operation can be considered the traditional avenue for maximizing diesel production from an FCC-centered refinery. As mentioned in the introduction, the quality and the yield of LCO improves as cracking severity is lowered. At the same time, reducing cracking severity will generally cause a loss of both LPG production and FCC naphtha octane. It will also increase the production of low-value slurry oil. There are practical limits to the amount of LCO that can be produced by lowering reaction temperature and catalyst activity because the coke make will become insufficient to heat-balance the FCC unit at a sustainable regenerator temperature.

On the positive side, reducing FCC severity will not be constrained by regenerator coke burning or by vapor recovery unit (VRU) capacity. On the other hand, increasing LCO production increases the burden on other refining units to meet modern diesel fuel specifications by upgrading the LCO. Recycling slurry oil and using a fired feed furnace.

These operating strategies are commonly employed to increase LCO yield while directionally helping to maintain regenerator temperature. However, with severely hydroprocessed vacuum gas oil (VGO) feedstocks, recycling slurry oil and increasing feed temperature can still be insufficient to maintain adequate regenerator temperature.

Nontraditional tactics can be employed to address the yield, product quality and heat balance issues associated with low-severity FCC operations. Two of these tactics are described below: • Use of a dedicated slurry oil stripping tower to recover incremental LCO from the slurry oil produced by the FCC main fractionator and, optionally, to recycle some of the stripped slurry oil to the FCC reactor • Direct firing of the regenerator with fuel, such as fuel gas or slurry oil, to maintain regenerator temperature.

Slurry oil stripping tower. The fractionation between LCO and slurry oil in the bottom of an FCC main fractionator is very coarse because the reactor products feed the fractionator through the bottom of the tower, where the slurry oil product is withdrawn, and also because there are few fractionation trays between the slurry product and the LCO product draws. There is, at most, a one-stage flash available to separate the slurry oil from its equilibrium with the rest of the FCC reactor product stream. For example, FIG. 4 presents simulated true boiling point distillations from an FCC main fractionator producing LCO, heavy cycle oil (HCO) and slurry oil. In this example, 36% of the FCC slurry 1,100 1,000 900 800 700 600 500 Gasoline 400 300 200 65 70

True boiling point,°F

As suggested in FIG. 3, after a refiner has taken the steps necessary to minimize the loss of straight-run diesel to the FCC feedstock, some FCC operating adjustments are commonly applied in the interest of increasing refinery diesel production.

These include the following: • Lowering FCC naphtha endpoint • Increasing FCC catalyst matrix activity and lowering rare earth/hydrogen (H2 ) transfer activity • Maximizing LCO endpoint • Hydroprocessing the LCO as required.

Beyond these commonly applied strategies, two divergent options remain for dealing with the diesel situation: 1. Reduce FCC cracking severity to maximize LCO production, and take action, if needed, to mitigate the associated loss of FCC naphtha octane and LPG production 2. Increase FCC cracking severity to maximize the production of lower-molecular-weight olefinic products from the FCC unit, and oligomerize these olefins to produce high-quality synthetic diesel.

Can the FCC-based refinery increase diesel production? The answer to this question is “yes.� The more germane question to consider is whether or not the increased diesel production justifies the associated investment costs and operating tradeoffs.

Data generated on an FCC pilot plant are presented in TABLE 2 to show how changing the FCC reaction severity can impact FCC yields and product qualities. Three cases are included, all based on the same feedstock and catalyst system. With this as

Slurry

LCO

75 80 85 90 Cumulative FCC product distillation, vol%

FIG. 4. FCC product distillation example.

HCO

95

100

Refining Developments oil and 50% of the HCO boils below the LCO product endpoint.

It is ironic that, in maximum LCO operations, the amount of LCO lost in the slurry oil increases significantly because of the higher volume of slurry oil produced. Another fundamental violation of the maximizing LCO objective is that the recycle of a typical slurry oil also carries LCO-boiling-range material back into the reactor, where the quality will be further degraded and some will be cracked into a non-LCO-boiling-range material.

Based on the above considerations, it is apparent that, to truly maximize the production of LCO from the FCC unit, a sharp fractionation between LCO and heavier liquid products must be achieved. A feature used to enhance this separation is the use of a dedicated LCO/slurry fractionation tower to recover LCO that would otherwise be lost in the slurry oil. In a traditional maximum-gasoline FCC operation, downstream recovery of LCO from slurry is not normally economic because

of the relatively low slurry oil yield. However, in a maximumLCO operation where the slurry production is higher and the LCO is more valuable, the additional fractionation tower may be economically viable.

The LCO/slurry fractionation tower can be a steam stripper or a tower operated under vacuum to achieve maximum LCO recovery. In addition to the prevention of the direct loss of LCO with the slurry product and the loss of LCO through its recycle to the reactor, the slurry oil fractionation tower provides a slurry oil that is a more effective recycle stream for supporting the FCC heat balance, due to its higher boiling range and higher Conradson Carbon Residue (CCR) content.

HCO recycle. In low-severity FCC operations where maintaining adequate regenerator temperature is not an issue (such as may be the case when processing residue), HCO may be preferred over slurry oil as a recycle stream, due to its

TABLE 2. FCC pilot plant data showing the impact of changing operating severity Low conversion

Medium conversion

High conversion

Gravity, °API

22.5

22.5

22.5

50 vol% boiling point, °F

851

851

851

Aniline point, °F

176

176

176

FCC feed properties

Sulfur, wt%

0.55

0.55

0.55

CCR, wt%

0.89

0.89

0.89

Riser temperature, °F

940

979

1,020

Feed temperature, °F

416

485

337

Catalyst-to-oil ratio, wt/wt

6.6

6.7

11.4

Micro Activity Test (MAT)

67

67

67

Rare-earth oxides, wt% (FCC E-Cat property)

0.6

0.6

0.6

1.23

2.08

3.5

C3 LPG, wt%

2.97

4.26

7.27

C4 LPG, wt%

5.98

7.88

11.57

Gasoline (C5 at 430°F), wt%

43.21

46.98

46

LCO (430°F–680°F), wt%

27.42

24.47

16.01

Slurry oil (680°F+), wt%

13.6

9.06

7.66

FCC pilot plant operating conditions

FCC pilot plant yields Dry gas, wt%

Coke, wt%

5.59

5.27

7.99

Conversion, wt%

58.98

66.47

76.33

C3 LPG olefinicity, wt%

83.8

83.8

85.7

C4 LPG olefinicity, wt%

66.7

68.5

67

FCC pilot plant product qualities

Naphtha gravity, °API Naphtha octane, RON/MON Naphtha P/O/N/A, wt%

56.6

57.2

55.9

91.7/81.1

92.9/81.6

95.6/84.4

27.2/49.5/11.8/11.5

25.7/49.1/10.9/14.3

31.3/36.8/10.5/21.4

LCO gravity, °API

22.2

17

11.3

LCO H2 content, wt%

10.7

9.9

8.8

Slurry oil gravity, °API

6

–0.8

–7.4

Slurry oil H2 content, wt%

9

7.8

6.7 Hydrocarbon Processing | SEPTEMBER 2012 41

Refining Developments very low carbon residue content and higher H2 content.4 Ideally, the HCO would also have its LCO-boiling-range material distilled before recycling it, but the economic practicality of redistilling the HCO can be questioned if this requires yet another cycle oil fractionator.

Direct firing of regenerator with fuel. The continuous direct firing of the regenerator with fuel can be essential to the operation of a maximum LCO FCC operation when processing non-residue-containing FCC feedstocks.

Continuous firing of the regenerator air heater has been utilized for heat balance support, but this practice can have an adverse impact on the velocities through the regenerator air distributors and on the practical issues associated with monitoring the heater firing.

Continuous firing of torch oil, which is normally only used during startup, has been practiced. However, this has reportedly been the cause of accelerated catalyst attrition and deactivation.

True boiling point, °F

1,100 1,000 900 800 700 600 500 400 300 200 100 40

Gasoline or LCO Gasoline 50

LCO

60 70 80 Cumulative FCC product distillation, vol%

90

100

FIG. 5. FCC liquid product distribution example.

97

95

RON

93

Octane number

91

89 85

83

MON

81

79 77

0

20

60

100 140 Gasoline final boiling point, °C

FIG. 6. FCC gasoline octane examples.

42 SEPTEMBER 2012 | HydrocarbonProcessing.com

180

220

240

One company has developed a system for distributing liquid fuel in the regenerator.5,6 The system is designed to mitigate the catalyst damage associated with conventional torch-oil firing. This technology has been adapted for use in conventional FCC units.

A patent-pending version is also available for use in conventional FCC operations. In addition to this system for liquid fuels, a system for firing the regenerator with fuel gas, which is often a lower-cost fuel, has been commercialized.

Increasing FCC cracking severity. Increasing cracking sever-

ity reduces LCO yield and provides the immediate impact of having less LCO to blend into the diesel pool. This can be a net benefit to the diesel blending operation, even though the quality of the LCO is diminished. At the same time, the increased LPG olefins can be oligomerized to produce high-quality synthetic diesel.

Increasing cracking severity can be achieved by raising reactor temperature and/or boosting catalyst activity. However, unless FCC capacity is reduced, increasing FCC severity may be constrained by regenerator coke burning or by VRU capacity. Even with adequate coke- and gas-handling capacity, increasing regenerator temperature can pose a limitation to the severity increase.

The use of slurry recycle in high-conversion FCC operations is usually counter-productive because it only exacerbates the coke-burning and regenerator-temperature limitations.

Furthermore, referring back to TABLE 2, the slurry oil from high-conversion FCC operations is H2-deficient and has little to offer in terms of potential cracking yield. Beyond simply increasing reaction temperature and catalyst activity, these three hardware-related upgrades warrant mention for their assistance in high-conversion FCC operations: • Applying an advanced riser termination system to minimize dry gas and coke production at the increased severity • Applying regenerator catalyst cooling to control the heat balance at the increased severity • Recycling FCC C4s and FCC light naphtha to an ultrahigh-severity FCC riser for the purpose of producing incremental C3/C4 olefins and aromatic, high-octane naphtha.

These options are further discussed below.

Riser termination system. An advanced riser termination system can minimize product vapor residence time between the riser outlet and the main fractionator, thereby reducing the formation of incremental dry gas from post-riser thermal cracking. In addition to the reduction in dry gas, the riser termination system reduces delta coke on units that previously employed low-catalyst-separation-efficiency riser termination devices.

Therefore, the system is especially appropriate for use when increasing FCC operating severity because it simultaneously relieves VRU capacity and regenerator operating temperature constraints. The advanced riser termination system also increases LCO production by minimizing the thermal condensation reactions that create slurry oil from LCO-range material.7 Catalyst cooling. In an unconstrained environment, increasing FCC reactor temperature is easy. However, in most cases, FCC units are already operating against several physical and economical constraints. High regenerator temperature can emerge as a major constraint to increasing reactor temperature because of the impact of the higher temperature on the unit heat balance.

FCC operators can implement a reduction in equilibrium catalyst activity to mitigate the increasing regenerator temperature,

Refining Developments but reducing catalyst activity runs counter to the more basic objective of increasing reaction severity. In high-severity FCC operations, the catalyst cooler can maintain the regenerator temperature at the optimum value, which increases olefins production. In a recent study, the addition of a catalyst cooler to a regenerator-temperature-constrained, high-olefins FCC operation enabled a 25+% increase in the unit’s propylene production.8 C4 and light FCC naphtha recycle. The recycle of C4 LPG and light FCC naphtha for the purpose of producing propylene and higher-octane FCC gasoline fits in well here because it can achieve the goals of increasing propylene yield and naphtha octane without destroying LCO. Ultimately, the application of such catalyst and hardware technology can push propylene yields into a range of 10 wt% to 20 wt% or more.6 The recycle of light naphtha to a high-severity second riser can be practiced in both high-severity and low-severity primary riser operations to improve octane and produce additional LPG olefins without sacrificing LCO yield or quality. There is a synergy between the low-severity primary riser operation and a highseverity light feed recycle riser because the naphtha from the low-severity primary riser is more olefinic, making this primary riser product better feedstock for the high-severity second riser.

Commonalities in basic process strategy. Even as the chosen strategy drives the refinery down a selected avenue of either a high- or low-conversion FCC operation, there will be some commonalities among the two strategies.

FCC fractionator cutpoint adjustment. Adjusting the FCC naphtha endpoint would be considered standard practice in most refineries for making seasonal adjustments for swings in gasoline vs. distillate demand. Reducing the endpoint of the FCC naphtha product shifts heavy naphtha into the LCO product. The limitation to the adjustment can be gasoline octane, the flashpoint specification of the LCO product, or poolcetane considerations. Another possible limitation is the minimum FCC main fractionator overhead temperature, which can be practiced without condensing water and fouling or corroding the top of the main fractionator or its overhead system.9 Typically, the FCC naphtha ASTM D86 endpoint would not be reduced to less than 300°F to stay above a minimum acceptable main fractionator overhead temperature.

FIG. 5 provides a typical example of how changes in the gasoline endpoint impact the naphtha yield and the LCO yield by implication. In addition to changes in the FCC naphtha and LCO yields due to the cutpoint adjustments, there will be changes in the product distillations, gravities, octanes, sulfur contents and cetane values.

Due to the wide variation in heavy FCC naphtha molecular composition from one FCC operation to the next, a rule of thumb is not provided for the impact of the cutpoint adjustments on octane, sulfur content or cetane. These effects are best taken from empirical observations on the operating unit.

As an example of the variability of product property trends with cutpoint, FIG. 6 shows the impact of the FCC gasoline

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Refining Developments endpoint on octane, calculated from narrow-boiling-range octane data for three different FCC situations operating with a variety of feedstocks, catalysts and operating conditions.10 In many cases, seasonal demand swings are accommodated with changes in the FCC gasoline cutpoint, with no change to the true (430°F) FCC conversion level, as this strategy works to preserve the LPG production, octane and total liquid volume associated with the higher-conversion operations.

Crude distillation. Another common practice is maximizing diesel production from the crude distillation processes so that losses of potential diesel to the FCC feed are minimized.

There are intermediate swing cuts from some crude distillation operations that can be routed to the FCC unit when gasoline is demanded, and routed to diesel production when the objec-

tive is maximizing diesel. As a side benefit, keeping the diesel out of the FCC feed also improves FCC gasoline octane.11 Pilot plant data have shown that, in moderate or high-severity FCC operations, most of the straight-run diesel will be converted to gasoline and lighter products with only 20%–30% leaving the FCC in the LCO product. The data have also shown that the LCO made from the distillate will have cetane values 10 to 15 numbers below that of the distillate feed, but still higher than that of typical FCC LCO. Beyond standard operating adjustments, there may be investment opportunities in crude distillation hardware that can achieve a sharper separation between the diesel product and FCC feed streams, reducing the loss of potential diesel to the FCC feed.

A survey of over 100 refineries indicated that FCC feed typi-

TABLE 3. Examples of calculated incremental diesel production Base case

Additional diesel recovery options

Atmospheric tower revamp

Add standard Add high-recovery Install gas oil tower diesel draw to VDU diesel draw to VDU in front of VDU

Install vacuum preflash tower in front of VDU

Install LVGO splitter tower

Incremental diesel, vol% of crude

1.3

3.0*

3.2*

2.2*

2.3*

3.4*

Number of additional fractionation stages between diesel and gasoil

5

2

6

4

4

12

*Incremental yield of selected option relative to base case

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Refining Developments cally contains between 10 vol% and 15 vol% of material, mostly diesel, boiling below 650°F.12 In environments where gasoline production is maximized, the loss of diesel to the FCC unit has little negative impact. However, if the objective is diesel maximization, better crude fractionation efficiency between diesel and FCC feed can be economically justified.

There are a number of ways to reduce the loss of virgin diesel to the FCC feed.13 Some of these options are listed below: • Revamp the atmospheric distillation column to increase the degree of fractionation between the diesel and atmospheric gasoil products • Revamp the vacuum column to produce a diesel product • Add a gasoil tower or a vacuum preflash tower between the atmospheric and vacuum distillation columns, and recover diesel from the vacuum tower feedstock • Add a splitter column to process the light vacuum gasoil (LGVO) and produce a diesel stream.

TABLE 3 shows examples of calculated incremental diesel production that were reported for some of these options.13 The best options for a given refinery are a function of the site specifics of the application, but the data in TABLE 3 indicate the magnitude of diesel production increases that are possible.

Part 2 of this article, to be published in October, will explore the selection of FCC catalysts, methods for hydroprocessing LCO, and the production of diesel fuel from FCC byproducts, among other topics.

LITERATURE CITED Eskew, B., “The Diesel Challenge and Other Issues Facing US Refiners,” NPRA Q&A and Technology Forum, Champions Gate, Florida, October 2008.

2 Flinn, N. and S. P. Torrisi Jr., “LCO Upgrading Options: From Simple to Progressive Solutions,” Russia and CIS Refining Technology Conference and Exhibition, Moscow, Russia, September 2008.

3 Unzelman, G. H., “Potential Impact of Cracking on Diesel Fuel Quality,” Katalistiks Fourth Annual Fluid Cat Cracking Symposium, Amsterdam, The Netherlands, May 1983.

4 Hunt, D., R. Hu, H. Ma, L. Langan and W.-C. Cheng, “Recycle Strategies and MIDAS-300® for Maximizing FCC Light Cycle Oil,” Catalagram 105, W. R. Grace & Co., Spring 2009.

5 Peterson, R. B., C. Santner and M. Tallman, US Patent No. 7,153,479.

6 Gilbert, M. F., M. J. Tallman, W. C. Petterson and P. K. Niccum, “Light Olefin Production from SUPERFLEXSM and MAXOFINTM FCC Technologies,” ARTC Petrochemical Conference, Malaysia, February 2001.

7 Miller, R., T. Johnson, C. Santner, A. Avidan and D. Johnson, “FCC Reactor Product-Catalyst Separation—Ten Years of Commercial Experience with Closed Cyclones,” NPRA Annual Meeting, San Francisco, California, March 1995.

8 Pillai, R. and P. K. Niccum, “FCC Catalyst Coolers Open Window to Increased Propylene,” Grace Davison FCC Conference, Munich, Germany, September 2011.

9 Melin, M., C. Baillie and G. McElhiney, “Salt Deposition in FCC Gas Concentration Units,” Catalagram 107, W. R. Grace & Co., 2010.

10 Akbar, M., B. Claverin, M. Borley and H. Otto, “Some Experiences with FCC Octane Enhancement,” Ketjen Catalysts Symposium, Scheveningen, The Netherlands, May 1986.

11 Fletcher, R., Meeting Transcript, 1997 NPRA Q&A Session: Refining and Petrochemical Technology, New Orleans, Louisiana, October 1997.

12 Sloley, A. W., “FCC Network News,” Refinery Process Services Inc., Vol. 35, January 2010.

13 Sloley, A. W., “Increase diesel recovery,” Hydrocarbon Processing, June 2008.

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Special Report

Refining Developments P.-Y. LE-GOFF, Axens, Rueil-Malmaison, France; J. LOPEZ, Axens, Salindres, France; and J. ROSS, Axens, Princeton, New Jersey

Redefining reforming catalyst performance: High selectivity and stability Over the next 10 years, global demand for oil products is forecast to increase at an average rate of 1.2%/yr through 2020.

Demand will be just below 100 million barrels per day of oil equivalent (MMbdoe). However, this growth will not be distributed evenly around the world.

Developed markets. In the Organization for Economic Co-

operation and Development (OECD) countries, reductions in automobile fuel consumption will decrease oil demand at about 0.5%/yr, thus creating refining overcapacity. The situation is completely different in nations with growing economies where the gross domestic product (GDP) is increasing rapidly and the population aspires to greater mobility. In these (non-OECD) countries, demand for oil products will rise at 2%/yr and will comprise 53% of world demand by 2020.

Developing markets. Concerning gasoline demand over the next 10 years, strong growth is mainly expected in Asia (+2.1 MMbdoe), the Middle East (+0.3 MMbdoe), the Former Soviet Union States (+0.37 MMbdoe) and Latin America (+0.6 MMbdoe), as shown in FIG. 1. In these regions of developing and growing economies, continued strong growth is projected for both gasoline and petrochemical polymers.

Petrochemicals. Worldwide demand for polymers is growing at a significantly higher pace than oil and gas production (FIG. 2) and thus initiating large expansions in olefins and aromatics complexes. Global paraxylene (PX) consumption is forecast to exceed 40 million tons (MMton) by 2015 compared to 32 MMton in 2011. The additional capacity will be located in the Asia-Pacific region, where PX demand is the highest, followed by the Middle East. New aromatic complexes, which include continuous catalyst regeneration (CCR) reforming units, will be required to meet the growing demand in polyester used for bottles and textiles. To meet both aromatics and gasoline demand, capacity additions for light-oil processing are expected in these

regions at about 1.5 MMbpd in combined reforming, isomerization and alkylation capacity by 2020.

Catalytic reforming of naphtha is central in the production of both high-octane fuel and aromatics to support both rapidly growing markets. Accordingly, there is a continued strong demand for catalytic reforming units and improved catalysts for new and existing units with a global installed capacity over 13 MMbpd. The present annual worldwide market for reforming catalyst represents several thousand metric tons for fixed bed, cyclic and CCR markets.

CATALYTIC REFORMING FUNDAMENTALS The role of catalytic reforming is fundamental in transforming low-octane naphtha from crude oil and hydroprocessing units into high-octane transportation fuels and aromatics. The process involves transforming or reforming the paraffinic and naphthenic molecules in the feed into high-octane aromatics and branched components, and coproducing hydrogen needed by other refinery units such as hydrotreaters and hydrocrackers. This is accomplished over a heterogeneous catalyst at elevated temperature and preferably low pressure according to Le Chatelier’s principle.

0.8 0.6 0.4 0.2 0.0 -0.2 -0.4 -0.6

0.4 0.2 0.0 -0.2 -0.4 -0.6

-0.6 0.3 0.0

Latin America

FSU 2.0

1.6 1.2 0.8 0.4 0.0

Europe 0.6 0.2 -0.2

North America Fuel oil Distillate = Diesel + Kerosine/jet Gasoline Naphtha

0.4 0.2 0.0

0.8 0.4 0.0 -0.6

Middle East

0.6 0.2 -0.2

China

0.4 0.0 -0.4

India

Japan

0.8 0.4 0.0

Other Asia Pacific Africa

Global demand 2010 2020

MMbdoe 88.2 99.8

Unit: MMbdoe Source: Axens estimates

FIG. 1. Worldwide incremental refinery product demand, 2010–2020.

Hydrocarbon Processing | SEPTEMBER 2012 47

Refining Developments Structure. Reforming catalysts are complex composites of a

Catalyst performance. The carrier and highly dispersed Pt

highly active precious metal, platinum (Pt), to efficiently perform dehydrogenation and hydrogenation reactions, and an active support or carrier to do complementary reactions. The carrier is a high-purity alumina, with a specific pore structure, designed to have an acid functionality, which can be moderated by controlling the amount of chloride added to the support and/or by the addition of promoters. Together, these “metal” and “acid” components, as shown schematically in FIG. 3, form a dual-function catalytic system capable of transforming lowoctane paraffins and naphthenes into high-octane gasoline, aromatics and byproduct hydrogen.

metal interact in a complex way to accomplish the desired reforming reactions. Performance of the catalyst is described in terms of activity, selectivity and stability.

Activity is commonly defined in terms of temperature required to achieve a given objective; it is very similar to the definition used to describe hydrotreating catalysts. A more active catalyst is able to achieve the same product yield or severity (gasoline octane or aromatics yield) at a lower reactor temperature. For fixed-bed units, this means longer cycle lengths, and, for CCR units, it means greater operating flexibility within unit constraints.

Selectivity. The selectivity of the catalyst refers to the relative yield of desired product, such as C5+ reformate gasoline or aromatics, compared to another catalyst operating with the same severity target (RONc) under similar process parameters (pressure, WHSV, H2 /HC). As with most reaction systems, high selectivity is desired, as long as the performance can be maintained.

Stability is a measure of how long a desired performance can be maintained, and it usually reflects the coking tendency of the catalyst as it affects both activity and selectivity. Higher stability in a fixed-bed catalyst translates into a longer cycle length while meeting process severity targets—i.e., more profitable onstream time. For reforming units equipped with CCR, higher stability means lower coking tendencies and slower regeneration cycles, thereby adding operational flexibility. Such operating flexibility provides opportunities to process more demanding feed, such as higher endpoint feed or increased amounts of coker naphtha, or an increased catalyst life resulting from a reduced regeneration frequency. Higher catalyst stability can also allow reducing the recycle gas requirement, thus lowering operating costs.

Carrier. The carrier formulation and method of metal impregnation have a significant impact on the activity, selectivity and stability of reforming catalysts. But this is only the beginning of catalyst design and production technique.

Functions. A simplistic representation of the main reactions is shown in FIG. 4 and is linked to the metallic and acid functions. The important dehydrogenation reaction to convert a cyclohexane component into an aromatic is very rapid and easily accomplished by the metal function of the catalyst.

For many feeds, in particular hydrocracker and coker derived naphthas, a significant portion of the naphthenic compounds contain cyclopentane elements that require the acid-catalyzed reaction of ring extension or conversion into a cyclohexanebearing component for subsequent dehydrogenation on the metallic sites. Ring extension and dehydrocyclization of paraffins are all difficult, but they are critical functions that require highly selective catalyst. If the acid and metal functions are not tuned or properly balanced, undesirable side reactions do occur, leading mainly to acid cracking and hydrogenolysis, and, to a lesser extent, dealkylation. In the reforming unit, these side reactions result in the formation of light petroleum gas (LPG), light gas and coke; all contribute to nonselective conversion, catalyst deactivation by coke deposition, and lightends handling limitations.

900

700 600 Growth Index

Polymer demand

Average growth rate 1990-05

800

GDP

5.6%

500 400 300

3.2%

200

Gas production 2.1%

100

Oil production

1.5%

0 1980

1990

2000

2010

2020

PROMOTERS AND ENHANCED PERFORMANCE In addition to the essential alumina carrier and Pt metal, other elements known as promoters are introduced to influence, moderate or otherwise change the catalyst activity, selectivity and stability. When combined effectively, the catalyst system allows the refinery to optimize gasoline yield and cyclelength or regeneration frequency to improve profitability and operability within unit constraints.

Metallic

Acid (Cl-Al Carrier)

Dehydrocyclization

Paraffin and naphthene isomerization H+

Pt

2030

FIG. 2. Worldwide growth index in oil, gas and polymer sectors.

HC M

Cl Al

Al-Cl Acid site (Cl-Alumina) M Metal site (ex. Pt) HC Hydrocarbon interactions

Carrier

FIG. 3. Schematic of acid and metal sites on reforming catalyst.

48 SEPTEMBER 2012 | HydrocarbonProcessing.com

Pt

+ H2

H+

+ 3H2

Hydrogenolysis/ring opening Pt + H2 CH4 + Pt

Hydrocracking/dealkylation H+

+

H+

+

Coke formation–complex mechanisms

FIG. 4. Bi-functional reforming catalyst reactions. The desired reactions are labeled in blue, with undesirable side-reactions labeled in red.

Refining Developments

Metallic and acid functions. The interaction between the metallic and acid functions is complex, and optimizing the relative importance of each function is fundamental to obtain the desired balance of selectivity, activity and stability. With the addition of other promoters, the permutations of interactions increases, and the relative affinity of molecules to either the metal or acid sites can be tuned for the desired effect, as in the case of Pt-Re. FIG. 6 is a catalyst system with multiple metals and varying chloride content.

Identification of promising promoter combinations requires extensive laboratory work and pilot testing. The exact formulation, impregnation method and manufacture are highly proprietary. Ultimately, the active site density and location are critical to achieving both the desired metal and acid functions. Moderating the acid site strength on the carrier is one important way to limit cracking reactions, but this is only possible if uniform deposition of the promoter(s) is achieved.

Equally important is the production trials where proprietary techniques are applied to produce commercial product meeting both the target process chemistry and particle mechanical properties. Detailed particle analysis is performed to ensure that the manufacturing method is effective, as shown in FIG. 7.

Uniform distribution of the carrier and metallic components is important to ensure accessibility to these precious constituents and proper function. When the promoter is mainly on the shell of the particle, the metal-to-acid function ratio is not constant along the diameter. Thus, hydrocarbons diffusing into the particle encounter a higher acid-to-metal ratio leading to undesired cracking reactions. This reduces the intrinsic catalyst selectivity and increases coke make. Moreover, when the promoter is preferentially on the surface, it is more sensitive to contamination, and its elution increases over time.

When the promoters are properly introduced, they remain effective for the service life of the catalyst, even under harsh operating conditions found in cyclic and CCR units. Earlier work on promoted systems demonstrates that the promoters are robust and do not elute from the catalyst over many regeneration cycles. FIG. 8 demonstrates excellent promoter retention, within the analytical accuracy of the test, for various CCR catalysts.

BREAKING THE SELECTIVITY-STABILITY BARRIER When targeting specific catalyst performance, there are many choices of promoters, method of impregnation and design of the carrier. Two fundamentally different catalyst lines using unique design approaches were recently compared leading to a new family of catalysts that break the selectivity-stability barrier commonly encountered in catalyst design.

D

-0.5

High

Cl Pt X Y Z

Relative conc.

In fixed-bed reformers, promoters have been used for a long time to increase the stability (onstream time) of the catalyst by moderating the coke formation rate. Platinum-Rhenium (Pt-Re) catalysts allow for longer cycles or more severe operation at thermodynamically favored lower pressure where the coking tendency is greater. Additional promoters are often added to fine-tune the selectivity and stability of the catalyst. There are trade-offs in performance and response to feed contaminants, such as sulfur, with these promoted catalyst systems. The challenge in catalyst development is to prepare the right catalyst formulation to achieve the best performance with the least degree of compromise. Traditionally, this results in trading selectivity and introduces a selectivity-stability barrier, as shown in FIG. 5.

-0.4

-0.3

-0.2

-0.1

0.0 0.1 Position, R/D

0.2

0.3

0.4

0.5

FIG. 7. CCR catalyst particle composition profile.

Selectivity

Desired region 120

Low Low

High Activity; stability

FIG. 5. Selectivity – stability trade-off or barrier.

Cl X Al

Pt Z Y

Cl Al

Carrier

Al Alumina carrier Cl Chlorine Pt Platinum metal X,Y,Z Promoters

FIG. 6. Schematic of complex multi-promoted catalyst system.

Promoter retention, %

110 100 90 80 70 60 50

0

100

200

300 400 Days onstream

500

600

700

FIG. 8. Commercial demonstration of promoter retention on CCR reformer catalysts.

Hydrocarbon Processing | SEPTEMBER 2012 49

Refining Developments 90

A Temperature, °C

C5+, wt %

88

Pt+Sn Tri-metallic 1 Tri-metallic 2 Quad-metallic 0

Pt+Sn Tri-metallic 1 Tri-metallic 2 Quad-metallic

505

89

87

Time

510

500

B

Coke 7 wt % Coke 6.5 wt %

495

Coke 6 wt %

490

20

40

60

Time

80

100

120

140

485

0

20

40

60

Time

80

100

120

140

FIG. 9A. Reformate yield vs. promoter system, and 9B. Stability and coke yield vs. promoter system.

89.6

A

Tri-metallic

Quad-metallic

89.2 C5+

88.8

88.4 88.0

50 3.20

75

100

B

125 Tri-metallic

3.15

150 Quad-metallic

H2

3.10 3.05 3.00 2.95 2.90 50 520

75

100

125

150

C

WABT, °C

510 500 490 480 50

Tri-metallic 75

100 Time

125

Quad-metallic 150

FIG. 10. Optimized quad-metallic catalysts comparison: A) reformate yield, B) hydrogen yield, and C) activity/stability.

At the macroscopic level, the two lines of catalyst produced similar results, but at the micro level, one exhibited better carrier production technique and the other better promoter characteristics. There were clearly opportunities to optimize the systems at the micro level to provide better performance. The first products to be explored were the CCR catalysts as used in severe, high-profit-margin aromatics units.

CCR catalyst formulations are built around a platinum-tin (Pt-Sn) base system. This provides significantly greater selec50 SEPTEMBER 2012 | HydrocarbonProcessing.com

tivity over Pt-only catalyst, but requires low pressure for best results and continuous regeneration to overcome the greater coke formation tendency. Additional metals, other than Pt and Sn, can be added as promoters to further optimize the catalyst systems. The importance of promoter selection can be demonstrated in FIG. 9.

Pilot-plant testing results are shown in FIG. 9A of the C5+ reformate yield selectivity over time for four catalyst systems: Pt+Sn (bimetallic), tri-metallic 1, tri-metallic 2 and optimized Quad-metallic. In this batch pilot testing strategy, the unit is operated at a constant RON target to reflect either a constant conversion toward aromatics for aromatics application or a constant octane in the case of gasoline application. As the test progresses, catalyst selectivity is measured by the reformate yield and stability by the rate of reformate-yield decay over time as the fixed batch of catalyst age.

During the test, coke is progressively deposited on the catalyst and the required temperature to maintain the target RON increases (FIG. 9B). Low coke formation and catalyst deactivation is indicated by a slow increase in reactor temperature to maintain the target RON. A small slope of the temperature curve indicates high catalyst stability, while the duration of the C5+ plateau and the slow rate of yield decay is the complementary indicator of the C5+ stability of the catalyst. From a commercial unit perspective, the latter part of the test, where temperature increases sharply to maintain severity, defines the ultimate catalyst stability (cycle life) within unit constraints.

Looking more closely at FIG. 9, the two tri-metallic systems show initial selectivity performance higher than the base PtSn, but the performance falls over time as a result of the lower stability (higher coke yield), shown in FIG. 9B, for these systems. When a fourth metal is properly introduced, the quad metallic or simply Quad system, a superior yield selectivity and equal stability is attained relative to the Pt-Sn system. In this case, the selectivity-stability barrier is broken, and stability does not suffer to attain superior selectivity. Significantly, this improvement was obtained while reducing the Pt loading on the catalyst by 20%, thereby offering a substantial cost reduction for our customers.

When the optimized carrier and promoter system were applied to the low-density CCR catalyst platform, a new Quad catalyst was developed. FIG. 10 shows the performance of this new system. The reformate yield is increased by 0.8 wt%; hydrogen increased by 0.1 wt% (50 scf/bbl), while the activity and stability are slightly improved.

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Refining Developments ENHANCED PHYSICAL PROPERTIES CCR moving bed catalysts also require careful attention to the physical properties to ensure mechanical strength and surface-area stability over many regeneration cycles, which is indicative of catalyst life and chlorine retention.

Accelerated aging tests have been performed on the new Quad-metallic catalyst to compare surface area retention to conventional Pt-Sn bimetallic catalyst. FIG. 11 shows the surface area decline over time following such test protocols. A conventional Pt/Sn catalyst reaches its end-of-life surface area (approximately 140 m2/g) relatively quickly, whereas the new Quad catalyst 220 Bi-metallic Quad-metallic Specific surface area, m2/g

200 180

Quad

160 ≈ 20 m2/g

Bi-metallic 140 120

0

100

200 Time

300

400

FIG. 11. Catalyst surface area aging test, quad metallic vs. bimetallic Pt-Sn.

retains a higher surface area in the range of 160 m2/g. Higher surface area is associated with improved regeneration (Pt redispersion) and better chloride (C1) retention. As a consequence, the new Quad catalysts will exhibit longer life, reduced salt deposit in downstream units, and lower chloride content in the hydrogen-rich gas, resulting in longer chloride trap life.

Put in quantitative terms, the better surface area retention and intrinsically higher chloride retention resulting from a new quad catalyst with a proprietary promoter system results in 30% lower chloride injection over the life of the catalyst vs. standard Pt/Sn. The mechanical properties of the catalyst are also important in CCR applications. Unlike fixed-bed catalysts, which are mainly concerned about crush strength to endure the static load forces within a fixed bed, CCR catalysts are spherical and designed to resist the dynamic forces from slow movement in the catalyst beds to pneumatic lifting between reactor and regenerator. These forces lead to particle attrition and fines production. Although the fines or broken pieces of the catalyst are captured within the system, they can lead to fouling of screens and increase pressure drop.

Highly developed CCR catalysts are more robust to ensure extended service over 7–9 years. New formulations are subjected to large-scale circulating test units to accurately represent commercial conditions and the forces leading to attrition. The new carrier and multi-promoted catalyst systems have proven to be as robust as previous-generation catalysts with an excellent track record of low particle attrition.

NOTES As a licensor of catalytic reforming and aromatics chain technologies, and supplier of catalysts for these units, Axens is focused on continuous improvement in both process technology and catalyst development. The recent acquisition of the Criterion catalytic reforming catalyst business in 2011, including production facilities and know-how, provided a unique opportunity to compare, contrast and build upon two different approaches to reforming catalyst development and production. New proprietary formulations and production techniques have emerged from this union resulting in breakthrough catalysts for both fixed-bed and movingbed CCR units that provide superior selectivity without compromising activity and stability. Re-engineered fixed-bed catalysts are under development and on-track for release in 2013. These new products promise the benefits of higher selectivity and reduced cost through promoter selection and loading optimization.

PIERRE-YVES LE GOFF is Axens’ senior technical manager for reforming catalysts and project leader for catalyst development.

Dr. Le Goff started his career as a research engineer at Rhodia, where he specialized in catalyst support design and process development. Dr. Le Goff holds an engineering degree from the École de Chimie de Mulhouse, an MBA from Université de la Sorbonne in Paris, and a PhD from Université de Haute-Alsace.

JAY ROSS is a senior technology and marketing manager for Axens covering the field of transportation fuels including FCC, catalytic reforming, isomerization and biodiesel production. He has over 30 years of experience in the refining and petrochemical industry including process engineering design, R&D, licensing and technical assistance. Mr. Ross is a graduate from Princeton University with a degree in chemical engineering.

JOSEPH LOPEZ is a development and industrialization engineer in Axens’ production plant of adsorbents and catalysts in Salindres, France. He is responsible for the development and scale-up of reforming supports and catalysts. He started his professional career as a research engineer at Rhodia working mainly in the field of heterogeneous and homogeneous catalysis. Dr. Lopez holds an engineering degree from the Ecole Nationale Supérieure de Chimie de Montpellier and a PhD in catalysis from the Université Claude Bernard of Lyon.

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Special Report

Refining Developments C. A. CABRERA and M. A. SILVERMAN, Ivanhoe Energy, Calgary, Alberta, Canada

Upgrade heavy oil more cost-efficiently

BACKGROUND Demand for refined crude oil products continues to be strained by the large and continually growing demand from developing economies, particularly from economic growth in Asia Pacific nations. Although forecasts vary widely, there is a new optimism over recent hydrocarbon resource discoveries in North America (mainly in the US) and South America (Brazil). However, the price of crude oil will continue to be most influenced by the world’s largest producers that have spare capacity. To alleviate high prices due to ever increasing demand, new sources of petroleum supplies will be required.

A largely untapped source of heavy crudes can be used to significantly augment supply. As shown in FIG. 1, there are substantial reserves of heavy oil, up to 2 trillion barrels, which constitutes nearly half of the remaining recoverable crude oil supply.1 Advanced technologies deployed across all phases of the supply chain will be needed to improve the economics and feasibility of producing and refining heavier crude oils. A novel technology has been proven to economically uplift the value of heavier crudes in the field. The uplift, or incremental margin captured per barrel of crude processed, is dependent on the quality of the heavy crude upgraded and ranges from $19/bbl to $32/bbl.

UPGRADING HEAVIER CRUDE OILS— BREAKING THE PARADIGM Historically, the petroleum industry supply chain has been divided into three discrete sectors: production, transportation and refining. Typically, crude is produced and made ready for transportation by production operations, and it is transported via pipeline or ship, train or truck to more sophisticated and complex refineries. Once at the refiner, the crude oil is refined into transportation fuels and other high-value finished products. The downstream sector of the hydrocarbon industry continues to optimize processing schemes to take advantage of the

lowest-cost crude oil, of which a significant portion of the “opportunity crudes” are heavy oils.

Production of heavier crudes strains the present supply chain.

These crudes include those found in the Canadian oil sands, the Orinoco Belt in Venezuela, Mexico, the Middle East, Africa, and other locations. The API of such crudes ranges from 6° API to 16° API, and the resources can be located onshore or offshore.

Production. Supply-chain constraints include the need to heat the heavy oils in situ (underground) to reduce the viscosity so 5.0 Conventional Heavy 4.0

3.0

Oil supply, trillion bbl

Heavy petroleum resources are becoming significantly more important as the availability of light, sweet crude oil continues to decline (FIG. 1). Heavy-oil resources are difficult to extract, transport and refine. Producers are focused on heavy-oil regions around the world, such as Venezuela, the Amazon basin and Canada’s oil sands. A new technology can be used in the field to economically upgrade and significantly improve the properties of heavy oil by reducing viscosity, increasing gravity and removing contaminants (FIG. 2). The authors discuss the economic drivers and benefits now available with this new method.

2.0

1.0

0.0 Global recoverable oil

Oil produced to date

FIG. 1. Global Oil recoverable resources.

FIG. 2. Commercial demonstration facility in Bakersfield, California.

Hydrocarbon Processing | SEPTEMBER 2012 55

Refining Developments that the oil will flow to the surface. After produced crude oil is dewatered, it must be diluted with a lighter hydrocarbon so that the crude oil can flow in a pipeline and be transported to the refinery gate. These diluents are typically naphtha or light oils, and diluents can make up 40% of the blended heavy-oil stream, thus adding significant cost to production operations.

Transport. Transporting diluent to the production facilities requires dedicated pipelines. Operators incur the costs to build and operate the diluent delivery facilities, as well as suffer the decrement in lost pipeline capacity that could be otherwise used to transport additional valuable crude.

Processing. Once at the refining center, the heavy oil is typically processed through a delayed coking unit where approximately 30% to 35% of the residual oil is converted to coke.

In summary, several factors are important in considering heavy oils as a feedstock for producing transportation fuels: 1. Heavy oils require significant energy for extraction from the reservoir 2. A diluent source is required to allow their transportation 3. Large refinery investments are necessary for processing heavy oils and a significant fraction of the feed is converted to a low-value byproduct—coke.

Novel process. A new process has been proven to overcome

many of the production, transportation and refining challenges of heavy oils. It is energy efficient. This process produces the energy in situ that is required to heat the heavy crudes to bring the oil to the surface. This process selectively removes the least valuable of the components (resid) of the heavy oil. This process significantly reduces the heavy crude’s viscosity and eliminates the cost and use of diluent. By eliminating most of the residual oil, the synthetic crude oil (SCO) is much easier to transport and more amenable for processing in refineries.

Excess energy can be generated and made available for export or for extracting the heavy oils from the reservoir. The process consumes only 8 vol% of the heavy oil in the process, thus leaving up to 92 vol% of the heavy crude oil produced for sale and/or refining. The resultant SCO can be effectively processed in most modern refineries. The heavy-oil upgrading (HOU) units can be

FIG. 3. Example of crude oil price seriatim—Canadian crude oils.

56 SEPTEMBER 2012 | HydrocarbonProcessing.com

designed at scales, as low as 10,000 bpd to 30,000 bpd. The process is ideal for modularization and access to remote locations.

Economics. By installing an HOU unit at the production site or midstream in the supply chain, significant economic returns can be realized. FIG. 3 illustrates the relative values of SCO at the refinery gate for the Canadian Athabasca Bitumen case as compared to other crude oils.2 In this example, the value of SCO crude, as determined by its convertibility into refined products, is $108/bbl vs. $82/bbl for the native unprocessed Canadian bitumen. This represents a $26/bbl uplift in value through the use of the HOU process.

In addition to uplifting the value of crude oil, the HOU process also produces energy for field operations and eliminates the reliance on diluent for transportation. This significantly lowers operators’ production costs thus improving the economics of heavy-oil projects.

Shift in operations. The new paradigm is that the energy industry has the flexibility to add a new technology that can optimize the supply chain. By selectively rejecting carbon economically and efficiently at the production site, vs. at the refinery, substantial economic returns are possible, thus breaking the old paradigm.

The existing constraints that impose a significant economic penalty to the commercialization of heavy oils can be removed.

The new process is highly scalable and cost-effective. For the first time, a new field-integrated approach allows carbon to be selectively and economically rejected closer to the production site.

Models. A variety of business models have been used to determine the best applications of this novel and unique technology.

Attractive returns on investment (> 20%) and a net present value (NPV) of $200 to $500 million are achievable depending on the installation, geography and type of heavy crude oil to be upgraded and converted into SCO.

TECHNOLOGY PRINCIPLES The HOU process uses a circulating transport bed of hot sand to quickly heat the heavy feedstock and convert it to a lighter, more valuable product. FIG. 4 shows an overview of the HOU process flow.3 The underlying breakthrough of this

Refining Developments method is that the asphaltenes present in heavy oil residue are dispersed and deposited on the sand in a thin film. This is facilitated by the high sand-to-oil ratio and efficient feed injection zone mixing. The process requires less than 2 seconds total time from feed in to product out. The very short residence time is at the heart of the process. It allows conversion of the heaviest residue into high yields of lighter, more valuable products with a minimum production of unwanted byproduct coke and gas.

The heaviest fractions of the liquid feed are converted to coke, which is directly deposited on the circulating sand particles. In addition, a small portion of the residue feed converts to noncondensable product gas. The coke-covered sand is regenerated in the reheater where the thin coke layer is burned off, thus providing the energy necessary to support the upgrading reactions and to also supply substantial excess energy that can be captured via high-pressure (HP) steam generation.

Product gas is collected and consumed as fuel gas in fired heaters and steam boilers that support the HOU unit’s internal energy demand while coproducing HP steam. This process generates enough excess energy to supply virtually the entire steam requirement for a typical steam-assisted gravity drainage (SAGD) project in Canada. Alternatively, in regions where steam is not needed for oil recovery, the excess energy can be converted into electricity. A typical 20,000-bpd HOU plant generates an energy equivalent of a 40-MW power plant.

Proven processing principles. The HOU process is me-

chanically very similar to a fluidized catalytic cracking (FCC) unit, a common conversion process found at the center of every modern refinery.4 At present, there are over 400 FCC units in operation today, and FCC has been commercialized globally since the 1940s. Although configured similarly to an FCC unit, the HOU process requires fewer pieces of equipment and is noncatalytic. Result: It is less complicated and easier to operate than an FCC unit.

Products and yields. The properties of the HOU product SCO, such as API, viscosity, metals, sulfur and nitrogen, are significantly better than the original heavy oil feedstock. This processing method nearly eliminates the residual oil (material boiling above 1,000°F) originally present in the feed and yields a SCO product that can be processed in refineries without producing large quantities of undesirable heavy fuel oil and requiring additional residue conversion capacity.

Unlike coking, this process does not accumulate large volumes of coke byproduct, which must be stored or transported offsite. The produced coke is consumed by the process itself and converted into onsite energy. Also, unlike other upgrading technologies, which require hydrocracking and/or hydrotreating, the HOU process does not require hydrogen addition to achieve the desired improvements in product quality. This represents a significant capital cost advantage in comparison with traditional technologies due to the reduced scale of the processing site and the fewer pieces of equipment required.

TABLE 1 summarizes the product yields using Athabasca bitumen as a feedstock in the HOU process. Note: Low residual oil in the SCO (5.8 voll%) as well as the very high yield of vacuum gasoil (VGO) plus distillates (78.9 voll%) TABLE 2 is an example of product properties that list the significant improvement in API, metals, viscosity, etc.

MIDSTREAM APPLICATION In many locations, producers are faced with declining rates of local light crude oil supplies that have traditionally been used as blendstock to facilitate delivery of heavy oil to markets. At the same time, these producers are also relying on increased volumes of heavier oil production to satisfy future export demand. These

TABLE 1. HOU product yield Athabasca bitumen

SCO

Naphtha, vol%

0.1

3.1

Kerosine, vol%

0.7

4.2

Distillate, vol%

12.1

21.7

VGO, vol%

34.8

57.2

Residuum, vol%

52.3

5.8

Coke, wt%

–

10.1

Gas, wt%

–

4.9

FIG. 4. Process flow diagram of the HOU process.

TABLE 2. HOU feed and product properties Feed Gravity, °API

Product

8.5

18.8 +

23,000

23

Sulfur, wt%

5.02

2.91

Nitrogen, wt%

0.66

0.4

Ni+ V, ppm

280

42

52

6

Viscosity, cst@40°C

Resid, 1,000°F+

FIG. 5. Midstream configuration to upgrade heavy oil into lighter, transportable SCO and to produce electrical power.

Hydrocarbon Processing | SEPTEMBER 2012 57

Refining Developments diverging production trends lead to crude oil quality that cannot meet pipeline and customer-contract specifications, or result in the market value of the heavy blends being so severely depressed due to residual oil conversion limits at the refineries that the heavy oil can no longer be economically produced. Countries and companies are facing declining rates of benchmark crudes, and are seeking ways to replenish supplies of export volumes with crude oil that can meet historical quality specifications. As illustrated in FIG. 5, HOU processing methods can offer unique opportunities to these producers via midstream solutions.

This process can be strategically located at a site where heavyoil production streams are gathered, such that the producer can eliminate or reduce the need for blending with large volumes of higher-value crude oil. The heavy oil is received from the producer, and upgraded in a location convenient to both the producer and the transportation terminal operator. Excess energy from byproduct gas and coke is converted onsite into electrical power that can be used to supply local electricity demands. Upgraded SCO is forwarded downstream to the transportation terminal, where it can be directly transferred to sales or utilized as a lighter diluent for blending with heavy production. The small footprint of the processing unit, coupled with the lower installation cost, is an attractive midstream solution.

Technology Development History In 2005, Ivanhoe Energy acquired the petroleum rights of a patented pyrolysis process that is based on a hot “transported” bed (typically, sand) to produce renewable liquid fuels and chemicals from wood residues and other solid biomass. Being forward-thinking, Ensyn investigated the applicability of applying a hot “transported” bed as a possible way to upgrade heavy oil in situ. The process, HOU, was studied extensively during early pilotplant work, and then validated by successful operation of a 1,000-bpd commercial demonstration facility (CDF) in Bakersfield, California (FIG. 2). Testing of heavy crude oils in the CDF proved the scalability of the HOU process, and it also provided key design information for the first commercial BED package and FEED of Ivanhoe Energy’s Tamarack project in Alberta, Canada.

In 2008, Ivanhoe Energy commissioned the feedstock test facility (FTF) at the Southwest Research Institute in San Antonio, Texas (FIG. 7) to further improve the process for a wide range of heavy oil feedstocks. The FTF was designed to model the commercial HOU process, but at a reduced capacity, making it feasible to test smaller batches of heavy crude oils rapidly. Equipped with a state-of-the-art process control and measurement system, the FTF maximizes the quality of data collected, validating technology advancements being made to this novel process and supplying critical data for commercial design. Ivanhoe Energy has completed technology development and commercial engineering. The process will not be available for licensing.

58 SEPTEMBER 2012 | HydrocarbonProcessing.com

COMMERCIAL ENGINEERING Following development, scale-up and testing operations, the designing and engineering of full-scale HOU facilities for commercial heavy oil projects is underway. The basic engineering and design (BED) package has been completed for Ivanhoe Energy’s Tamarack Athabasca Oil Sands Project. This phase established a complete deployment strategy, including the technical design basis, capital cost estimate and project execution strategy for the first commercial unit. Key technical design deliverables were finalized, such as process and instrumentation diagrams (P&IDs); equipment, instrument, and materials purchase and installation specifications; and three-dimensional (3D)CAD modeling of plant equipment locations, piping networks, civil and structural supports (FIG. 6).

Modularization. A key component of the project execution strategy is modularization, and it has been fully incorporated into the cost estimate and the design plan based on extensive project experience in Canada. The capital cost estimate for Tamarack has been developed to Class 3 (AACE) accuracy. This estimate was completed at the end of the front-end engineering and design (FEED) phase with competitively priced equipment and installation costs based on physical material-takeoffs generated by the 3D CAD model.

The BED, FEED and value-engineering efforts undertaken for the Tamarack project will serve as a basis for future conceptual and feasibility studies. A conceptual engineering study and accompanying cost estimate were recently completed for a Latin American midstream project. This commercial engineer-

FIG. 6. Footprint of a commercial HOU facility.

FIG. 7. Feedstock test facility at the Southwest Research Institute in San Antonio, Texas.

Refining Developments ing work has demonstrated that the HOU process is economic at feed capacities as low as 10,000 bpd to 30,000 bpd, and the typical Class 4 cost estimate for a plant ranges from $12,000/ bbl to $20,000/bbl of capacity, depending on scale, feedstock properties and configuration.

CASE HISTORY This novel process is a powerful way to monetize heavy oil resources either at the source deployed to a production field, or in the midstream application. The key value to this novel process’ is that the SCO produced is of great value to refiners.

Such value is principally the result of: • Low residual oil content (6 wt%–10 wt%) • Higher API (16°–20°).

A recent study by a world-class independent consulting firm determined the market value of HOU SCO in several different refining centers. This study was done using proprietary refinery modeling and optimization tools (linear programs or LPs) that are representative of regional refining centers and can be used to determine the value of a new crude oil when brought into the overall feedslate of that refining center.

The premise of the evaluation was to simulate penetration of HOU-produced SCO into the refining center’s overall crude diet, and allow the regional LP modeling tool to optimize the refinery operations with the new crude slate. Product volumes and prices were held constant, such that the optimization program could adjust unit operations and the suggested market

price for the new crude. The program iterates through the model calculations until the refining center model is able to achieve the same gross product volumes and net margins (profits) with the new crude slate, as was realized from the original crude slate.

The result of this analysis is the determination of the SCO value, benchmarked against a crude oil with a known market price.

Modeling of HOU SCO was evaluated at market penetration levels of 1% to 5% to ensure that the refining models were adequately reflective of the expected market price of the HOU SCO. This procedure provided certainty that, on aggregate, the refineries in a regional center will be able to realistically introduce the SCO in significant volumes and that the market value determined by the study is realistic and achievable. Two strategic HOU SCO products for modeling were selected: • Expected commercial SCO product from the future Tamarack Athabasca Oil Sands Project in Alberta, Canada.

Penetration of the Tamarack SCO was modeled into two key refining centers. The first center evaluated was the Midwest refining region of PADD 2 due to the geographical proximity to Canada. The second center was Singapore, which serves as a proxy for the Asia Pacific region.

• The other SCO modeled was the product of HOU processing of Boscan crude oil from Venezuela. The Boscan SCO was modeled into the PADD 3 center, as well as into the Singapore refining center.

The results of this study determined that the HOU SCO will be valued on a par with Brent price, with the differences

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Hydrocarbon Processing | SEPTEMBER 2012 59

Refining Developments

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dependent on a combination of the refining center selected and the feed quality. HOU SCO has a very low content of residual oil and a very high VGO content, such that it makes an excellent feedstock for refineries with sufficient hydrotreating capability to manage the SCO’s high sulfur and low hydrogento-carbon ratio. The penetration studies show that refining capacity available for processing SCO exists in significant amounts for all regions, thus supporting these price levels since the calculated SCO values were independent of market penetration within this range.

The pricing forecasts for heavy oil and SCO generated in this study, together with the CAPEX and OPEX estimates, were used to generate the expected economic returns for sample HOU projects. For example, projects with capacities of 20,000 bpd to 30,000 bpd are expected to provide IRR’s between 15% and 30% depending on location specifics, feedstock quality and various design considerations.

ACKNOWLEDGMENTS The authors thank Michael Hillerman for his assistance in preparing this manuscript and also Hilary McMeekin and Jerry Schiefelbein for reviewing the manuscript.

LITERATURE CITED International Energy Agency, World Energy Outlook 2011, (excludes Kerogen oil).

2 Independent study with world class consulting firm.

3 Complete HTL process video available at www.ivanhoeenergy.net.

4 Cabrera, C. A. and M. Silverman, “Bringing heavy crudes to market,” International Refining and Petrochemical Conference 2012, 12-14, June 2012, Milan, Italy.

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EDITOR’S NOTE The article is a revised and updated version from an earlier presentation at the International Refining and Petrochemical Conference 2012, 12–14 June 2012, at Milan, Italy.

Ivanhoe Energy uses technologically innovative methods to significantly improve the development of heavy oil and other oil and gas assets. Primary among these is Ivanhoe’s proprietary, patented heavy-oil upgrading process called HTL, or Heavy-to-Light.

CARLOS A. CABRERA is the executive chairman of Ivanhoe Energy, a publicly traded oil and gas company. Prior to his appointment, he served as the founding president and CEO of the National Institute of Low Carbon and Clean Energy (NICE) based in Beijing, China. Mr. Cabrera was also a 35-year employee with UOP, holding posts as the president/CEO and then chairman. He is a distinguished associate to the world energy consulting firm FACTS and serves on the board of directors of GEVO, a publicly traded biotechnology company, and the Gas Technology Institute, a US-based leading research, development and training organization. Mr. Cabrera has been given many awards, including being inducted into the University of Kentucky Engineering Hall of Distinction and the Honeywell Corp. 2008 Senior Leadership Award. He earned a BS degree in chemical engineering from the University of Kentucky and an MBA from the University of Chicago.

DR. MICHAEL SILVERMAN is executive vice president and chief technology officer of Ivanhoe Energy. Dr. Silverman joined Ivanhoe in 2007 from Kellogg, Brown and Root (KBR) and is responsible for all technical aspects of Ivanhoe Energy’s proprietary heavy oil upgrading process—HTL (heavy-to-light).

This includes interfacing with leading engineering firms in the design of commercial HTL installations, technology development and intellectual property management. Dr. Silverman has almost 30 years of experience in technology development and management, including the commercialization and marketing of new technologies, and is a leading expert in the fluid catalytic cracking (FCC) processes. Prior to joining KBR, Dr. Silverman was the manager of technology development for Stone & Webster, Inc. His earlier experience included the management of fluid catalytic cracking for Tenneco Oil Co., and an assistant professorship in chemistry at Rutgers University.

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Special Report

Refining Developments W. BAADE, S. FARNAND, R. HUTCHISON and K. WELCH, Air Products and Chemicals, Allentown, Pennsylvania

CO2 capture from SMRs: A demonstration project In June 2010, the US Department of Energy (DOE) selected a gas-specialty company to receive American Recovery and Reinvestment Act (ARRA) funding to design, construct and operate a system to capture CO2 from two steam methane reformers (SMRs) located within the Valero refinery in Port Arthur, Texas. The CO2 removal technology will be retrofitted to the SMRs, which produce hydrogen to assist in the manufacture of petrochemicals and the making of cleaner burning transportation fuels by refinery customers on the Gulf Coast hydrogen pipeline network.

The necessary commercial agreements were signed to proceed with a planned carbon capture and sequestration (CSS) project in Port Arthur, Texas. The refinery is providing the additional land and rights-of-way required for the project, in addition to supplying utilities to support the project. Meanwhile, purified and compressed CO2 will be supplied for injection into enhanced oil recovery (EOR) projects in Texas. CO2 for EOR is beneficial because it: • Increases energy security by increasing recoverable oil • Creates economic opportunity for the government via increased tax revenues and for individuals via jobs created in domestic oil fields.

• Provides environmental benefits from capturing, productively using and storing CO2, rather than emitting it into the atmosphere.

Beginning in late 2012, approximately 1 million tons of CO2 annually will be recovered and purified. The DOE is providing a total of $284 million or approximately 66% of the over $400 million project. This includes partial reimbursement of operating costs through the end of the demonstration period (September 30, 2015).

Current Port Arthur site. A new 180-mile-long pipeline is being constructed to connect to existing Louisiana and Texas hydrogen pipeline systems. This integrated pipeline system will unite over 20 hydrogen plants and over 600 miles of pipelines to supply the Louisiana and Texas refinery and petrochemical industries with more than one billion cubic feet of hydrogen per day. The Port Arthur SMRs and the CO2 capture project will be part of the combined pipeline system (FIG. 1).

The Port Arthur site was selected to host the CO2 capture facility based on economies of scale of capturing CO2 from the two SMRs on the premises. The proximity of the SMRs accommodated a common drying and compression system that significantly reduced capital when compared to the alternative of isolated drying and compression arrangements.

TEXAS LOUISIANA Houston

Geismar Port Arthur

New Orleans

Texas City Sweeney Three Rivers

Ingleside Corpus Christi

Gulf of Mexico Hydrogen pipeline Offgas H2 plant SMR/POx hydrogen

H2 plants Capacity Pipeline length

USGC 1.2 + Bscfd 600 miles

FIG. 1. The CO2 capture project will be part of a hydrogen pipeline system on the US Gulf Coast.

H2 power generation export steam CO2 transport via pipeline for EOR and storage

Objectives and scope. The main objective for this CO2

capture project is to demonstrate an advanced technology that captures and sequesters carbon dioxide emissions from large-scale industrial sources into underground formations. In order to be eligible for supplemental funding from the DOE, it was necessary for applicants to meet certain DOE objectives, which are itemized in TABLE 1.

In addition, the DOE evaluated projects on a cost-per-unit basis of CO2 captured and sequestered, as well as on the magnitude of future potential commercialization. This project will provide real-world data illustrating the true costs of CO2 capture and sequestration. It was one of only three projects to receive Phase 2 funding from the DOE, which covers construction and operating and maintenance costs during the demonstration period.

Baton Rouge

Lake Charles

H2 power generation export steam

CO2removal purification, compression

FIG. 2. 1 million tons of CO2 per year will be captured from the two SMRs. The CO2 will be used for enhanced oil recovery.

Hydrocarbon Processing | SEPTEMBER 2012 63

Refining Developments FIG. 3 is a block flow diagram for the project that illustrates how the CO2 capture facility will be integrated within the existing SMRs. The facility will utilize a proprietary-designed CO2 vacuum swing adsorption (VSA) system that will be retrofitted to each of the two existing SMR trains (PA-1 and PA-2). Each VSA unit is designed to remove more than 90% of the CO2 contained in the reformer pressure swing adsorption (PSA) feed gas (FIG. 4).

Sweet syngas (CO2 removed) will be returned from the CO2 VSA system to feed the existing SMR hydrogen PSAs. CO2 produced from the VSA units will be compressed and dried in a single train located at PA-2.

VSA system (PA-1 and PA-2). CO2 containing syngas from the steam-methane reformer cold process condensate separator is routed to the VSA system. The CO2 contained in the process gas of the PA-1 and PA-2 SMRs will be removed with multiple VSA units. Each VSA unit includes a series of vessels filled with adsorbent to selectively remove one or more components from the feed gas. In this case, the feed gas

Process summary and equipment.

Port Arthur 2 Natural gas Utilities HP steam export Power export

Purge gas Syngas

LP steam

Port Arthur 1 Natural gas Utilities HP steam export Power export

Existing PSA

Existing SMR Syngas

Syngas (CO2 removed) Water New New Wet CO2 compressor/dryer VSA

Export hydrogen

Export CO2

is the raw hydrogen stream from the SMR plants upstream of the existing hydrogen PSA. The VSA cycle is similar to the hydrogen PSA cycle. Adsorber vessels are fed with gas at high pressure, causing selective adsorption of feed components onto the adsorbent bed. The gas that is not adsorbed by the bed is a hydrogenrich stream and is sent to the H2 PSA for further purification.

Then, the vessel undergoes a series of pressure equalizations, with vessels at lower pressures before a CO2 product is drawn off. There are two unique steps in the VSA cycle because the product is now CO2 at high purity. The first is that a vacuum pump is needed to draw off the CO2 product (FIG. 5) to subatmospheric pressures in an “evacuation” step. The second is a “rinse” step in which blowdown gas is taken from a lower pressure bed, compressed, and fed to a higher pressure bed.

The “rinse” and “evacuation” steps are the keys to achieving a high purity CO2 product.

CO2 compressor and dryer (PA-2). Raw CO2 exits the two trains of the VSA systems after cooling and is combined at the suction of the first stage of an eight-stage, integrally-geared centrifugal compressor. Each of the first five compressor stages is followed by an intercooler, which also includes an integral separating section to remove condensate, which is mainly water.

Condensate from the first five intercoolers is combined in a common vessel and piped to the existing plant waste sump.

A portion of the PA-2 condensate can be sent to the tri-ethylene glycol (TEG) dryer system, where it serves as water makeup, thereby reducing the overall water requirements of the plant by recycling.

Purge gas Syngas Existing SMR LP steam

Existing PSA Syngas

Export hydrogen

Syngas (CO2 removed) New VSA

Wet CO2

Existing stream New stream Revised stream

FIG. 3. Block flow diagram of Port Arthur SMRs and integrated CO2 capture facility.

FIG. 4. VSA trains are used to remove more than 90% of the CO2 contained in the reformer PSA feed gas.

64 SEPTEMBER 2012 | HydrocarbonProcessing.com

TABLE 1. Certain objectives had to be met to receive DOE supplemental funding DOE objectives

Satisfying criteria

Compliance with American Recovery Act objectives (jobs and economic recovery)

The CO2 capture facility will require construction jobs to complete the retrofit and will require additional operators to manage the facility on an ongoing basis

Capture at least 75% of the CO2 from a treated industrial gas stream comprising at least 10% CO2 by volume that would otherwise be emitted to the atmosphere

Capturing greater than 90% of the CO2 from two SMR hydrogen production process streams that contain greater than 15% CO2

Project size shall be a large-scale industrial CCS project producing 1 million tons of CO2 /yr

The CO2 Capture Facility is designed to capture 1 million tpy of CO2

CO2 must be sequestered in underground geologic formation including oil-bearing formations

This project will sequester the CO2 in existing EOR fields.

EOR projects are conducted in reservoirs that have trapped oil and thus are excellent candidates to trap CO2 during EOR operations

Monitoring, verification and accounting (MVA) of the sequestered CO2

The EOR administrator will monitor, verify and account for the CO2 sequestered with this project

Proposed technologies for CO2 capture and sequestration are ready for demonstration at commercially relevant scale

CO2 capture technology using a VSA system will be used in this project.

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CO2 exiting the fifth stage intercooler is sent to a TEG drying system, where water is removed. After drying, the CO2 is sent to the sixth stage section, where the final compression occurs in stages 6, 7 and 8. After final cooling following the eighth stage, the CO2 exits the battery limits and enters the CO2 pipeline at the required pipeline pressure of over 2,000 psig.

TEG dehydration units have routinely been used for CO2 dehydration for EOR applications, as well as being the standard technology for natural gas drying. TEG has a very high affinity for water, allowing very high removal, and a low volatility, minimizing solvent losses into the CO2 product.

The wet CO2 exits the after cooler following the fifth stage of compression and is contacted with lean dry TEG in the tray or structured packing section of the contactor tower, where water vapor is absorbed in the TEG, thus reducing its water content.

The dry CO2 exiting the top of the absorber is heated vs. the incoming lean TEG and sent to the final three stages of CO2 compression, where the CO2 is raised above the critical pressure of 1,071 psia. The TEG content of the dry CO2 is very low.

The wet rich TEG exiting the contactor is depressurized and flows to the regeneration system. The wet rich TEG is then preheated and flashed in a horizontal separator to remove much of the dissolved CO2 and other light gases. The flash gas is sent back to the compressor so that the contained CO2 is not lost. The flashed water-rich TEG liquor is cleaned in charcoal and sock filters and then heated with lean TEG from the regenerator column. The rich heated TEG is then fractionated in the regenerator column and heated in the reboiler, boiling off the absorbed water vapor. The lean TEG exiting the bottom of the regenerator is cooled with rich TEG and then pumped back to the absorber. The reboiler is directly fired with natural gas.

FIG. 5. VSA vacuum blowers are used to recover CO2 from the VSA beds and deliver it to the CO2 product compressor before offsite transport via pipeline for use in EOR.

Carbon sequestration system description. The CO2 for EOR will be transported to the site via the pipeline, and will be injected via a CO2 injection pump station in the field connected to 14 CO2 Class II injection wells.

The commercial monitoring program will track the CO2 injected, the CO2 recycled and the performance of the reservoir and wells in retaining CO2. The research program will collect time-lapse data testing alternative and possibly high-resolution techniques for documenting that the CO2 is retained in the injection zone and in the predicted flood area, and that pressure is below that determined to be safe. A report will be Hydrocarbon Processing | SEPTEMBER 2012 65

Refining Developments prepared evaluating the results of the MVA program, revised model runs showing model match, comparing the effectiveness of the commercial program to the research program in documenting effectiveness and permanence of storage.

facility with the Green pipeline. The pipeline is an existing 24in. pipeline that runs from Donaldsonville, Louisiana, to the Hastings Field, south of Houston, Texas (FIG. 6).

Current status. The CO2 capture project is being executed

CO2 export pipeline. A 13-mile pipeline will be constructed

in conjunction with this project to connect the CO2 capture Arkansas

Texas

Phase 9 (Conroe) 130 MMbbls Phase 7 (Hastings area) 70-100 MMbbls

Phase 3 (Tinsley) Mississippi Alabama 46 MMbbls Delta Louisiana Free State Phase 5 (Delhi) pipeline pipeline Phase 2 Sonat MS 36 MMbbls 83 MMbbls pipeline Phase 4 31 MMbbls Phase 1 Phase 6 (Citronelle) NEJD Green 82 MMbbls pipeline 26 MMbbls pipeline Summary (MMbbls) Proved 148 339 Probable3 Produced-to-date 58 545 Total3

Phase 8 (Oyster Bayou) 20-30 MMbbls

FIG. 6. Map showing Denbury’s 300+ mile long Green pipeline, which was designed to carry natural and anthropogenic CO2 to oil fields in Texas and Louisiana. Source: Denbury 2011 Annual Report.

in three phases and is proceeding right on schedule. Phase 1 established the definitive project basis and has been completed. Phase 2 covers the design and construction of the project and Phase 3 entails operation of the project through the end of the demonstration period. The project is currently in Phase 2. The project is further broken down into three subprojects: CO2 capture facility, CO2 export pipeline and MVA. The CO2 capture facility and CO2 export pipeline are being executed as a single project, with the MVA portion subcontracted to Denbury.

For the CO2 capture facility, all of the major equipment purchases and detailed design have been completed. The detailed design for work outside the battery limit (OSBL) has been awarded and is complete. The OSBL construction work was kicked off in the spring of 2011. For work inside the battery limit (ISBL), piling began in August 2011 and foundations began October 2011; both have been completed. Mechanical construction began January 2012, and electrical and instrumentation construction began June 2012.

The units are being brought online in sequence to facilitate early CO2 capture and to allow for commissioning learnings from PA-2 to be incorporated into PA-1. Commissioning ac-

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Refining Developments tivities are planned for September 2012, with CO2 product being introduced in the pipeline December 2012.

Forward schedule and plan for the future. The PA-2 CO2 capture unit (including CO2 drying and export compression) is scheduled to be onstream in late 2012 and the PA-1 CO2 capture unit is scheduled to be onstream in early 2013. The demonstration period will continue until September 30, 2015.

Over the past 25 years, the industry has transitioned from amine and potassium carbonate liquid absorption processes to PSAs for two reasons. The first is because of increased hydrogen purity requirements for refining processes. The second involves the increased thermal efficiency afforded by steam export to refineries. Capturing CO2 from existing hydrogen plants with PSAs is more challenging because the thermal efficiency is already highly optimized. VSAs are advantaged for retrofits because they can be more easily incorporated with minimal impacts to hydrogen supply to the existing refinery.

This commercial scale demonstration of VSA technology provides an additional option for recovering significant volumes of CO2 for EOR. Despite a shortage of CO2 for EOR, the existing CO2 market does not support current CO2 capture economics without external funding, which is why the DOE’s support is essential.

Technical and economic results from this project will be key in determining the most effective path to commercialization.

NOTE Air Products and Chemicals received the ARRA funding to supply CO2 for EOR. WILLIAM F. BAADE is the global marketing manager for oil, natural gas and transport fuels in Air Products’ Tonnage Gases, Equipment and Energy Division. He has over 35 years of industrial experience in various sales, business development and marketing assignments. Mr. Baade holds a BS degree in chemical engineering from Stevens Institute of Technology and graduated in 1976. He obtained a MBA degree from Lehigh University in 1982.

SARAH G. FARNAND is a market manager with Air Products & Chemicals.

Her current responsibilities include analyzing the global oil and natural gas markets with an eye to identifying opportunities for Air Products in the fields of EOR, GTLs, LNG, refining and alternative fuels. She holds a BA degree in economics from the College of William and Mary and a MBA in finance and strategy from the University of Maryland.

ROBERT L. HUTCHISON joined Air Products & Chemicals in 1979 and is currently the senior project manager for the Port Arthur CO2 recovery project.

Mr. Hutchison has held various engineering, operations and commercial positions during his 33 year career at Air Products and has distinguished himself in the management of large, complex industrial gas projects. He holds a BS degree in chemical engineering from the University of Illinois and a MBA degree from Lehigh University.

KEN WELCH joined Air Products & Chemicals in 1996 and is currently the HyCO business development manager. Mr. Welch was the principal investigator for the CO2 capture project, working as the asset manager and primary contact for the DOE. Mr. Welch has held various commercial positions during his Air Products career and has distinguished himself in the business development of large, complex HyCO projects. He holds a BS degree in chemical engineering and marketing from Pennsylvania State University.

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Special Report

Refining Developments M. LIPPMANN and L. WOLSCHLAG, UOP LLC, a Honeywell Co., Des Plaines, Illinois

Increase FCC processing flexibility with improved catalyst recycling methods The present refining market is highly dynamic, which emphasizes the need for greater operating flexibility in the fluid catalytic cracking (FCC) unit. Continued development in FCC technology is a high priority. For example, a new technology allows refiners to optimize catalyst circulation rates in the riser, independent of the unit heat balance. This capability enables improved conversion, product selectivity and emissions control while simultaneously reducing operating costs. This article will discuss how an advanced FCC catalyst recycling process technology increases the flexibility of the FCC unit to shift between different processing objectives while lowering costs and maximizing product values to meet the challenges faced by the global refining industry.

ADVANCED FCC CATALYST RECYCLING TECHNOLOGY The basic concept of the advanced FCC catalyst recycling process technology is to recycle catalyst from the FCC reactor stripper back to the inlet of the riser. Modern catalyst systems are inherently more coke tolerant than their older counterparts. Thus, they can accrue appreciable quantities of coke and still retain a substantial fraction of base activity. Recycling of catalyst from the reactor stripper in modern FCC units represents an additional activity component being added to the riser. A new term, “carbonized,� has been adopted to describe this catalyst. At present, six advanced FCC catalyst recycling process units are in operation, with an additional four units being engineered. FIG. 1 shows the layout of an FCC unit with the a catalyst recycling technology.

• Increasing riser temperature • Decreasing feed preheat • Increasing regenerator catalyst cooler duty • Injecting a heat load into the riser (steam, water, light cycle oil) In contrast, carbonized catalyst recycle from the reactor stripper via the advanced FCC catalyst recycling process standpipe is not constrained by the heat balance as it does not significantly alter the total coke yield. Because catalyst is circulated from the riser outlet, down to the riser inlet, and back up to the riser outlet starting and ending at the same temperature, little enthalpy change occurs in the loop. Result: There is practically no impact upon the coke yield. Thus, the riser cat/oil can now be expressed as: Cat/oil Riser =

Coke yield

∆HRegeneration

CpCatalyst (TRegen

TReactor )

Cat/oil Recycling

The advanced FCC catalyst recycling process impacts the heat balance by increasing ∆ coke on the catalyst circulating

Catalyst recycling and heat balance. In the traditional FCC process, the catalyst circulation rate is fixed by the heat balance. Under these conditions, the catalyst circulation only increases in response to a greater heat demand by the reactor.

Therefore, in a conventional FCC system, the extent that regenerator catalyst to oil ratio (cat/oil) increases is expressed as:

Cat/oil Regen =

Coke yield

∆HRegeneration

CpCatalyst (TRegen

TReactor )

Process changes that increase the regenerator catalyst circulation rate and raise the coke make required to satisfy the altered heat balance include:

FIG. 1. Equipment diagram of the advanced FCC catalyst recycling process.

Hydrocarbon Processing | SEPTEMBER 2012 71

Refining Developments to the regenerator. The ∆ coke is defined as the difference in coke content between the regenerated catalyst and spent catalyst. As the advanced FCC catalyst recycling process circulation rate is increased, the ∆ coke increases due to the recycling catalyst particles completing additional passes through the riser prior to regeneration. Because regenerator temperature is a strong function of ∆ coke, the increase in ∆ coke from the TABLE 1. Reactor/regenerator response to change in the advanced FCC catalyst recycling process cat/oil Advanced FCC catalyst recycling cat/oil

0.0

5.0

7.5

Regen cat/oil

8.2

7

6.5

Riser cat/oil

8.2

12

14

Advanced FCC catalyst recycling ratio

0.0

0.7

1.2

∆ Coke

0.6

0.7

0.8

1,260

1,300

1,320

Regen temperature

TABLE 2. Evaluation of DFAH vs. advanced FCC catalyst recycling technology for regenerator temperature control Case 1

Case 2

Case 3

Base

DFAH

New catalyst recycling

Feedrate, bpd

30,000

30,000

30,000

Advanced FCC catalyst recycling C/O

0.0

0.0

6.2

Riser C/O

8.2

6.2

12

Fuel gas to air heater, wt% feed

0.0

1.1

0.0

advanced FCC catalyst recycling process increases the regenerator temperature and decreases the regenerator cat/oil ratio, as shown in TABLE 1.

Despite the decrease in regenerated cat/oil, this FCC catalyst recycling technology enables a refiner to increase the total riser cat/oil ratio to levels considerably higher than a traditional FCC unit while simultaneously increasing the regenerator temperature. Reducing feed contaminants through severe hydrotreating reduces the ∆ coke in the unit, which cools the regenerator. Such conditions present a significant challenge for refiners on maintaining the regenerator hot enough to control carbon monoxide (CO) and nitrogen oxide (NOx ) emissions below acceptable levels. The advanced FCC catalyst recycling process can provide an alternative solution to traditional methods of maintaining high regenerator temperatures, and it simultaneously enhances unit performance through increased total riser cat/oil ratio. TABLE 2 shows an economic comparison between using the direct-fired air heater (DFAH) and the advanced FCC catalyst recycling technology to increase regenerator temperature by an equivalent amount.

While both approaches will achieve a higher regenerator temperature, firing the DFAH will result in a lower riser cat/oil ratio and, consequently, a loss of conversion and margin. Conversely, the advanced FCC catalyst recycling process increases TABLE 3. ECAT physical properties ECAT A

ECAT B

Ace micro activity test (MAT)

74

66

64

UCS, A

24.267

24.292

24.27

150

115

149

Total surface area, m2/g 2

ECAT C

Zeolite surface area, m /g

61

40

93

89

75

56

Regenerator, °F

1,260

1,340

1,350

Matrix surface area, m2/g

Conversion, wt%

Base

(3.0)

2.1

Micropore volume, cc/g

0.028

0.019

0.043

500

6,620

610

Gross margin, $/bbl

Base

(1.35)

0.86

V, ppm

Gross margin, MM$/yr

Base

(14.4)

8.6

Ni, ppm

520

4,160

970

ZSM-5

No

Yes

Yes

Product pricing source: Global Petroleum Market Outlook 2011, Purvin and Gertz

1,300

1.8

1.4

1,250 Δ dry gas yield, wt %

Feed-contact-zone temperature, °F

1.6

1,200

1,150

1.2 1.0 0.8 0.6 0.4 0.2

1,100 0.0

0.5

1.0 Recycle ratio

1.5

FIG.2. Advanced FCC catalyst recycling process cat/oil vs. feed contact zone temperature.

72 SEPTEMBER 2012 | HydrocarbonProcessing.com

2.0

0.0

0

50 100 Δ feed-contact-zone temperature, °F

FIG. 3. Pilot-plant feed contact zone temperature vs. dry-gas yield, 1,000°F riser outlet temperature.

150

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Refining Developments the riser cat/oil ratio, resulting in a conversion increase and, ultimately, a gain in margin, all without consuming additional fuel gas. In addition, the higher regenerator temperatures improve burn kinetics and allow the FCC operator to lower the excess oxygen in the regenerator while simultaneously reducing CO and NOx emissions.

FCC catalyst recycling process and dry-gas yields. The advanced FCC catalyst recycling process can also improve product yields. The catalyst recirculating through the advanced FCC catalyst recycling process standpipe enters a proprietary mixing chamber at the base of the riser at temperatures several hundred degrees Fahrenheit below the regenerated catalyst temperature.

When these two catalyst streams are properly blended, the resultant catalyst stream contacting the feed in the injection zone of the riser is at a significantly lower temperature, thus reducing thermal reactions that produce unwanted dry gas and coke. FIG. 2 illustrates how the reactor-feed-injection zone temperature decreases as a function of new FCC catalyst recycling process cat/oil ratio, while FIG. 3 graphs how the dry-gas make decreases in response to lowering the feed-injection-zone temperature, as measured in the circulating riser pilot plant.

Catalyst activity retention as a function of coke. While

the advanced FCC catalyst recycling process technology increases riser cat/oil ratio, the impact of coke deposition on catalyst activity must be understood to predict the benefits of the higher catalyst circulation rate. To determine the relationship between coke deposition and catalyst activity, testing was conducted on several commercially available equilibrium catalysts (ECATs). TABLE 3 summarizes the physical properties of three test catalysts.

ACE pilot-plant runs were then conducted for the three catalysts to determine activity retention as a function of carbon content on the catalyst surface. Results are shown in FIG. 4. These data highlight a similar activity decline for catalysts A and B and a more pronounced decline for catalyst C. Significant differences in activity retention as a function of coke are not always obvious from the catalyst physical properties. For instance, while ECATs B and C have similar MAT activities, they do not have similar activity retention properties. Therefore, it is important to conduct activity retention tests when optimizing a catalyst for FCC catalyst recycling process. This testing enables the determination of the effective cat/oil response in the new FCC catalyst recycling system, which can be defined as: Cat/oil Effective = Cat/oil Regen +Cat/oil RecycleCat ×

TABLE 4. Impact of the advanced FCC catalyst recycling process on product yields for ECAT A Advanced FCC catalyst recycling cat/oil

0.0

5

7.5

Regen cat/oil

8.2

7

6.5

Riser cat/oil

8.2

12

14.0

Effective C/O

8.2

9.5

10.2

Dry-gas yield, wt%

Base

(0.4)

(0.5)

LPG yield, wt%

Base

1.6

2.2

Gasoline yield, wt%

Base

0.9

1.1

LCO yield, wt%

Base

(0.8)

(1.3)

CSO yield, wt%

Base

(1.3)

(1.8)

Coke yield, wt%

Base

0.1

0.2

Conversion, wt%

Base

2.1

3.1

[1−(ΔCoke × ARC )K ]

where ARC is the slope of the catalyst activity retention as a function of coke determined in the ACE unit and K is a constant.

To determine constant, K, the three example catalysts were tested in the circulating riser pilot plant by increasing the advanced FCC catalyst recycling process cat/oil and maintaining a stable regenerator cat/oil. FIG. 5 shows the testing results. These data illustrate that the conversion response to an increase in the advanced FCC catalyst recycling process cat/ oil is best achieved by ECATs A and B, which have better ARC properties relative to ECAT C.

FCC CATALYST RECYCLING PROCESS YIELDS BENEFITS Once the activity retention properties of the catalyst and the operating severity of the unit are understood for the advanced FCC catalyst recycling process, the remainder of the product

1.0 ECAT A ECAT B ECAT C

5 4

0.8

y = -0.30x

0.7

Δ conversion, wt%

Relative ACE cracking activity

0.9

0.6

y = -0.31x

0.5

0.3 0.0

0.5

1.0 Carbon on catalyst, wt%

FIG. 4. Relative activity vs. coke for three ECATS.

74 SEPTEMBER 2012 | HydrocarbonProcessing.com

3 2 1

y = -0.55x

0.4

ECAT A ECAT B ECAT C

1.5

2.0

0 0.0

0.5

Recycle cat ratio

1.0

1.5

FIG. 5. CRU conversion response to new FCC catalyst recycling process ratio for three ECATs.

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Refining Developments yields can be estimated from the calculated increase in effective cat/oil ratio. For ECAT A, the full product yield shift in response to a change in advanced FCC catalyst recycling process cat/oil is represented in TABLE 4. This table highlights that while riser cat/oil increases purely as a function of the new FCC catalyst recycling process valve output and the unit heat balance, the effective cat/oil is the primary driver of yield shifts on the FCC unit applying the advanced catalyst recycling method.

To confirm the theoretical pilot-plant data, it is important to observe the conversion shifts in the commercial advanced FCC catalyst recycling process units that have optimized the catalyst formulation to take advantage of this new catalyst recycling technology. FIG. 6 shows the conversion response for an increase in the advanced FCC catalyst recycling process for three separate commercial units. These data were filtered for constant feed quality and riser outlet temperature to isolate the impact of the new catalyst recycling process ratio on conversion. The commercial results are consistent with the pilot plant yields, thus demonstrating an approximate 2 vol% to 3.5 vol% yield improvement over the range of FCC catalyst recycling process ratio.

Improved riser design for revamps. In the traditional FCC catalyst recycling process design, regenerated catalyst from the regenerator is combined with the carbonized catalyst from 86

the reactor stripper at the base of the riser, using a proprietary mixing chamber, as shown in FIG. 7. For new units, the mixing chamber can be easily incorporated into the FCC design. However, incorporating the advanced mixing chamber in a revamp can prove challenging with regard to physically fitting the new chamber within the existing configuration without major structural modifications. To install the advanced FCC catalyst recycling technology as part of a revamp scenarios, the redesign can also include a proprietary mixing chamber and riser, as shown in FIG. 8. While the new mixing chamber would extend below grade, the redesigned mixing riser design fits within the existing configuration without major structural changes or modifications to the feed injector elevations.

Need for flexibility in FCC operations. An advanced FCC

catalyst recycling technology has demonstrated, in both pilotplant and commercial testing, a unique ability to manipulate overall riser cat/oil ratio to increase the effective riser catalyst activity gain outside the traditional limitations of the unit heat balance. This added flexibility enables FCC operators to gain a competitive advantage by offering improved yield selectivities, enhanced operational controls, and reduced operating costs.

In addition, a new mixing riser design allows many refiners to revamp their existing units to gain the full benefits of improved FCC catalyst recycling process technology.

NOTES An upgraded and revised presentation from the AFPM Annual Meeting, March 4–5, 2012, San Diego California.

84 Conversion, wt%

82 MATTHEW LIPPMANN is a group leader in Honeywell’s UOP FCC alkylation and treating development group in Des Plaines, Illinois. His responsibilities include advancing the FCC technology platform and managing the FCC pilot-plant areas. Prior to working for UOP, he was a technical services group leader at the HOVENSA LLC refinery in St. Croix and was the process engineering supervisor for the FCC, alkylation and delayed coking areas. Mr. Lippmann earned a BE degree in chemical engineering from Drexel University.

80 78 Unit X Unit Y Unit Z

76 74 0.0

0.2

0.4 Recycle cat ratio

0.6

FIG. 6. Commercial unit conversion response to advanced FCC catalyst recycling process cat/oil.

Regen catalyst

0.8

LISA WOLSCHLAG is the senior manager of Honeywell’s UOP FCC, alkylation and treating development department located in Des Plaines, Illinois. In this role, she is accountable for improving and advancing UOP’s FCC, alkylation and treating technology portfolios. Ms. Wolschlag has 20 years of experience with UOP that has included research and development, field operating service, technical service and process development. She holds a BS degree in chemical engineering from University of Illinois and an MBA degree from the University of Chicago.

Spent catalyst

Reactor riser

Recirculation standpipe

El. 0

FIG. 7. Side view of advanced mixing chamber on an FCC unit.

76 SEPTEMBER 2012 | HydrocarbonProcessing.com

Regenerated standpipe Mixing riser Proprietary mixing chamber

FIG. 8. Revamp comparison of an advanced mixing chamber vs. a proprietary mixing riser design.

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Special Report

Refining Developments R. KOLODZIEJ, Wood Group Mustang, Houston, Texas; and J. SCHEIB, Gevo Inc., Englewood, Colorado

Bio-isobutanol: The next-generation biofuel The success of any new industry lies in its ability to innovate and grow. Future growth in renewable fuels may require an evolution from first-generation products, such as ethanol and biodiesel, to next-generation products, such as isobutanol.

Isobutanol, a form of biobutanol, has many outstanding characteristics that allow it to be used in a variety of ways: • “As is”—i.e., as a solvent or as a gasoline blendstock • Converted, through known processes, to a variety of hydrocarbons for use in the petrochemical and/or refining industries • In existing production, distribution, marketing and enduser assets.

This article highlights the technology, feedstocks and market growth opportunities for isobutanol, with a focus on potential new market offerings in 2012.

Technology pathway for bio-isobutanol. The specialized production process for bio-isobutanol is fermentation paired with an integrated separation technology. This approach, developed over the past seven years, has been successfully proven at bench scale, at a pilot plant, and at a 1 million-gallon-per-year (MMgpy) demonstration plant. In May 2012, the world’s first commercial, bio-based isobutanol production plant was started up in Luverne, Minnesota, with a capacity of 18 MMgpy.

Bio-isobutanol fermentation is very similar to the existing ethanol process. Ethanol plants can be repurposed to make isobutanol relatively easily and cost-effectively, with two key modifications:

1. Modified biocatalyst. Isobutanol is a naturally occurring product of the fermentation process, found in many items such as bread and scotch whiskey; however, its commercial use to date has been limited. However, through innovations in microbiology and biochemistry, traditional yeasts have been modified, making possible a much higher selectivity in producing isobutanol—i.e., turning up the yeast’s ability to make isobutanol while also limiting the ethanol production pathway.

2. Unique proprietary separation. As the isobutanol is produced, a stream is taken from the fermentation broth where the isobutanol is removed, and the remaining broth is returned for further conversion. This has the effect of keeping the isobutanol concentration below the biocatalyst toxicity level, but it allows for improved conversion.

With these two additions to existing facilities, it is clear how the project completion time and CAPEX to make bio-isobutanol can be significantly lower than those for the construction of a greenfield plant. A plant conversion can nominally be 20%–40% of the CAPEX of a greenfield bio-isobutanol plant.

As fermentation ethanol plants have been shut down or underutilized due to recent poor economics (e.g., the US ethanol subsidy has been repealed, and the regulation “blend wall” has effectively been reached), the ability to repurpose these plants to isobutanol becomes an attractive opportunity.

Upon fermentation plant conversion, the plant capacity will be approximately 80% on a volumetric product-yield basis (compared to ethanol), but comparable on an energy-

FIG. 1. Conversion of a fermentation ethanol plant to an isobutanol plant in Luverne, Minnesota.

Hydrocarbon Processing | SEPTEMBER 2012 79

Refining Developments equivalent basis (isobutanol contains more energy than ethanol). Therefore, the utility requirements and OPEX are comparable to ethanol production (which, again, limits CAPEX requirements).

There is over 20 billion gpy (Bgpy) of existing fermentation ethanol capacity in the world, located mostly in North and South America. A leading company in bio-isobutanol is converting some of these ethanol plants to isobutanol production.

That company’s business model is based on the flexibility to buy ethanol plant assets, form a joint venture with the current plant owner for the conversion, or to license the isobutanol production technology to ethanol plant owners.

FIG. 1 illustrates an isobutanol plant conversion. The “before” photo shows a facility in Luverne, Minnesota as a 22-MMgpy ethanol plant. The “after” photo depicts the plant as it was repurposed to produce up to 18 MMgpy of isobutanol.

applications, isobutanol can be blended as a low-vapor-pressure gasoline component and/or used as feedstock to make other transportation fuels (e.g., iso-paraffinic kerosine for use as biojet) or other renewable products (e.g., renewable heating oil).

Bio-isobutanol as a gasoline blendstock. Bio-isobutanol’s

Ethanol

Isobutanol

Alkylate

properties as a gasoline blendstock can best be understood by comparing some of the blending properties to ethanol and alkylate. TABLE 1 summarizes some key aspects in the comparison.

Compared to ethanol, isobutanol has a much lower Reid vapor pressure (RVP) and about a 30% higher energy content. The blend octane of isobutanol is high as well (although slightly lower than ethanol). Isobutanol also has a lower oxygen (O2 ) content than ethanol, so more isobutanol can be blended into gasoline for a given O2 content. Greater blend volume, plus higher energy content, means more renewable identification number (RIN) generation. See TABLE 2 for a RIN comparison summary.

Unlike ethanol, which is fully miscible in water, isobutanol has limited water solubility (about 8.5%). Isobutanol also does not cause stress corrosion cracking in pipelines. These factors result in major advantages in terms of blending logistics. Isobutanol can be blended as a drop-in renewable fuel at the refinery and shipped in pipelines to fuel terminals via existing infrastructure, which prospectively eliminates the need for segregated tankage or pipelines. This also affords refiners the opportunity to once again produce a finished-specification gasoline vs. a sub-octane blendstock for oxygenate blending.

Isobutanol overcomes the regulation “blend wall” limitation of ethanol blending. Isobutanol blended into gasoline up to 12.5 vol% produces a substantially similar gasoline at a 2.7% O2 content. For refiners, this is a conservative first step for blending, and it generates 16.25 RINs per gallon of finished product.

E10 has 3.5 vol% O2 , which is the currently accepted limit of O2 content by automobile engine manufacturers. For this same 3.5 vol% O2 , a US Environmental Protection Agency (EPA) waiver (211b) exists that would potentially allow isobutanol blending of up to 16.1 vol%, yielding 20.93 RINs, or more than twice the number of RINs as E10 for an equivalent O2 content.

112

102

95

Bio-isobutanol can be an advanced biofuel. To account

18–22

4–5

4–5

for the relative amounts of renewable energy benefit, each biofuel generates a RIN based on its energy content. There are basically four types of RINs: renewable (e.g., first-generation, cornbased ethanol), biomass-based diesel, cellulosic and advanced.

Feedstock. One company’s proprietary fermentation process

is designed to convert feedstocks of all types: grain, sugarcane, cellulose and/or nonfood-based materials. Almost anything that can be converted into a fermentable sugar can be used, whether it is a traditional C6 sugar, such as glucose, or a C5 sugar, such as pentose. The issue of feedstock selection is one of economics, but technology can be put into yeasts to allow them to digest C6 or C5 sugars. In fact, at bench scale, these yeasts have produced cellulosic isobutanol using a mixed stream of C5 and C6 sugars.

Bio-isobutanol has versatility. One of the main reasons that converted plants have such good projected economics is that bio-isobutanol is versatile as a platform molecule. In the chemicals arena, it can be sold as a solvent product (e.g., paints) and/ or converted into materials such as butyl rubber, paraxylene (PX) and other derivatives for use in market applications such as tires, plastic bottles, carpets and clothing. (This conversion is accomplished through dehydration to isobutylene.) For fuels TABLE 1. Gasoline blendstock comparison: Ethanol vs. isobutanol

Blend octane (R + M) ÷ 2 Blend RVP (psi)

34.7

21.6

0

Net energy (% of gasoline)

65

82

95

Fungible in infrastructure

No

Yes

Yes

O2 content

2.5

TABLE 2. Gasoline blend RIN generation summary

O2 content

E10

10%

3.5%

10

E15

15%

5.2%

15

Isobutanol (substantially similar to gasoline)

12.5%

2.7%

16.25

Isobutanol (EPA waivers allowing O2 content of 3.5 wt%)

16.1%

2.0 Million barrels per day

Volume in gasoline

RIN-gal per 100 gal of finished product

1.5 1.0 0.5 0.0

3.5%

80 SEPTEMBER 2012 | HydrocarbonProcessing.com

20.93

Domestic ethanol Brazilian ethanol Biodiesel Pyrolysis oil, FT liquids, green diesel EISA renewable EISA advanced

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Year

FIG. 2. Projected RIN-gallons vs. EISA targets.

Refining Developments Advanced RINs are generated with the production of advanced biofuels with an approved US EPA pathway (i.e., rated as having at least a 50% reduction in greenhouse gas footprint vs. baseline hydrocarbon fuel). Since bio-isobutanol has a higher energy content than ethanol, bio-isobutanol generates 1.3 RINs per gallon, vs. first-generation ethanol’s 1.0 RINs per gallon. In addition, whereas today’s corn ethanol is precluded from qualifying as an advanced biofuel, bio-isobutanol—produced with a green energy source (e.g., biomass-fired combined heat and power) has the potential to qualify for advanced RIN status.

FIG. 2 summarizes the US Renewable Fuel Standard (RFS) projected gallons for implemented renewable and advanced biofuels, as compared to the requirements stated by the US Energy Independence and Security Act (EISA) of 2007. As can be seen, there is a projected shortfall of advanced biofuels.

Bio-isobutanol offers some flexibility for meeting the RFS2 targets with domestically produced renewable fuels, as opposed to relying on sugarcane ethanol imports from Brazil, which is the main biofuel pathway currently approved by the EPA for advanced status.

Bio-isobutanol as renewable feedstock for biojet. Tak-

ing the bio-isobutanol and processing it further to isoparaffinic kerosine (IPK) biojet has been demonstrated at a hydrocarbon plant in Silsbee, Texas. The process is outlined in FIG. 3.

Producing IPK biojet from bio-isobutanol involves three sequential steps: 1. Dehydration of the renewable isobutanol to isobutylene 2. Oligomerization of the isobutylene to mostly trimers/ tetramers to produce C12 and C16 molecules 3. Hydrogenation of olefins to IPK biojet.

These processes present opportunities for retrofits of existing, underutilized refining/petrochemical assets, in some cases. Commercialization and integration into an existing process plant should be straightforward.

Depending upon economics, the overall process also has the flexibility to make more or less isooctene and/or isooctane product streams, which make good renewable gasoline blending components. It should be noted that both renewable gasoline blendstocks (isobutanol and isooctene) are not tied to crude oil processing, so these are not likely to have crude oil volatility effects. Again, isobutylene, isooctene and isooctane can also be drawn off for the production of other renewable petrochemical products (e.g., PX).

This biojet process has been demonstrated in a small (10,000-gallon-per-month-capacity) unit for several months.

The alcohol-to-jet (ATJ) product has been sold to the US Air Force as part of the Alternative Fuels Certification Office (AFCO) process. FIG. 4 shows a picture of the demonstration plant in Silsbee, Texas.

Therefore, idled semi-regenerative reformers are possibilities for retrofits to develop the dehydration step. The catalyst for the dehydration has been fully commercialized in similar applications.

The dehydration reaction can be efficiently designed to almost complete conversion, minimizing the downstream complexities of the separation of the butylene and water, and the effluence of the water.

It should be noted that isobutylene can be a hydrocarbon feedstock for other refining and petrochemical processes.

Since the isobutylene is renewable, any resulting RINs would carry forward to any hydrocarbon product covered by RFS2.

Oligomerization. Step 2 is the oligomerization of the isobutylene to dimers (isooctene), trimers (C12 olefins) and tetramers.

There is some measure of flexibility in the amount of each olefin produced. Since IPK jet fuel primarily requires C12–C16 olefins, dimers are recycled to yield more trimer/tetramer product.

Oligomerization is an exothermic reaction, with operating conditions, heats of reaction, and catalysts that closely resemble MTBE production units and/or catalytic polymerization units; these units are possible retrofit candidates for this oligomerization step. In fact, after MTBE was banned in the US, many MTBE units were converted to make isooctene (dimer).

These units could be used with a minor retrofit. Depending upon economics, the dimer could be used for gasoline blending and/or further processing options.

Hydrogenation. Step 3 is the saturation of the olefin product from the oligomerization section. This is also a well-known and practiced operation in refineries and petrochemical plants.

The main reaction is the conversion of the trimers/tetramers to IPK. The operating conditions are mild, and they have relaIsooctene (if desired)

Isobutanol

Dehydration

Isobutylene

Oligomerization

Isooctane (if desired)

Hydrogenation

IPK

Hydrogen

FIG. 3. Isobutanol-to-IPK jet fuel process flow diagram.

IPK process steps. There are three steps in the IPK produc-

tion process.

Dehydration. Step 1 is the dehydration of isobutanol to isobutylene and water. The reaction is endothermic, with a relatively low operating pressure (< 200 psig) and temperatures of around 550°F–650°F. The operating requirements are similar to semi-regenerative catalytic reforming—older technology that has since been upgraded in refineries and petrochemical plants.

FIG. 4. IPK biojet demonstration plant.

Hydrocarbon Processing | SEPTEMBER 2012 81

Refining Developments tively low operating pressure and temperature, and modest space velocity requirements. The hydrogenation reaction is exothermic and occurs with hydrogen consumption in the process, so some recycle and cooling design details are correlated with the reactor bed design to ensure proper heat removal and control of the reaction.

Olefin hydrogenation is well-known and practiced, so there may be an opportunity to retrofit existing assets, since lowerpressure hydrogenation units have been idled as hydrogenation requirements have become more severe. The operations learning curve is somewhat established already, as per catalyst preparation, unit startup, normal plant operations, etc.

Return on investment, % rate of return

40 35 30 25 20 $2.60 jet $2.80 jet $3.00 jet $3.20 jet $3.40 jet

15 10 5 0 1.10

1.20

1.30

1.40

1.50 1.60 1.70 1.80 Isobutanol advanced RIN value, $

1.90

2.00

2.10

FIG. 5. Biojet plant financial summary analysis.

Source: Mustang Engineering

Biojet properties. IPK biojet has some properties that en-

hance its value. The freeze point is low (–80°C), while oxidation stability is high. Starting from isobutanol, a renewable IPK would also generate RINs at the rate of 1.6 per gallon, based on the process. The current specification limit for a jet fuel blend with synthetic blending components is a maximum of 50%. For a 1:1 blend with petroleum jet fuel, 80 RINs are generated for every 50 gallons of IPK that are used to produce 100 gallons of blended jet product.

Scoping economics of biojet. One important aspect of understanding how bio-isobutanol can be a versatile alternative biofuel is the nominal economic incentive for its conversion to jet fuel. Preliminary scoping economics were developed for making biojet from renewable isobutanol feedstock. Although a retrofit of existing units would help the economics, retrofits are not possible in all cases. Therefore, a new unit was used as the basis for this scoping evaluation.

In addition to CAPEX and efficiencies associated with the possible retrofit of some existing assets, the other sensitivity in scoping economics is the value and use of established RIN and other tax credit incentives, as allowed.

The CAPEX throughput basis was a nominal 3,000-barrels-per-stream-day (bpsd) grassroots plant. The unit was assumed with all new equipment (no retrofit or surplus or idled equipment). All inside-battery-limit (ISBL) equipment was sized, specified and budget-estimated. The CAPEX was

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Refining Developments determined by applying factors to the equipment pricing to account for commodity materials and labor. Allowances were also made for engineering, escalation and contingency. A 30% allowance for offsites was assumed and added.

For the jet fuel price basis, a relatively conservative $2.60–$3.40-per-gallon price range was assumed, although the price could be higher. Sensitivities for this price range were included in the scoping economic study.

With the advent of the jet fuel carbon tax on international flights landing in the EU, the airline industry and fuel suppliers have been looking for cost-effective, renewable alternatives to petroleum jet fuel. A scoping sensitivity examining this tax credit is shown in FIG. 5.

Fuels markets Low-carbon gasoline, jet or diesel

Corn Isobutanol retrofitted ethanol plant

Sugarcane

Isooctene or C12

Agricultural residue

As can be seen, the EU tax credit has a significant effect on the scoping economics. As one might expect, the RIN value also has a considerable impact. In summary, this nominal 3,000-bpsd biojet plant study illustrated some positive scoping economics, even at conservative jet fuel prices.

Bio-isobutanol for renewable PX for PET. Once the renewable hydrocarbon is made, there is the chance to make renewable hydrocarbon products via traditional or even newer processes. One new process uses isooctene to make PX, which then can be made into purified terephthalic acid (PTA), and then into renewable polyethylene terephthalate (PET) via traditional methods.

A pilot plant is being designed for this new process, which yields PX at a very high selectivity vs. other xylenes. High selectivity eliminates the need for xylene isomerization, separation and recycle steps. Additionally, the PX can be integrated with the rest of the biofuel plant, as shown in FIG. 6. Depending on the relative amounts of each renewable product, even the hydrogen made in the PX plant can be used in the biojet hydrogenation unit.

Paraxylene Chemicals markets

Wood FIG. 6. Bio-isobutanol to paraxylene, gasoline blendstock and/or biojet.

Takeaway. Isobutanol has gasoline blending, chemical and usage advantages vs. ethanol, which result in positive economics for the conversion of existing ethanol facilities to bio-isobutanol production. Compared to other transportation fuel blendstocks, bio-isobutanol is a better environmental alterna-

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Refining Developments tive (e.g., low vapor pressure, meaning lower volatility in finished fuel). Also, being made by fermentation of sugars (via normal or cellulosic biomass), these renewable fuels are not tied to crude oil prices or to petroleum supply fluctuations.

The process configuration for bio-isobutanol to IPK biojet fuel involves three sequential, straightforward steps. The process operates at moderate operating conditions, and it is similar to some existing refinery and petrochemical units that have been idled or underutilized. Revamps are possible, and they would reduce the CAPEX and construction time. Projected RIN values and EU carbon tax incentives would provide additional upside on the project economics. This three-step process has been demonstrated at a 10,000-gallon-per-month-capacity hydrocarbon plant in Silsbee, Texas. On-spec product is being made and sold to the US Air Force for the military certification process.

Bio-isobutanol has numerous process and product platforms that can be employed as economics dictate. These include, but are not limited to, solvent sales, use as a gasoline blendstock, conversion to biojet or use as a feedstock for renewable PX. Bio-isobutanol has the versatility to allow multiple options at the same time. For example, marine and small-engine fuels are niche options that can be addressed.

Renewable diesel is another option.

The pathway for bio-isobutanol via fermentation has been established, and the business model makes economic sense to revamp idled or underutilized fermentation ethanol plants.

One company’s production of bio-isobutanol at demonstration scale was proven in 2009. More recently, a commercialscale, 18-MMgpy plant was started up.

Furthermore, bio-isobutanol has versatility and environmental and economic advantages when compared to ethanol.

Bio-isobutanol has the capability to provide significant impact as an advanced gasoline blendstock, or as a feedstock to make other advanced fuels or products; therefore, it should be considered a high-potential, next-generation biofuel.

RICK KOLODZIEJ is a process technology manager at Wood Group Mustang.

He has over 30 years of experience in process and project engineering and development in the refining, petrochemicals, chemicals, polymers and gas processing industries. Mr. Kolodziej has been involved with several new technology development projects, including several bio-related projects.

Most recently, Mr. Kolodziej was involved with Gevo’s projects in renewable isobutanol and various petrochemicals. He is also responsible for process plant project development for Wood Group Mustang in the Far East. Mr. Kolodziej has US and international patents in hydrotreatment technology. He holds a BS degree in chemical engineering from the University of Illinois (Chicago) and an MBA degree in finance from DePaul University, and is a registered professional engineer in the state of Illinois.

JEFF SCHEIB is vice president for fuels at Gevo Inc., overseeing sales, marketing and business development activities for isobutanol-into-fuels markets, including refining, biojet, gasoline distributors and marketers, marine and small-engine applications. He has over 20 years of fuels and biofuels leadership expertise, having worked 17 years within the petroleum sector with ARCO and BP, followed by four years in the renewable energy arena with Cilion and Chromatin, prior to joining Gevo in 2011. Jeff holds an MBA degree from the University of California (Los Angeles) and a BS degree in industrial engineering from Northwestern University.

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Special Report

Refining Developments X. PRICE, C. TERAN, A. VANHOVE and J. CASANOVA, GE Water & Process Technologies, The Woodlands, Texas

Successful fouling control hinges on effective monitoring Equipment reliability, processing flexibility and energy conservation are key objectives for modern refineries. Refiners today are routinely using lower quality, more difficult to process feedstocks that offer favorable economic incentives. Unfortunately, along with their lower cost, many of these challenging crudes often come with a significant increase in fouling potential.

Fouling can result in severe economic penalties, from throughput reductions to complete unit shutdown, as well as increased energy consumption, lost opportunities, and significant safety and environmental concerns. Some of the typical problem areas include: • Crude unit preheat exchangers and furnaces • Hydrotreater exchangers, reboilers and reactor beds • Fluid catalytic cracking unit (FCCU) slurry exchangers • Thermal cracking process exchangers, reboilers and furnaces.

For decades, chemical treatment programs have been used effectively to help reduce fouling of heat exchange systems throughout the refinery.1 The benefits of such programs were once difficult to demonstrate due to limitations in monitoring and program justification. Now, with advanced monitoring techniques, improved analytical tools and extensive experience around the globe, chemical suppliers are better prepared to document improvements in refinery profitability and operational flexibility directly related to customized, cost effective, fouling control programs.

Factors that impact fouling. Multiple factors can impact fouling, including equipment design, heat flux, velocities, flow rates, feed quality, temperatures and cracking severity. Other common practices such as caustic addition can impact crude preheat and coker furnace fouling. Because of the many interrelated factors involved, each process unit and fouling control program is unique. Fundamental analytical tools and vital monitoring techniques have been developed to identify, predict and track process fouling, as well as categorically quantify the impact and economic benefits of a chemical treatment program.

The selection and design of a successful solution relies on tools specifically developed to identify the root cause and quantify the impact of the fouling problem.

Deposit analysis. Deposit samples are taken during equipment openings, before high pressure jetting or any other remediation steps are initiated. Care should be taken during sampling to ensure that an average composition is obtained, unless analysis of localized deposition is needed. The shutdown pro-

cedure, prior to equipment opening, should be clearly defined (such as rinsing or steam-out) in order to provide the correct interpretation of the analytical results.

A thermographic analysis of the deposit will determine the percentage of organic and volatile inorganic components, as well as the ash level remaining. A methylene chloride extraction is also typically done to identify the entrained hydrocarbon and degraded oil fraction in the sample. The non-extractable components represent mainly the coke and inorganic fraction of the sample. Metal analysis (Fe, Na, Ca, Mg, Cu, etc.) and elemental analysis for C, H, N and S are also conducted. The deposit analysis can indicate whether the major foulant is inorganic, organic, or a combination. In addition, calculation of the mass ratio of hydrogen to carbon in the sample will give a more specific indication of the organic nature of the sample (coke vs. polymer vs. paraffins).

Feedstock characterization. A feedstock can be analyzed to identify fouling precursors that are associated with a specific fouling mechanism.2 The feed analysis is tailored to the type of fluid. Various tests are performed to determine the specific characteristics of each feedstock. These characteristics can include physical properties, salts, filterable solids, asphalthenes, sulfur, mercaptans, basic nitrogen, total acid number, bromine number, carbonyls, pyrrole nitrogen and metal levels.

Pressurized hot-wire test. A relatively rapid method to evaluate the efficacy of different anti-foulant products is the pressurized hot wire test (FIG. 1). The feedstock sample is equally divided into several sample cells. An electrical resistance wire is then submerged in the fluid. The sample cells are N2 supply

P Power supply

Blank

Treatment A

Treatment B

Treatment C

FIG. 1. Pressurized hot-wire tester.

Hydrocarbon Processing | SEPTEMBER 2012 87

Refining Developments pressurized and the wire is then electrically charged. While the testing time typically remains constant, the electrical charge is adjusted according to the fouling tendency of the fluid.

Four tests can be conducted simultaneously under the same conditions, including an untreated blank sample. Both the wire deposit and the solids formed in the fluid are compared relative to each other for quantity and nature. FIG. 2 shows a picture of the wires after the test, and clearly illustrates the efficacy differences between the treated samples and the blank.

Hot liquid process simulator. A dynamic test device known as the hot liquid process simulator (HLPS) (FIG. 3) can be used in different operating modes, simulating a heat exchanger or furnace heat transfer problem. It can even be used to simulate a hydrotreater reactor pressure drop problem.

A schematic is shown in FIG. 3. The fluid is circulated through a test exchanger at a controlled flowrate. An electrically heated core provides the required heat to simulate the process. The inlet temperature is monitored, and, depending if the core or

FIG. 2. Wires after pressurized hot-wire test.

Purge

Monitoring techniques. The development and selection of

N2 pressure Temperature logging control

P

outlet temperature is controlled, the outlet or core temperature, respectively, is also monitored to evaluate the fouling rate.

Different treatment programs can be evaluated as shown in FIG. 4. FIG. 5 illustrates two cores with different deposits.

Asphaltene stability. An optical scanning device is available to help determine the asphaltene precipitation tendencies of any crude or crude blend. The device incorporates the industry standard test method, ASTM D7061-06.3 ASTM D7061-06, designed to measure asphaltene stability, is, in fact, similar to the titration based methods, as all these methods provide a measure of the reserve capability of a crude blend, in terms of resistance to asphaltene precipitation.

It makes 16 separate scans across the sample and the software records transmittance (FIG. 6) and backscatter every 40 µm (micrometer) while moving across the scan window.

The standard deviation of the average transmittance value of each scan between the scanning heights of 10 mm to 55 mm is calculated for the dataset of each sample. This value is the separability number (FIG. 7). The testing device provides robust information over a wide variety of hydrocarbon fluids.

It offers a very rapid means of identifying and monitoring fluid stability and other indicators of fouling propensity. By looking at the stability index for various crude blends, highly nonlinear blending behavior can be rapidly determined with small sample volumes. Crude stability, or the lack thereof, is known to cause fouling in crude preheat systems, furnaces and tower bottoms.

Electrical power supply

appropriate monitoring techniques, specific to each heat exchange system, is a crucial component of any successful antifoulant program. It is imperative that a “current performance” base case is established, and that metrics are identified to evaluate the ongoing performance of the treatment program and to quantify its benefits. The accuracy and availability of

Sample reservoir

Circulation lines (heated) Controlled circulation pump

FIG. 3. HLPS simulator schematic.

340 Outlet temperature, °C

320 300 280 260 240

Blank Treatment A Treatment B

220 200

0

20

40

Treatment C Treatment D 60

80 100 Time, minutes

120

FIG. 4. Crude preheat fouling simulation test .

88 SEPTEMBER 2012 | HydrocarbonProcessing.com

140

160

180

FIG. 5. HLPS fouled rods.

Q

Customer:

Q

Challenge:

Q

Result:

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Refining Developments process data can significantly impact the selection of monitoring techniques. Ideally, the appropriate techniques should be identified and then the needed data made available. However, in real world situations, this is not always the case. Not having a suitable monitoring program should not be an option.

To illustrate the complexity of heat transfer monitoring and evaluation, the following section focuses on the challenges specific to crude preheat exchangers. The basics outlined can typically be applied to all refinery heat transfer equipment.

Three direct indicators of heat exchanger train performance are the furnace inlet temperature (FIT), throughput and pressure drop. The process conditions change so often that comparing the actual measured furnace inlet temperatures is not

FIG. 6. Percent transmittance as a function of sample tube length.

representative, and a normalization technique is required to evaluate the performance of a treatment program.

A unit survey is required to collect the necessary information to define the appropriate monitoring and calculation methods.

This survey should provide the thorough system configuration and exchanger mechanical data with indications of the available flow and temperature measurements and their locations.

Techniques such as multiple regression analysis (MRA) and statistical process control (SPC) are used to evaluate the overall heat train performance without detailing each individual exchanger. The same techniques can be used to evaluate the pressure drop over an exchanger train, reboiler or reactor bed, in addition to other equipment.

The MRA/SPC technique is used to generate a mathematical model using a baseline period and the key operational parameters that impact a key performance indicator (KPI). The generated model provides the means for normalization of the data to a standard set of operating conditions, thus providing the ability to isolate the impact of various parameters on the KPI (FIG. 8).

Statistical process control limits are then established (at +/– 3 standard deviations) to account for the standard error of the model and to categorically validate the certainty of model predictions and actual observations at a confidence level of 99.73%. The resultant MRA/SPC control chart is also used as a KPI monitoring tool, providing for early detection of deviations from expected or predicted behavior requiring specific actions.

It can then also be used to confirm and quantify the effects re-

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Refining Developments sulting from those actions (e.g., extending run length). The implementation of this monitoring tool will clearly demonstrate whether or not the proposed solution was successful (FIG. 9).

Rigorous network modeling is another way to effectively calculate the actual status of each individual exchanger and recalculate the (normalized) furnace inlet temperature (NFIT) under standardized conditions (FIG. 10). The model also performs simulation calculations to define the optimum cleaning program and to calculate the impact on the whole train if selective exchanger cleaning was applied. The model uses the actual plant data to check the heat balance per exchanger and over the whole train. Data corrections can be applied to ensure that the adiabatic nature of heat transfer in heat exchangers is respected, and that consistent, accurate data is used for the calculations.

The fouling factors and heat transfer coefficients are also calculated per exchanger. Comparing the NFIT for a treated and untreated run period will quantify the performance of the chemical treatment, where the fouling rate or slope of the NFIT curve is compared during both runs (FIG. 11).

Raw crude blend

1.13

Tank 1 Tank 2

Key to long-term success. Fouling of refinery process equipment results from a number of different interrelated variables, including unique fluid characteristics, operating practices and unit configurations, as well as ever changing operational parameters, primarily temperatures and flowrates.

Regardless of the cause, process fouling exacts significant economic and operational penalties. Without the implementation of the appropriate tools needed to understand, quantify and monitor the fouling phenomena, even the best designed solution is bound to fail.

Prior to the start of a chemical treatment program, a representative base case must be established, and clear objectives and well defined criteria for success must be agreed upon.

5.51 0.31

Blend 1

7.34

Blend 2

FIG. 10. Rigorous modeling—NFIT vs. throughput variation.

8.08

Blend 3

0.55

Blend 4

0.59

Blend 5

0.66

Blend 6

0.72

0–5 stable

5–10 medium instability

> 10 high unstability

» www.dresser-rand.com

Q, MMBtu/day

FIG. 7. Separability number (an indicator of asphaltene instability).

1,700 1,650 1,600 1,550 1,500 1,450 1,400 1,350

Actual Model Normalized Corrected 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 Time

Q corrected, MMBtu/day

FIG. 8. MRA model for a crude preheat train.

1,660 1,640 1,620 1,600 1,580 1,560 1,540 1,520 1,500

Treated performance

UCL

Treatment starts

LCL Untreated model projected performance

Untreated performance Time

FIG. 9. MRA/SPC control chart (treated vs. untreated).

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Refining Developments 255

NFIT, °C

250

Turn it on now!

Treated

245

Savings

240

Untreated

235 230

0

2

4

6 Months

8

10

12

FIG. 11. Treatment savings (no cleaning).

Appropriate monitoring tools must also be put in place to track actual performance against the base case and to respond to potential deviations of key performance indicators.

LITERATURE CITED ASTM D7061-06, “Standard test method for measuring n-heptane induced phase separation of asphaltene containing heavy fuel oils as separability number by an optical scanning device,” www.astm.org/Standards/D7061.htm.

2 Wilson, R. M. and J. J. Perugini, “Antifoulants: A proven energy-savings investment,” NPRA AM-85-52, The Woodlands, Texas.

3 Fields, D. E., R. F. Freeman and B. E. Wright, “Predicting crude oil fouling tendency,” Texas Energy Progress (Vol 8, No. 4).

4 Groce, B. C., “Chemical, mechanical treatment options reduce hydroprocessor fouling” Oil & Gas Journal, January 29, 1996.

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XIOMARA PRICE is a senior application specialist at GE Water & Process Technologies focused on fouling control. She has over 14 years of process and water chemical treatment application experience in the hydrocarbon processing industry. Her areas of expertise include heat transfer and fouling control, process chemical applications, phase separation and corrosion control.

Mrs. Price holds a BS degree in chemical engineering from Louisiana Tech University.

CONRAD TERAN is a refining technology senior technical manager for GE Water & Process Technologies. He is responsible for the troubleshooting, analysis and resolution of challenging technical issues in the hydrocarbon processing industry. His specialty areas include heat transfer, fouling, phase separations and the implementation of neural networks, multiple regression analysis and statistical process control for process modeling, optimization and control. He has over 33 years of oil refining and upgrading experience. Mr. Teran has a BS degree in chemical engineering from Brigham Young University in Provo Utah, and a master of engineering degree in chemical engineering from Lamar University in Beaumont, Texas. He is a registered professional engineer in the state of Texas.

ANDRE VANHOVE is the hydrocarbon process product application manager at GE Water & Process Technologies, where he leads the Europe, Middle East and Africa and AsiaPacific product application teams. Mr. Vanhove has over 30 years of experience in the refining and petrochemical industries.

He is leading global business development opportunities in the refinery industry and has developed specific expertise in visbreaking process enhancement applications. He is also co-author of several technical papers and patents. Mr. Vanhove has an industrial engineering degree in chemical processes from the Institute De Nayer in Mechelen, Belgium.

JUVENCIO CASANOVA has over 15 years of commercial experience in the water and process treatment business.

Mr. Casanova has an MBA degree from Texas A&M and a BS degree in chemical engineering from Simon Bolivar University.

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| Bonus Report HEAT TRANSFER DEVELOPMENTS The hydrocarbon processing industry (HPI) is an energy-intensive business.

Following feedstock costs, energy (heating and refrigeration) is the secondlargest operating cost center for HPI facilities. Heat exchangers are common heat-transfer equipment used throughout refineries, petrochemical facilities and liquefied natural gas (LNG) complexes. The design and maintenance of exchangers and other heat-transfer equipment dramatically impacts facility operating costs and product quality as discussed in this monthâ&#x20AC;&#x2122;s Bonus Report.

A new exchanger is being readied for transport. Photo courtesy of Walter Toasto, a world leader in the production of heavy-wall static and heat-transfer equipment for the oil, gas, power and petrochemical markets. The main fabrication facilities are located in Chieti Scalo, Italy.

Bonus Report

Heat Transfer Developments J. CAZENAVE, Aspen Technology Inc., Reading, UK

What are the benefits of rigorous modeling in heat exchanger design?

Today, process engineers are responsible for many project activities, including conceptual design, revamp studies and operational troubleshooting. Increasingly, the process simulator is an essential tool central to these activities. Process simulators are very powerful tools for modeling all or parts of a process.

While they are excellent for general-purpose process modeling, it is the process engineer’s responsibility to understand to what extent these tools can be applied, and how combining their application with more specialized tools might be appropriate. This choice is ultimately based on the business and technical objectives to be achieved.

This article examines three different applications where rigorous heat exchanger models can enhance value derived from process simulation and provide more accurate results. These applications include conceptual designs of new plants, revamps of existing facilities, and operations support.

Conceptual design. One of the key responsibilities of the

process engineer is related to the conceptual design of processes. With conceptual design, the use of process simulation is central to project activities. The initial stages of conceptual design consider the main process synthesis and separation operations required to convert feedstocks to products. At this early stage, the process flowsheet typically involves simplified models of reactors, distillation columns, and the heating and cooling services required to facilitate the essential parts of the process. At this stage, the type and design of equipment required, for example, to preheat reactants before they enter a reactor, are less important. The traditional functionality of process simulation in providing heat and mass balance over the conceptual process is paramount.

As the conceptual design evolves, it becomes important to take account of the actual equipment involved. The reactors, separators and heat exchangers need to be evaluated to further develop their designs to ensure desired performance; to size them adequately; and to obtain estimates of the capital cost of the process, the heating and cooling utility requirements and the energy cost to operate the process. Heat transfer equipment can typically be up to 30% of the capital cost of process equipment. Therefore, as the process design progresses, it is important to take account of the real design requirements for the major heat transfer equipment items. For any heat exchanger, two main aspects must be considered: • How much duty does the heat exchanger need to provide?

• How much pressure drop can be consumed?

The first aspect can be modeled by a simple equation: Q = m (ho – hi )

(1)

where Q is the rate of heat transfer, m is the mass flow, h is specific enthalpy, and the subscripts o and i refer, respectively, to outlet and inlet. Where there is no phase change, this can be expressed as: Q = m Cp (To – Ti )

(2)

where Cp is the specific heat of the fluid, and T is the temperature.

Consider the following simple example, where a water/water exchanger has been modeled with one side heating up from 20°C to 90°C, while the other side is cooling down from 90°C to 20°C (FIG. 1).

However, if the exchanger must be designed to determine how much surface it will require, the basic heat transfer equation (for pure counter-current flow) must be considered: Q = UA ⫻ LMTD

(3)

where U is the overall heat transfer coefficient, A is the effective area in the heat exchanger, and LMTD is the logarithmic mean temperature difference.

If a generic heat exchanger is assumed to have two ends (here referred to as “A” and “B”) at which the hot and cold streams enter or exit on either side, then LMTD is defined by the logarithmic mean, as follows: LMTD = (ΔTA − ΔTB ) ÷ [ln (ΔTA ÷ ΔTB )]

(4)

FIG. 1. Water/water exchanger model showing one side heating up and one side cooling down.

Hydrocarbon Processing | SEPTEMBER 2012 95

Heat Transfer Developments where ΔTA is the temperature difference between the two streams at end A, and ΔTB is the temperature difference between the two streams at end B. In this case, the LMTD will have a limit of 0, so it will need a UA with an infinite limit.

The second aspect to consider for any real equipment is the pressure drop that will be consumed on the hot and cold sides as the respective streams flow through the heat exchanger.

It is normal for the process engineer to designate how much pressure drop will be allocated to a particular exchanger. For example, in turbulent flow inside tubes, the local heat transfer coefficient varies approximately with the mass velocity raised to the power 0.8. The pressure drop varies approximately with the mass velocity squared. This means that, if pressure drop is kept low, the heat transfer coefficient will be very low, and a large surface area will be needed for the heat exchanger. A realistic pressure drop must be estimated at this stage to enable the design of the heat exchanger later without having to rework the process design.

A more realistic way to model the exchanger is to assume that one side of the exchanger is between 90°C and 25°C, with the other side heating up from 20°C to 85°C. Both sides have a pressure drop of 0.5 bar (FIG. 2).

FIG. 2. Heat exchanger model showing one side heating up and one side cooling down.

This type of idealized approach is often used to model an exchanger where a process stream is heated by utility steam in a heat exchanger. Pure fluids, like steam, condense isothermally at constant pressure. If isothermal condensation is present, then EQ. 3 can be applied to good effect; however, in reality, any pressure drop on the steam side will result in a lower saturation temperature, and then the exit temperature will be lower than the inlet temperature.

The main issue with this approach is that it is easy for the process engineer to specify conditions that later make it difficult to achieve a practical exchanger design. This hampers effective collaboration between process engineers and thermal design specialists, resulting in additional cycles of engineering to refine the overall process and equipment designs.

One way to promote better collaboration between disciplines and achieve better designs quickly is to use a rigorous exchanger modeling tool within the process simulation to achieve a preliminary design. This approach enables the process engineer to get a better first approximation for evaluating the feasibility of the process, and to give the thermal specialist a useful starting point for full design optimization. Where this technique is employed, it has been shown to reduce project schedules and eliminate costly rework.

Revamp studies. The second type of project where rigorous heat exchanger modeling can improve the engineering workflow is a revamp. Typically, revamp projects have two main aspects. First, there is a check that the actual proposed equipment in the process is accurately simulating the plant performance data. Secondly, “what if ” options can be explored for process and capital improvements, with different equipment geometries and stream sequencings validated against the revamp’s performance objective.

Modeling an existing exchanger can be easy if plant data is available. The process simulator allows the specification of process conditions for the exchanger. This, in turn, allows simple modeling of an exchanger based on EQ. 3, and it enables the simulator to estimate the exchanger duty. The inherent assumption is that UA will remain constant. The pressure drop will not be recalculated by the simulator, so any variation will need to be estimated with a manual calculation. As mentioned earlier, for single-phase turbulent flow inside tubes, the local heat transfer coefficient will vary according to:

␣ = f (m0.8 )

FIG. 3. Revamp study of an exchanger in a crude preheat train.

96 SEPTEMBER 2012 | HydrocarbonProcessing.com

(5)

where ␣ is the local tube-side heat transfer coefficient, and m is the mass velocity in the tubes. This indicates that, as the flow of either stream in an exchanger is varied, the simple modeling of the simulator will result in an error in the estimated duty of an exchanger. Change in steam properties will also be unaccounted for in this simple modeling approach.

In the following example, the first exchanger downstream of the desalter in a crude preheat train is subject to examination in a revamp study where the overall aim is to recover more pumparound energy and increase the throughput of the refinery (FIG. 3). The first step is to model the existing exchanger. The crude on the tube side of this exchanger is focused on in TABLE 1.

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Heat Transfer Developments TABLE 1. Modeling data for a heat exchanger in a crude preheat chain Error

Design conditions

New conditions

Pressure drop, bar

Temperature drop, °C

Pressure drop, bar

Temperature drop, °C

UA

0.6

39.4

Rigorous model

0.59

39.7

−1.7%

0.8%

UA

0.6

33.8

Rigorous model

0.79

35.1

24.1%

3.7%

Revamp

0.59

33.7

−1.7%

−0.3%

than 20% for the pressure drop. The rigorous modeling shows that the pressure drop increased to a value higher than the limit of 0.6 bar defined in the process. After the revamp and a redesign of the heat exchanger, it is possible to calculate the pressure drop for the rigorous model below the limit of 0.6 bar.

The rigorous modeling of the heat exchanger is needed to check the performance with new process conditions and to properly design a revamped heat exchanger. The integration of rigorous modeling inside the simulator allows the engineer to check the anticipated heat exchanger performance and take any corrective design actions without leaving the simulator environment.

FIG. 4. Water-cooled exchanger on a gas compression system.

FIG. 5. Rigorous simulation for a water-cooled exchanger.

The first two columns are the values of the pressure drop and the temperature changes on the tube side of the exchanger. The last two columns represent the difference between the simple UA modeling and the rigorous modeling approaches.

In the first set of process conditions, the rigorous model and UA model values are close. This is expected, since the UA model is based on the result of the rigorous calculation performed during the design stage. However, when the process conditions change, the UA model and rigorous model diverge, with the relative difference increasing from less than 1% to more than 3% for the temperature drop, and from less than 2% to more 98 SEPTEMBER 2012 | HydrocarbonProcessing.com

Operation support. In this case study, an existing exchanger on a gas compression system is water-cooled. The process is modeled with a control operation that simulates the adjustment of the water flow to achieve a specified outlet temperature for the gas being cooled on the tube side of the heat exchanger (FIG. 4).

The operator is seeking to reduce the outlet temperature of the heat exchanger to reduce the power consumed by a large compressor. In the process simulator, it is simple to set a lower gas outlet temperature target in the control block, and the coolant flow rate will be increased until the new, higher duty is achieved.

In the rigorous exchanger simulation shown in FIG. 5, it is clear that the pressure drop on the water side is below the maximum allowable for the existing operating conditions.

If a lower gas outlet temperature is prescribed to affect the desired reduced compressor power, the rigorous model in the simulation responds to the increased coolant flow that the adjust mechanism imposes. The exchanger can now achieve the new duty. However, because a rigorous tool is being used, other beneficial calculations can be performed. The results highlighted in FIG. 6 show three issues to consider: Pressure drop. The increase in water flow has resulted in a pressure drop on the shell side, which exceeds the design allowable. This may mean that sufficient pumping capacity will not be available to achieve the required flow.

Dynamic pressure. The Tubular Exchanger Manufacturers Association (TEMA) defines maximum dynamic pressure as:

q = rho v 2 where rho is the fluid density, and v is the fluid velocity.1

(6)

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Heat Transfer Developments The maximum dynamic pressure will be different based on the exchanger geometry. Exceeding these values brings the risk of excessive erosion and the potential for premature failure of tubes or other pressure parts of the exchanger.

Vibration. The rigorous exchanger model performs a vibration analysis for the exchanger bundle. It can be seen that the increase in the cooling-water flowrate has resulted in a possible risk of flow-induced vibration for this exchanger bundle. This can lead to tube failure, which, in some cases, can be rapid.

The process simulation, coupled with the rigorous heat exchanger analysis, can reveal potential operational problems that go far beyond the simple considerations of heat and mass balance. In this case, the operator can choose to work within

FIG. 6. Results of rigorous simulation for a water-cooled exchanger.

limits that avoid the risks of erosion, flow-induced vibration and other operational problems. The simulator and the rigorous exchanger tools can be used to evaluate an alternative control scheme, such as controlling the cooling-water temperature instead of the flowrate.

Best practice in exchanger/process modeling. Today,

leading engineering and operating companies in the chemical and energy sectors are exploiting the integration of rigorous exchanger models within process simulation to reduce project schedules, minimize rework, and provide better overall optimization of their processes.

However, traditional organizations often separate process engineering, thermal design and mechanical design functions, which can be a barrier to the adoption of integrated technologies. As companies recognize the benefits provided by closer cooperation between the disciplines involved, many are seeing that they can make much more effective use of specialist skills when process engineers undertake preliminary designs using rigorous models in their simulations. Such simulations can then be fully optimized by the thermal specialist as process activities proceed.

In many smaller engineering organizations, a broader skill base for process engineers allows them to directly exploit the benefits of the integration discussed here. In a case study2 presented at the OPTIMIZE 2011 conference, one chemical company discussed a feasibility study wherein a reduction in capital equipment costs of 15% and an annual energy savings of $200,000 were discovered through the integration of rigorous equipment modeling with process simulation.

Another company obtained an estimated $5.5 million in additional revenue from increased liquefied petroleum gas (LPG) production, while reducing equipment costs by $0.5 million.3 This was achieved through the integration of a platefin rigorous modeling tool inside a process simulator. The integration allowed the evaluation of various alternative process solutions and their direct impact on temperature approach in the heat exchanger type selected.

The integration of rigorous modeling tools for heat exchanger modeling inside process simulators allows a faster delivery of projects by shortening the discussion time between different disciplines. Process engineers can be confident with the results of the process modeling by using the real geometry and the most rigorous tool for the heat exchanger calculation. Finally, plant operations are made safer by modeling all aspects of the heat exchanger operation, such as vibration.

LITERATURE CITED Standards of the Tubular Exchanger Manufacturers Association, 9th Ed., New York, New York, 2007.

2 Roy, E., presentation at the AspenTech OPTIMIZE 2011 Conference, Washington, DC, May 2011.

3 Venkatesh, L., Petrofac Engineering India Ltd., presentation at Aspentech OPTIMIZE 2011 Conference, Washington, DC, May 2011.

1

JULIEN CAZENAVE is an Aspen exchanger design and rating (EDR) business consultant for AspenTech, based at the companyâ&#x20AC;&#x2122;s European headquarters in Reading, UK. He has more than 10 years of experience in working with customers of AspenTechâ&#x20AC;&#x2122;s EDR and simulation products across Europe, the Middle East and Africa. Mr. Cazenave ensures that customers derive maximum value from their investment and are regularly updated on new developments in the software and the underlying technology.

100

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Bonus Report

Heat Transfer Developments K. BIRAMOV, M. MAITY, and E. AL-ZAHRANI, Sabic Technology Centre, Jubail, Kingdom of Saudi Arabia; and M. A. KAREEM, Eastern Petrochemical Co., Jubail, Kingdom of Saudi Arabia

Prevent external corrosion of boiler tubes under refractory lining A leak developed on the water wall for several boiler tubes within five months of the commissioning of a plant boiler. In this case, the boiler tubes were partially covered with a castable refractory layer near the water drum at the bottom and at the top of the steam drum. Severe corrosion was noticed on the external surface of the boiler tubes, particularly at the lower section near the water drum. A detailed analysis and microstructural characterization of the corroded tubes and refractory samples were conducted to understand the root cause for the corrosion. Caustic gouging was determined as the predominate cause for the corrosion of the boiler tubes’ external surface. A review of the plant’s history noted that the boiler had been idled for a long time before commissioning. Wet refractory had promoted migration of alkalis to the tube surfaces, thus subsequently initiating the corrosion process.

BACKGROUND A package boiler for the utility plant in this petrochemical facility experienced leakage in the water wall tubes of the combustion section. The boiler leak required an emergency shutdown. The operating temperature of the furnace ranged between 1,200°C and 1,250°C. The tube-metal temperature at the furnace section is around 340°C. The tube material is carbon steel with a diameter of 64 mm and a thickness of 5 mm. Natural gas was used as the combustion fuel.

The boiler tubes are partly covered with refractory castable at the junction at the top of the steam drum and at the bottom of the water drum, as shown in FIG. 1. The castable refractory was an alumina-silicate base with a hydraulic setting. Severe corrosion was noticed on the external surface of the tubes under the refractory in the lower division wall tubes (adjacent to the water drum area). Interestingly, the corrosion was first noticed in lowest areas where the boiler tubes are covered with the refractory. However, no visible corrosion was noticed in the same tubes at the upper section near the steam drum that was also covered with the same refractory lining. Also, no corrosion was reported in the superheater, boiler bank and economizer area. A failure analysis was conducted on the leaking and corroded tubes to identify the failure mode.

VISUAL INSPECTION ANALYSIS FIGS. 2 and 3 depict the typical refractory covering over the tubes along, with examples of the corroded tubes. The visual

inspection provided evidence of localized mild to severe corrosion on the external surface of the tubes. As shown in FIG. 3, a complete perforation in one of the tubes developed. The corrosion was mainly localized in areas covered with the refractory, particularly at floor level adjacent to the water drum. No corrosion was detected in the exposed part of the tubes. It is also important to note that no corrosion was noticed at the upper part of tubes covered with refractory (the steam drum area).

The corrosion products examined in this investigation were removed from the external surface of the tubes. The corrosion products were brittle and porous. The products’ colors

FIG. 1. Tubes with refractory cover at bottom and top, respectively.

FIG. 2. Evidences of corrosion process with leaking boiler tubes.

FIG. 3. Corroded and leaking tubes.

Hydrocarbon Processing | SEPTEMBER 2012 103

Heat Transfer Developments varied from brown to black. Also, the corrosion products had a layered appearance.

Sample testing. An X-ray fluorescent (XRF) spectropho-

tometer was used to do an elemental analysis of the corrosion products. TABLE 1 summarizes the results of the XRF analysis.

XRF samples indicated the presence of mainly oxygen (O) and iron (Fe) corrosion products. The applied refractory was cement-based castable with high a calcium oxide (CaO) content.

SEM micrograph/EDX examination. Corroded tubes were

sectioned and prepared for micro-structural evaluation from the pit, as well as from the intact areas. Microanalyses of tube surface were undertaken via energy dispersive X-ray (EDX) spectrometry. The images were recorded by scanning electron microscopy (SEM). A cross-section of the pit showed the hemispherical bottom with some corrosion products. The top surface of the pit showed the presence of deposits with varying TABLE 1. XRF analysis, wt% Elements

Corrosion product

Refractory

O

27.71

40.35

Fe

69.98

2.764

Na

0.067

0.11

Al

0.2

24.4

Si

0.095

7.15

P

0.1

0.188

S

0.144

0.069

K

0.067

0.511

Ca

0.062

17.43

Zr

–

6.736

Cr

0.026

0.093

Mn

0.423

0.022

Ni

0.945

0.016

Mo

0.041

–

Mg

–

0.169

Cl

–

0.0072

V

–

0.043

Other

Traces

Traces

TABLE 2. Leaching test of refractories pH

10.4

Anions

Unit

Value

Cations

Unit

Value

Fluoride (F–)

mg/l

7.2

Lithium (Li+)

mg/l

ND

Chloride (Cl–)

mg/l

69

Sodium (Na+)

mg/l

2,923

Nitrite (NO2–)

mg/l

ND

Ammonium (NH4+) mg/l

–

Bromide (Br ) – 3

Nitrate (NO )

mg/l

ND

+

Potassium (K )

ND

mg/l

222

+2

mg/l

287

Magnesium (Mg ) mg/l

0.6

Phosphate (PO4–3) mg/l

154

Calcium (Ca+2)

1,638

Sulfate (SO4–2)

204

mg/l

Source: ND—Not detected

104 SEPTEMBER 2012 | HydrocarbonProcessing.com

mg/l

thicknesses (FIG. 4). The EDX detected the presence of silica (Si), sodium (Na) and sulfur (S) peaks beside the usual O, Fe and carbon (C) peaks. All of the concentrations of the elements are summarized in FIG. 5. Metallographic examination revealed normal ferrite-perlite microstructures typical for carbon steel.

Leaching test and pH of refractory samples. Soluble cat-

ion and anion levels were checked semi-quantitatively in the refractory samples. Approximately 10 gm of refractory powder was soaked and placed in 50 ml of demineralized water with continuous stirring for about six hours. Subsequently, the pH and the dissolved cations and anions of the solution were checked. The testing results are summarized in TABLE 2. The solution was highly alkaline with a pH of 10.4. The significant presence of soluble calcium (Ca), Na and potassium (K) were detected. Likewise, different anions were also detected.

ROOT CAUSE OF THE CORROSION The corrosion occurring in boiler tubes or in other metallic sections covered with refractory is a complex phenomenon. It depends on many different processes and environmental conditions. Of all the variables of interest, the chemical composition of the combustion fuel—specifically the heavy metal— chloride, sulfate and alkali content of the natural gas—and the refractory used on the boiler were probably the two most important contributing factors supporting corrosion of the tubes’ external surface.1,2 The sulfur-bearing elements were negligible in the natural gas fuel.

In this case, corrosion of the boiler tubes was noticed mainly at the lower part of the boiler and around the burners. The tubes were covered with refractory in these areas. However, no corrosion was noticed at the upper part of the tubes although they were also covered with refractory. Therefore, corrosion of tubes exclusively due to fuel was ruled out. Otherwise, corrosion would have been found on other boiler tubes covered with refractory. The XRF analysis revealed the presence of mainly Fe and O along with minor constituents.

The presence of alkaline-producing species such as Na, Ca and K was detected in leaching tests of refractories with a very high pH. The EDX spectrums also showed elements such as Na and Ca in the surface layers of the corroded areas. High alkaline concentration may have occurred due to the ingress of water into the refractory during the long storage before commissioning.

The corrosion mainly at the lower part of the boiler confirmed the same; moisture (water) would accumulate in the same region as a thin layer due to gravity. The alkaline environment at high temperatures can cause localized corrosion, known as caustic gouging, or ductile gouging in the form of deep depressions and grooves with hemispherical bottoms.3–7 For example, the formed sodium hydroxide (NaOH) will easily dissolve the protective magnetite layer on the tube surface at high temperatures.

When this film is removed, the concentrated alkali reacts directly with the bare Fe surface forming sodium ferroate (Na2FeO2): Fe+NaOH → Na2FeO2 + H2 Considering all of the listed observations and analyses obtained from the lab examinations, it may be concluded that the corrosion occurred due to a caustic-gouging mechanism. Alkaline corrosion was most likely the root cause. Generally, this

Heat Transfer Developments 2.6

gs\supervisor\Desktop\SharedData\Analysis Data\2010\MCS\MCS-10-08-02\20719-A2-04.spc < Pt. 3 Spot> LSecs: 84

0

Fe

2.1 1.6 KCnt

type of damage is highly localized, as was found in this investigation. In this case, the boiler was idle for a long time, and the refractory was not dried out properly after installation. External moisture and water could have ingressed during the long storage or shifting when the boiler was moved from the shop to the site.

Moisture/water appeared to be in contact with the tubes under the refractory for a long time before commissioning. The presence of water could have enhanced the migration of alkalies to the tube surfaces. The concentration of alkali species on tube surfaces increased at higher operating temperatures, which resulted in a concentration mechanism.

1.1

Fe

0.5 C 0.0 Spectrum Wt%

O 29.58

Si 0.45

Na

Fe

Si

1

2 Na 0.83

3

4

6 5 Energy, keV

Fe 56.33

7

8

9

10

C 12.81

FIG. 4. The SEM micrograph of the corroded surface with pitting showing the corrosion products, and an EDX spectrum, showing the peaks of O, Fe and C, as well as, Si and Na

Final remarks. Based on the investigation

gs\supervisor\Desktop\SharedData\Analysis Data\2010\MCS\MCS-10-08-02\20719-A1-04.spc < Pt. 3 Spot> LSecs: 81

KCnt

3.4 findings, several conclusions were made: 0 Fe • Corrosion due to fuel quality was 2.7 ruled out as no corrosion was noticed at the upper part of tubes covered with refractory.

2.1 Furthermore, the content of the corrosive elements in the fuel, mainly S, is very low 1.4 Fe and within the specification for the boiler.

• The boiler tube corrosion is most 0.7 Fe C Si likely attributed to the caustic gouging Na 0.0 mechanism.

1 2 3 4 5 6 7 8 9 10 • The observed highly localized corroEnergy, keV sion is not associated with creep rupture.

Spectrum O Si S Na Fe C The lesson learned from this event is Wt% 30.1 0.58 0.65 1.56 62.28 4.78 that it is very important to heat dry castable refractory after installation. In the event FIG. 5. Cross-section (as polished) of corroded tube showing pitting with hemispherical bottom, that the commissioning is delayed, then and an EDX spectrum showing the peaks of O, Fe and C, as well as, Si, S and Na. the refractory lining should be protected DR. AVTANDIL KHALIL BAIRAMOV is working as a consultant in SABIC from moisture and the ingress of any water with proper covering.

Technology Center-Jubail, Materials and Corrosion Section. He graduated from Natural air circulation should be maintained to avoid any stagMoscow Institute of Petrochemical and Gas Industry with distinction award. He nant humid condition within the boiler. earned his PhD in chemical resistance of materials and protection from corrosion LITERATURE CITED Hancock, J. D., Practical Refractories, Cannon & Hancock CC, 2002.

2 Potgieter, J. H., R. H. M. Godoi and R. V. Grieken, “ A Case Study of High Temperature Corrosion in Rotary Cement Kilns,” The Journal of The South African Institute of Mining and Metallurgy, November 2004, pp. 603–606.

3 Metals Handbook, 8th Ed., Vol. 7, “Atlas of Microstructure of Industrial Alloys,” ASM, 1972.

4 Port, R. D., H. M. Hero, The NALCO guide to boiler failure analysis, McGraw-Hill Inc., New York, New York, 1991.

5 Metals Handbook, 9th Ed., “Failure Analysis and Prevention, ASM, 1995.

6 STEAM, its Generation and Use, 40th Ed., Babcock & Wicox, McDermot Co., Barberton, Ohio, 1992.

7 Lay, G. Y., High Temperature Corrosion of Engineering Alloys, Hayness International, Kokomo, Indiana, 1990.

1

Al Ca C Cl Cr Fe Mg Mn Mo

Aluminum Calcium Carbon Chlorine Chromium Iron Magnesium Manganese Molybdenum

NOMENCLATURE Ni Nickel O Oxygen P Phosphorus K Potassium Si Silicon Na Sodium S Sulfur V Vanadium Zr Zirconium

from Azerbaijan Academy of Sciences, Baku, where he was Manager of Corrosion and Electrochemistry Department. Dr. Bairamov published over 130 technical papers including 15 national patents. Dr. Bairamov completed numerous failure investigation studies and materials selection projects. He received 2010 NACE International Technical Achievement Award. Dr. Bairamov is a Professional Member of Institute of Corrosion (MICorr., UK) and NACE. MANABENDRA MAITY is working as a refractory specialist at the Materials & Corrosion Section of Sabic Technology Centre, Jubail, KSA. He holds B.Tech degree in ceramic engineering from Calcutta University and a M.Tech degree in ceramic engineering from IT-BHU, India. He has more than 16 years of extensive experience in refractory lining design, engineering, installation and quality control, failure analysis and troubleshooting. He started his career in 1994 as a refractories and non-metallics engineer in Engineers India Ltd. Mr. Maity is life member of the India Ceramic Society & Indian Institute of Ceramics and is qualified for API-936 Refractory Personnel Certification Program.

E. ALZAHRANI works as a failure analysis engineer in SABIC Technology Center, Jubail, Kingdom of Saudi Arabia, since 2008. He has a BS degree in mechanical engineering from King Khalid University, KSA. MOHAMED ABDULKAREEM is a mechanical engineer by discipline and has more than 10 years of working experience in the field of inspection. At present, he is working as an inspection specialist in the inspection and reliability department of Eastern Petrochemical Co. (SHARQ), SABIC in Saudi Arabia. He engages in the corrosion mitigation, failure analysis and inspection of static equipment.

Hydrocarbon Processing | SEPTEMBER 2012 105

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Special Supplement to

ENGINEERING AND CONSTRUCTION 2012 What you don’t know can hurt you [E–109] Engineering and construction news [E–112] CORPORATE PROFILES Air Liquide Global E&C Solutions [E–115] COVER PHOTO

Koch-Glitsch [E–117]

Abu Dhabi Terminals unloads the heaviest cargo received at the Musaffah Port, Abu Dhabi. The high-pressure absorber, weighing over 1,300 metric tons, was manufactured by Walter Toasto of Chieti Scalo, Italy. This cargo lift marks a milestone for the port.

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ENGINEERING AND CONSTRUCTION

WHAT YOU DON’T KNOW CAN HURT YOU Be certain systems are safely grounded J. GLENNEY, Littelfuse, Saskatoon, Canada

An engineer at a large chemical plant in the Eastern US inspected plant substations that were grounded via a high resistance grounded system. He discovered that two of 10 substations had been operating with failed systems and nobody knew it. When the connection to ground is interrupted, usually because of a mechanical failure in the resistor, there is usually no sign that the ground has been lost. Without resistance grounding, transient overvoltages can occur on the system, which can endanger personnel and cause insulation failures on motors throughout the system. What’s more, without grounding, current-sensing ground-fault protection will not indicate the presence of a ground fault that could damage equipment and injure workers.

Resistance grounding (FIG. 1) has been used in hydrocarbon processing plants for many years. When properly designed, it eliminates many of the problems associated with solidly grounded and ungrounded systems while retaining their benefits. It can: • Limit point-of-fault damage • Prevent transient overvoltages • Reduce the risk of an arc-flash • Provide continuity of service during a ground fault • Allow adequate current for ground-fault detection and selective coordination.

Resistance grounding possesses a critical element that is often ignored: the neutral grounding resistor (NGR). Even though the petroleum and chemical industries have used resistance grounding since the 1960s, there are some petrochemical facilities that do not monitor their NGRs.

What’s the danger of open NGRs? The first thing that generally happens when an NGR fails open-circuit is nothing. While the system is now ungrounded, it continues to operate until the open resistor is discovered.

Yet without continuous NGR monitoring, there is no indication that the system has become ungrounded, and operators will not be aware that there is no longer any current-sensing ground-fault protection and that there is a risk of transient overvoltages.

A short-circuited NGR is not as serious a problem as an open-circuited one. It results in a grounded electrical system; if there is a ground fault, this results in a ground-fault current with the fault being cleared by ground-fault or overcurrent protection. This is somewhat reassuring, but not ideal, as a shorted-out NGR means some of the advantages of resistance grounding are lost.

Detecting a failed NGR is difficult. A visual examination for an opencircuited NGR may not reveal any problems. Voltage monitoring at the neutral will not detect an open until there is a ground-fault somewhere else on the system. Voltage monitoring does not allow selective coordination or control of touch potential on portable loads, which can be fatal. Occasionally, open resistors are discovered during preventive maintenance (if measurement of the NGR resistance is part of standard practice), yet even then there are no guarantees. Periodic measurement

NGRs can and will fail. A typical NGR element consists of resistance wire or metal strips wrapped around porcelain insulators. When it fails (due to corrosion, mechanical damage, vibration, severe electrical disturbances or simply age), it fails open-circuit (FIG. 2). NGRs can also be shorted out (usually accidentally during construction or maintenance), but this is much less common and does not defeat ground fault or overcurrent protection.

Grounding resistor

Power transformer secondary

FIG. 1. In a resistance grounded system, the center point of the input transformer is connected to the ground via a resistor.

FIG. 2. An NGR is a mechanical component and is subject to mechanical failures. This photo shows an NGR thermal failure.

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ENGINEERING AND CONSTRUCTION

of NGR resistance cannot pick up a failure that occurs later, and sometimes the person making the resistance measurement forgets to reconnect the resistor after the measurement.

Sometimes ground-fault relays are tested by intentionally grounding a phase. If the NGR is open, then the ground fault relay will not operate, and the investigation into the reason should reveal the open NGR. Testing the ground-fault relays by primary current injection, on the other hand, will not reveal an open NGR, because the ground-fault relays will respond to the injected current and appear to operate properly.

This would then falsely confirm that ground-fault protection was working.

NGR monitoring. There are several ways to monitor NGRs, some better than others. A potential transformer and a time-delay voltage relay connected across the NGR will monitor neutral voltage, but it will not operate until a ground fault occurs, regardless of the condition of the NGR. This is not continuous NGR monitoring. Another approach is to use voltage measurement and current measurement combined with logic circuit to the NGR (FIG. 3). If both voltage and current are present, there is a ground fault on the system, and since there is current flowing through the NGR, it cannot be open. If there is voltage but no current in the NGR, it must be open. Like the previous example, this is not continuous NGR monitoring because it works only during a ground fault.

Continuous monitoring is the way to go. A far better solution is an automatic monitoring device. A continuous NGR monitor detects an open NGR as soon as the failure occurs. It works whenever control power is applied, whether or not the system is energized and with or without a ground fault. It also reduces the opportunity for human error during inspection and maintenance.

At a petroleum facility, engineers performed quarterly insulation tests on resistance grounded generators. To perform the test, the engineers had to â&#x20AC;&#x153;floatâ&#x20AC;? the generator, disconnecting the neutral-grounding resistor from ground. How could engineers be sure that each generator was re-grounded after each test was completed? The solution in this case was to install NGR monitors that would report the condition of the ground to plant control software. Not only would engineers know

Overcurrent

for certain that generators had been re-grounded, but that fact would be documented in the control system.

A good way to implement NGR monitoring is to combine an overvoltage measurement, an overcurrent measurement and a resistance measurement (FIG. 4). In physical form (FIG. 5), it combines measured NGR current, transformer or generator neutral voltage and NGR resistance to continuously determine the health of the NGR. The resistance measurement is the sum of the resistance from the sensing resistor, to the neutral point, through the NGR to ground, and through ground back to the monitor. Connecting the sensing resistor to a separate lug on the neutral bus assures that the NGR connection to the neutral point is part of the monitored loop.

When there is no ground fault on the system, a measurement of NGR resistance is enough to confirm NGR continuity. The monitor determines the presence of a ground fault through the voltage and current measurements. Voltage on the neutral and current in the NGR indicates a ground fault.

When a ground fault is present, a resistance measurement is not sufficient to confirm NGR continuity because of the possibility of measuring continuity through the fault, as mentioned earlier. Because a resistance measurement alone is not sufficient to confirm NGR continuity, the monitor constantly evaluates resistance, current and voltage measurements.

When neutral voltage is elevated and current is flowing through the NGR, the NGR must be continuous. When the neutral voltage is elevated but no current flows through the NGR, the NGR must be open.

The ability to detect an open NGR in the presence of a ground fault is particularly important in alarm-only systems where ground faults can remain on the system for long periods.

When a ground fault occurs in a resistance-grounded system, voltage appears on the system neutral. In the case of a bolted fault, the transformer or generator neutral rises to line-to-neutral voltage. An NGR monitor that is directly connected to the system neutral brings a conductor with line-to-neutral voltage during a ground fault into a low-voltage control cubicle. This is not acceptable in many applications. The sensing

Overvoltage

Overcurrent

Overvoltage

Ί FIG. 3. One way to monitor the status of an NGR is to apply an overvoltage measurement, an overcurrent measurement and a logic circuit to it.

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ENGINEERING AND CONSTRUCTION 2012 HydrocarbonProcessing.com

FIG. 4. A better solution is the combination of an overvoltage measurement, an overcurrent measurement and a resistance measurement.

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ENGINEERING AND CONSTRUCTION Transformer or generator Neutral NGR enclosure CT

Sensing resistor NGR NGR monitor L1 L2 Ground fault

Resistor fault

FIG. 5. A physical embodiment combines measured NGR current, transformer or generator neutral voltage and NGR resistance to continuously determine the health of the NGR. resistor, as shown in FIG. 5, connects the monitor to the power system while isolating it from neutral voltage. The sensing resistor limits the voltage transfer from the system neutral to the NGR monitor. The resistive elements of the sensing resistor will not contribute to ferroresonance, a condition in which inductance working in conjunction with system capacitance results in voltage oscillations that can produce overvoltages that may exceed two to three times system voltage. A failure of the sensing resistor results in a resistor-fault contact changing state and LEDs indicating an issue since the resistance measurement reads an open circuit.

The final word on NGRs. Located outdoors, NGRs are subject to failures related to corrosion, lightning, storms, earthquakes and

wildlife. Other problems that can befall NGRs include thermal overload, extended service life, vibration and improper specification or installation.

A plant electrical system with an open NGR is subject to transient overvoltages, and current-sensing ground-fault protection will not indicate the presence of a ground fault. A ground fault then remains on the system and might escalate to a phase-to-phase fault.

A well-designed NGR monitor provides continuous protection against failures that previously rendered ground fault protection, coordination, and annunciation systems inoperative and left the system exposed to damaging transient overvoltages. An NGR monitor provides confidence that current-sensing ground-fault protection will operate as designed on the next ground fault.

A good example of this approach is a petrochemical plant in Texas in which the aging resistance grounding system had failed and plant managers had continued operations on an ungrounded electrical system. Managers needed to determine which of the two pumps on that particular transformer had a ground fault, without shutting off the pumps, which would interrupt production. This was not possible unless they grounded the electrical system, and connecting a solid ground would have tripped the overcurrent protection. The plant installed a new resistance grounding system, and, this time, it added an NGR monitor to prevent this problem from happening again.

Remember, the ability to reliably monitor neutral grounding resistors is not trivial, so be sure to select a company that has proven experience in your industry at all voltage levels.

Jeff Glenney is a sales engineering manager for Littelfuse’s protective relay products line. Mr. Glenney received a BS degree in electrical engineering from the University of Saskatchewan in Saskatoon, Canada. He is a registered professional engineer in Saskatchewan. In Mr. Glenney’s capacities as sales engineer and sales engineering manager, he has worked with many system designers and end users to find solutions for protection relays. He now manages Littelfuse’s US relay sales.

ENGINEERING AND CONSTRUCTION NEWS CB&I TO BUY SHAW GROUP CB&I has agreed to acquire Shaw Group, a US-based engineering company primarily focused on serving clients in the power generation and government services sector. The acquisition is expected to close in early 2013. Reports valued the overall deal at approximately $3 billion.

CB&I said that combining the two companies will create “one of the most complete energy focused technology, engineering, procurement, fabrication, construction, maintenance and associated services companies in the world.”

With a global workforce of nearly 50,000 employees, backlog of over $28 billion, and engineering and fabrication facilities strategically located on all continents, the company will have the capacity to execute large energy infrastructure projects now and in the future, according to company officials.

“This is a highly compelling transaction that we believe will create significant value for our shareholders,” said Philip K. Asherman, president and CEO of CB&I. “By adding them into the CB&I family, we will become fully diversified across the entire energy sector, from power generation to LNG, from refining to gas processing, from offshore to oil sands, and beyond.”

CB&I will acquire Shaw for $46 a share in cash and stock, with shareholders receiving $41 in cash and $5 in CB&I equity (0.12883 shares based on a recent average stock price of $38.81 a share) for each share of Shaw stock at closing. CB&I will use cash on the balance E-112

ENGINEERING AND CONSTRUCTION 2012 HydrocarbonProcessing.com

sheets of both companies, along with approximately $1.9 billion in debt, to finance the acquisition, it said.

The acquisition of Shaw was unanimously approved by the directors of each company’s boards. The transaction is subject to approval by each company’s shareholders, along with the receipt of certain regulatory approvals and the satisfaction of other customary closing conditions.

CB&I plans to operate Shaw as a business sector under the brand name CB&I Shaw, enabling the new company to retain Shaw’s brand equity.

METHANEX AWARDS PLANT ENGINEERING DEAL TO JACOBS FOR CHILE-TO-US RELOCATION Jacobs Engineering Group was awarded a contract from Methanex to provide engineering, procurement and construction services for the relocation of an idled Chilean methanol facility to Geismar, Louisiana. Officials estimate the construction value to be $550 million.

Jacobs is already executing site-specific engineering and construction management for the 225-acre location in Geismar, La. from its offices in Baton Rouge, with support for the disassembly from its office in Santiago, Chile, the company said. The plant is expected to be operational the second half of 2014.

“The US Gulf Coast is a prime location for this facility, especially since demand for methanol is expected to grow in the coming years,” said Jacobs Vice President Mike Autrey.

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KOCH-GLITSCH

PROVIDING SOLUTIONS FOR FOULING APPLICATIONS:PROFLUXTM SEVERE SERVICE GRID Cs m/s

INTRODUCTION % Liquid entrained e though bed

0.138016

0.148016

0.158016

SEPARATION EFFICIENCY The high efficiency of PROFLUX™ grid packing, as demonstrated in testing (Figure 2), gives the refiner an option to use a more robust packing throughout the entire wash bed and run at higher operating rates, versus the current practice that uses a combination bed of conventional grid and structured packing. As with any wash bed packing, the vapor flow should be as uniform as possible to minimize areas of high vapor velocity that can dry out the packing. Koch-Glitsch’s patented advanced vapor horn technology for tangential and radial vapor inlets works in conjunction with the wash bed packing to maximize de-entrainment of the resid and provide excellent vapor distribution to the HVGO bed above.

RELIABILITY The first PROFLUX™ severe service grid is already in operation in a refinery for more than 2 years. The welded construction of PROFLUX™ SPONSORED CONTENT

0.178016

0.188016

0.198016 12

9.0 FLEXIGRID™ 3-45 grid

8.0

PROFLUX™ 64 grid

7.0

PROFLUX™ 45 grid

6.0 5.0 4.0 3.0 2.0 1.0 0.0 0.42

0

0.44

0.46

0.48

0.50

0.52

CAPACITY

0.54

0.56

0.58

0.60

0.62

0.64

0.66

0.68

Cs ft/s

FIG. 1. De-entrainment Efficiency

Cs m/s 0.00 80

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

0.18 2000 1800

70

1600

60

1400

HETP inches

The primary function of the vacuum crude tower wash zone is to remove entrained resid from the flash zone. Grid style packings, such as FLEXIGRID® severe service grid packing, have typically been used because of their robust construction and resistance to fouling. These packings are adequate at lower vapor rates; however, when pushed to higher CS values by the need for deeper cutpoints, they can exhibit resid entrainment. The secondary function of the wash bed is to fractionate impurities; therefore, depending on the severity of the cut, efficiency can be important as well. Based on its extensive experience supplying equipment for fouling services, Koch-Glitsch has developed a new grid packing that combines the efficiency and de-entrainment performance of a conventional structured packing with the ruggedness and fouling resistance of a conventional grid packing.

The patent pending PROFLUX™ severe service grid packing consists of smooth surface crimped sheets that are spaced apart and welded together with rods. Tests performed under conditions similar to a typical vacuum crude tower wash bed show, in comparison with conventional grid packing, that PROFLUX™ grid packing can operate at higher CS values before significant entrainment is monitored. Figure 1 shows the entrainment levels as a function of tower throughput for both sizes of PROFLUX™ grid packing compared to FLEXIGRID 3 grid packing. Greater capacity compared to conventional grid or structured packing allows increased flow rates in existing vacuum towers or a reduction in vessel diameter for new units.

0.168016

50

1200

40

1000

30

800

20 10

HETP mm

In today’s competitive refining industry, maximizing existing assets or building new export capacity requires key technologies to ensure a return on investment. Two of the most important parameters considered in revamp work or new construction are throughput and reliability of the crude distillation unit. At the heart of the crude distillation unit sits the vacuum crude tower wash zone, which usually defines both capacity and run length of the unit. As crude slates become heavier, the severity of the conditions in the wash zone increases. Wash bed performance and reliability are determined by many factors, which include the design of mass transfer equipment.

0.128016 10.0

600 PROFLUX™ 45 grid

400

PROFLUX™ 64 grid

200

0 0 0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40 0.45 0.50 0.55 0.60 0.65

Cs ft/s

Xylenes, Total reflux, 200 mmHg

FIG. 2. PROFLUX™ Grid Packing Efficiency grid packing provides superior durability in severe service applications.

Panels can be through-bolted to provide uplift resistance. The spacing between the corrugated sheets eliminates contact points that could serve as potential sites for coking or accumulation of solids. The lack of horizontal surfaces allows free drainage of liquid and ensures the entire surface of the packing is wetted. This is critical to minimize coke formation. Tests using a precipitating salt solution have shown that the fouling resistance of PROFLUX™ grid packing is superior to conventional grid packings of similar surface area. The construction of this packing permits easy removal, cleaning, and installation.

CONTACT INFORMATION 4111 East 37th Street North Wichita, KS 67220 Phone: 316-828-5110 Fax: 316-828-7985 www.koch-glitsch.com HYDROCARBON PROCESSING

ENGINEERING AND CONSTRUCTION 2012

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O c t o b e r 3 0 – 3 1 , 2 0 1 2 • H y a t t R e g e n c y H o u s t o n • H o u s t o n , Te x a s U S A The Women’s Global Leadership Conference in Energy and Technology (WGLC) is one of the largest women’s events in the industry, and the only one that focuses on discussing key environmental, economic and professional development issues in oil and gas.

This year, Houston Mayor Annise Parker will deliver a welcome address the morning of October 30 to open day one of the conference. Day two of the conference will begin with a keynote presentation by Mark Mills, CEO of Digital Power Group, titled “Unleashing the North American Energy Colossus – Hydrocarbons Can Fuel Growth and Prosperity.” To download the full conference agenda, please visit WGLNetwork.com.

Conference content will focus on the global impact of recent technological advances in exploration and production. Executives from leading oil and gas companies will share the latest information on topics like regulatory changes, sustainability, refining, international operations, IOC/NOC relationships and global upstream trends. Also slated for discussion is the recent North American revolution in shale energy, oil sands and natural gas, and the wider implications on transportation and infrastructure.

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ADVERTISER INDEX / HydrocarbonProcessing.com The first number after the company name is the page on which an advertisement appears. The second number, appearing in parentheses, after the company name, is the Reader Service Number. There are two ways readers can obtain product and service information: 1. Go to www.HydrocarbonProcessing.com/RS. Follow the instructions on the screen, and your request will be forwarded for immediate action.

2. Go online to the advertiser's Website listed below.

Company Website

Page

RS#

Aggreko ........................................... 66 (166) www.info.hotims.com/41432-166

Air Products & Chemicals Inc. .............. 17

(67)

Altair Strickland ................................ 46

(75)

www.info.hotims.com/41432-67 www.info.hotims.com/41432-75

Ametek Process Instruments ............... 21 www.info.hotims.com/41432-153

Asco Valve Inc. ................................. 102 www.info.hotims.com/41432-64

Axens .............................................. 128 www.info.hotims.com/41432-53

Baldor Electric Company ....................127 www.info.hotims.com/41432-69

(153) (64)

Company Website

Page

Gulf Publishing Company Construction Boxscore.......................30 Events—EMGC .................................125 Events—WGLC .................................119 Gas Processes Handbook ..................122 HPI Marketplace ....................... 120–121 HPI Market Data 2013 ....................... 90 Haldor Topsøe A/S.............................. 18 www.info.hotims.com/41432-56

(53)

HTRI .................................................. 14 www.info.hotims.com/41432-151

(69)

RS#

Saint-Gobain NorPro ..........................36 (56) (151)

www.info.hotims.com/41432-159

Idrojet ...............................................52 (162)

(68)

www.info.hotims.com/41432-165 www.info.hotims.com/41432-162

Buchen-ICS GmbH ............................. 60 (164)

Imperial Crane ...................................68 (167)

Burckhardt Compression AG ................53

(79)

ITW Polymer Technologies/Chockfast ....84 (169)

Cameron ...........................................97

(55)

John M Campbell & Co .................... E-113

(99)

(157)

Johnson Screens ................................73

(60)

Carver Pump Company .......................26 www.info.hotims.com/41432-157

www.info.hotims.com/41432-167

www.info.hotims.com/41432-169 www.info.hotims.com/41432-99

www.info.hotims.com/41432-60

Samson GmbH ...................................45 Selas Fluid Processing Corp ................101 Sherwin Williams .............................. 99 Siemens AG ....................................... 15 Spraying Systems Co ........................... 8 Sulzer Chemtech, USA Inc....................25 Swagelok Co. ..................................... 61 T.D. Williamson ..................................70

T.F. Hudgins, Inc .................................43 (158) www.info.hotims.com/41432-158

Team Industrial Services .....................27 Total Safety .......................................78

Colfax Americas .................................32

(86)

Linde Process Plants ...........................77

(85)

Trachte USA .....................................100

Curtiss-Wright .................................... 2

(76)

Lurgi GmbH ...................................E-114

(101)

Transfield Services .............................86

Dresser-Rand..................................... 51

(65)

Man Diesel & Turbo.............................69

(59)

Dresser-Rand..................................... 91

(171)

Merichem Company............................54

(84)

UOP LLC ............................................. 12 URS ...............................................E-118

Elliott Group ......................................89

(52)

Messe Düsseldorf North America .........92

(172)

www.info.hotims.com/41432-76

www.info.hotims.com/41432-65

www.info.hotims.com/41432-171 www.info.hotims.com/41432-52

Emerson Process Management (Deltav)...........................................11 www.info.hotims.com/41432-63

(63) (93)

Foster Wheeler ............................. E-108

(83)

www.info.hotims.com/41432-83

www.info.hotims.com/41432-59

www.info.hotims.com/41432-84

www.info.hotims.com/41432-172

Michell Instruments ...........................82 (168)

Flexitallic LP ....................................... 5 www.info.hotims.com/41432-93

www.info.hotims.com/41432-101

www.info.hotims.com/41432-168

Milliken Workwear .............................62 www.info.hotims.com/41432-97

(97)

www.info.hotims.com/41432-160

(95)

www.info.hotims.com/41432-95

(71)

www.info.hotims.com/41432-71

(173)

www.info.hotims.com/41432-173

(72)

www.info.hotims.com/41432-72

(82)

www.info.hotims.com/41432-82

Vega Americas, Inc. ............................23 (155) www.info.hotims.com/41432-155

Wood Group Mustang .........................34

(90)

www.info.hotims.com/41432-90

Wood Group Mustang ......................E-111

(89)

www.info.hotims.com/41432-89

Nace International .............................85 (170)

Worley Parsons .................................. 16 (152)

Neptune Research ..............................59 (163)

Zeeco ................................................67

Paharpur Cooling Towers, Ltd. ............123 (102)

ZymeFlow Decon Technology ..............75

www.info.hotims.com/41432-170

FourQuest Energy...............................28 (160)

(80)

www.info.hotims.com/41432-80

(78)

www.info.hotims.com/41432-86

(87)

www.info.hotims.com/41432-87

(91)

www.info.hotims.com/41432-85

(74)

www.info.hotims.com/41432-74

Chevron Lummus Global ................... 106 www.info.hotims.com/41432-91

(66)

www.info.hotims.com/41432-66

Linde AG ............................................34 www.info.hotims.com/41432-78

(62)

www.info.hotims.com/41432-62

(77)

www.info.hotims.com/41432-77

(94)

www.info.hotims.com/41432-94

Koch-Glitsch ..................................E-116

www.info.hotims.com/41432-81

(73)

www.info.hotims.com/41432-73

(81)

CB&I ..................................................93

(161)

www.info.hotims.com/41432-161

BIC Alliance........................................24 (156)

www.info.hotims.com/41432-55

(57)

www.info.hotims.com/41432-57

(98)

www.info.hotims.com/41432-79

(61)

www.info.hotims.com/41432-61

Bete Fog Nozzle ................................. 31

www.info.hotims.com/41432-164

(174)

www.info.hotims.com/41432-154

HyTorc ...............................................65 (165)

www.info.hotims.com/41432-156

Prosernat .......................................... 21

Rosemount Tank Gauging ...................29

Heurtey Petrochem ............................25

www.info.hotims.com/41432-98

RS#

Quest Integrity Group LLC....................22 (154)

Hermetic Pumpen GmbH ................... 44 (159) www.info.hotims.com/41432-68

Page

Website

www.info.hotims.com/41432-174

BASF Corporation ...............................83 (100) www.info.hotims.com/41432-100

Company

www.info.hotims.com/41432-163

www.info.hotims.com/41432-102

www.info.hotims.com/41432-152

(88)

www.info.hotims.com/41432-88

(92)

www.info.hotims.com/41432-92

This Index and procedure for securing additional information is provided as a service to Hydrocarbon Processing advertisers and a convenience to our readers. Gulf Publishing Company is not responsible for omissions or errors.

124 SEPTEMBER 2012 | HydrocarbonProcessing.com

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Automation Safety

WILLIAM M. GOBLE, CONTRIBUTING EDITOR wgoble@exida.com

‘Sticktion’: A dangerous failure mode I set a wet glass on the old wooden kitchen table at our home. It sat there all night. The next morning, when I went to grab the glass, it stuck to the table. Yes, this event has happened before. But, this time, it took a considerable yank to remove the glass from the wooden table. I do not know what type of finish was applied to this table; however, things do tend to “stick” to it.

While visiting the maintenance shop at a refinery, I was asking about solenoid valve, actuator and valve failures. One of the maintenance workers jumped in and told a story. “If I don’t go out there and turn that hand valve once a week, no one will ever be able to turn it again.” This sparked a discussion over the reasons for this phenomenon, and it became clear that mechanical devices that do not move for significant periods require higher force levels to begin movement.

intent was to detect when the assembly gets stuck. But it appears that the movement is also enough to reduce “sticktion.”

So is there a double benefit? And how often should there be testing? The answer varies depending on process conditions. In the worst-case scenario, performing a partialstroke test once a day or even once a shift (8 hours) would be sufficient to eliminate most “sticktion” failures. This is an improvement in safety. In addition, the well-designed partial-valve stroke test measures actuator pressure and valve position. Such monitoring can detect when “sticktion” is just beginning or has already occurred. Dangerous failure-rate reduction and detection of “sticktion” are a good combination to improve safety and reduce capital equipment and maintenance costs.

Changing minds. As I explained this idea to one safety engi-

‘Sticktion’: Action or condition? A search revealed quite

a bit of research on this subject. Several papers and articles used the word “sticktion” to describe this condition. One set of test data shows that the magnitude of the force required to move the part will increase with time left unmoved in position. Movement, even a small one, breaks the bonds that cause this problem. The movement force becomes significant after a day and increases until about 200 hours, where it levels off.

The comment from the shop employee makes sense; in this context, one week is 168 hours. Of course, there are many other variables, including temperature, materials, surface finish of metal parts, process materials, etc. The chance that a valve would not move is also related to a design parameter called the force/friction ratio. An informal online survey indicated that several engineers felt severe “sticktion” would occur only after a valve stayed in one position for about a month.

Opportunity for failure. The real problem with this failure

mode in safety systems is that most safety systems in the hydrocarbon processing industry take action to protect a process very infrequently. Often, such safeguard devices will sit motionless for years. When solenoid valves, quick-exhaust valves, actuators and valves have significant “sticktion,” this is a dangerous failure! It is obvious that the dangerous failure rate for these products will be much higher in applications in which movement is infrequent, as compared to those applications where the movement is frequent and regular. So what can be done?

Solutions. The concept of automatic partial-valve-stroke testing comes to mind. There are several products on the market designed to automatically move an actuator-valve assembly a small amount at predetermined time intervals. The original 126 SEPTEMBER 2012 | HydrocarbonProcessing.com

neer, he stopped me. No way was he going to implement any automatic partial-stroke testing. Why? He thought this would cause a false trip almost every time the test was conducted. I understand that a false trip is a huge deal in some processing situations. A false trip can not only be costly, but I am told by process experts that it may also cause a dangerous situation.

It is an absolute fact that the detailed part level failure modes and effects analysis shows that there are failures initiated by a false trip. However, this is no more likely than the conventional solenoid valve circuit!

Opportunities. Fortunately, more safety system design engineers are implementing partial-valve-stroke testing, and some are even configuring timed automatic partial-stroke testing. We will all be observing these installations for their results. I like to say, “Let the numbers answer this question.”

If the failure-rate numbers are even a rough predictor of field performance, we will soon know if the false-trip rate increases. It will take much longer to conclude if safety improves, but the automatic systems will, at least, do a good job of recording failure events. Does anyone want to place a bet on the expected false trip rate? I am most certainly betting on false-trip-rate reductions.

WILLIAM M. GOBLE is a principal partner of exida.com, a company that does consulting, training and support for safety-critical and high-availability process automation. He has over 25 years of experience in automation systems, doing analog and digital circuit design, software development, engineering management and marketing. Dr. Goble is the author of the ISA book Control Systems Safety Evaluation and Reliability. He is a fellow member of ISA and a member of ISA’s SP84 committee on safety systems.

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