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PROCESS CONTROL AND INFORMATION SYSTEMS ®

HydrocarbonProcessing.com | OCTOBER 2012

Better control systems and equipment vastly improve operations and contribute to increased safety and reliability, along with higher profits

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YOU CAN DO THAT Eliminate uncertainty, reduce your risk with DeltaV SIS. Emerson’s smart safety instrumented system provides an integrated, intuitive set of engineering tools and software that enables your team to handle configuration, alarms and device health monitoring–while maintaining the systems separation required by IEC 61511 and 61508 standards. The DeltaV SIS system reduces your training and lifecycle costs by eliminating complex data-mapping and multiple databases while helping to ensure that you’re meeting safety compliance. Learn more about safety processes and best practices by downloading the Safety Lifecycle Workbook at: www.DeltaVSIS.com/workbook Select 63 at www.HydrocarbonProcessing.com/RS

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

OCTOBER 2012 | Volume 91 Number 10 HydrocarbonProcessing.com

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SPECIAL REPORT: PROCESS CONTROL AND INFORMATION SYSTEMS

35 Update hydrocracking reactor controls for improved reliability A. G. Kern

41 Use a systematized approach of good practices in pygas hydrogenation via APC J.-M. Bader and G. Rolland

47 Why don’t we properly train control engineers? M. J. King

DEPARTMENTS

6 9 15 19 26 98 100

Brief Impact Innovations Construction Construction Boxscore Update Marketplace Advertiser index

51 Consider automated fault detection systems to improve facility reliability A. J. Szladow

COLUMNS

29

Reliability Equipment life extension involves upgrades

33

Integration Strategies Recent trends shape the future of DCS Water Management Consider software tools for water reuse projects

55 Optimize desulfurization of gasoline via advanced process control techniques V. Yadav, P. Dube, H. Shah and S. Debnath

REFINING DEVELOPMENTS

61 Maximize diesel production in an FCC-centered refinery, Part 2 P. K. Niccum

SULFUR—SUPPLEMENT

S-69 Optimize sulfur recovery from dilute H2S sources M. P. Heisel and A. F. Slavens

HEAT TRANSFER

83 Identify and control excess air from process heaters S. Ahamad and R. Vallavanatt

ROTATING EQUIPMENT

91 Apply new pump-drive software to test performance K. Bihler, D. Dominiak, B. Keith and J. Johnson Cover Image: Photo courtesy of Emerson Process Management

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| Brief New fuel standards in the US The US government recently finalized standards that will increase fuel economy to the equivalent of 54.5 mpg for cars and light-duty trucks by model year 2025. When combined with previous standards, this move will nearly double the fuel efficiency of those vehicles compared to new vehicles currently on the road. In total, the program to improve fuel economy is expected to reduce US oil consumption by 12 billion barrels. The standards issued by the US Department of Transportation (DOT) and the US Environmental Protection Agency (EPA) build on the previously issued standards for cars and light trucks for model years 2011–2016. Those standards raised average fuel efficiency by 2016 to the equivalent of 35.5 mpg.

BILLY THINNES, TECHNICAL EDITOR / [email protected]

Brief Valero has decided to further reduce operations and reorganize its 235,000-bpd Aruba refinery as a

refined products terminal, the company said. The terminal will feature both deepwater berths and smaller berths, and will have the flexibility to load the very largest crude ships. Terminal activities will, however, require a considerably smaller workforce, according to the company. The reorganization and reduction in workforce is expected to be complete before the end of 2012. Valero will continue to supply jet fuel, gasoline, diesel and fuel oil to the island, as well as engage in third-party terminal services. In the terminal operations mode, Valero will continue to invest in Aruba with facility improvements and dock and tankage upgrades, the company said. In the nearterm, the refinery will continue to be maintained in a state that would allow a restart, should Valero be successful in the pursuit of alternatives for the refinery prior to the terminal transition. US investment group Carlyle has agreed to buy the performance coatings business of DuPont for $4.9 billion

in cash. The transaction is expected to close in the first quarter of 2013, subject to customary closing conditions and regulatory approvals. DuPont Performance Coatings is a global supplier of vehicle and industrial coating systems, with 2012 expected sales of more than $4 billion and more than 11,000 employees. As part of the transaction, Carlyle will assume $250 million of DuPont’s unfunded pension liabilities. Carlyle’s industrial and automotive investments include Allison Transmission, Hertz and PQ Corp., as well as recent commitments to invest in Hamilton Sundstrand Industrial and regional rail freight operator Genesee & Wyoming. Enterprise Products recently began an open commitment period to determine additional shipper

demand for capacity on its Appalachia-to-Texas (ATEX Express) ethane pipeline. The 1,230-mile system will deliver growing ethane production from the Marcellus/Utica Shale areas of Pennsylvania, West Virginia and Ohio to Mont Belvieu, Texas. The open commitment period will be used to determine market interest in executing additional 15-year binding transportation agreements. The ATEX Express is expected to begin operations in the first quarter of 2014. Cosmo Oil will permanently close its 140,000-bpd Sakaide refinery in western Japan by July 2013 to meet

a government regulation that encourages refining capacity cuts amid falling local demand. The Japanese Ministry of Economy, Trade and Industry set rules in July 2010 requiring refiners to raise residual cracking capacity to a designated percentage of crude refining capacity, as calculated by a formula, by March 2014. By closing the refinery, Cosmo expects to save Y10 billion a year in costs.

Technip has completed the acquisition of the Stone & Webster process technologies and associated oil and

gas engineering capabilities. Technip sees this acquisition as a way to further diversify its onshore/offshore segment, adding revenues based on technology supply. It will also use the Stone & Webster brand to expand in promising growth areas such as the US, where downstream markets will benefit from the supply of unconventional gas. To make the most of these strengths, a new business unit, Technip Stone & Webster Process Technology, will be developed within the company’s onshore/offshore segment. Technip paid cash consideration of around €225 million from existing cash resources, which will be subject to customary price adjustments. Air Liquide has officially opened its first public hydrogen filling station for passenger cars in Düsseldorf, Germany.

This station will be followed by 10 new hydrogen filling stations that will be designed, built and rolled out in the next three years under the auspices of the German government’s major demonstration project. By 2015, Germany will have a supply network of at least 50 public hydrogen filling stations. Driven by the same dynamic, two other stations have been installed recently by Air Liquide in Oslo, Norway, and in Brugg, Switzerland. In Japan, the government sees hydrogen as a promising major energy source for cars and expects to install about 100 hydrogen distribution stations for fuel cell vehicles by 2015. In response to this government policy, Air Liquide Japan has recently set up a specialized team focused on the hydrogen business. So far, they have installed three hydrogen energy stations (in Tokyo, Kawasaki and Saga). One of these stations demonstrated the feasibility of a complete “blue hydrogen” chain, from wood chips to clean mobility. Western Refining and Glencore International announced that two of their subsidiary companies (York River

Fuels and Glencore Ltd.) have entered into a long-term commercial supply and trading agreement. Glencore has agreed to provide global sourcing, supply and trading and inventory and risk management services to support York River’s midAtlantic wholesale business. In return, York River has agreed to provide rack marketing and contract and credit management. Glencore has entered into a long-term commitment with Epic Terminals at its terminal in Savannah, Georgia. The Savannah terminal includes over 450,000 bbl of storage capacity for various grades of gasoline, distillates, ethanol, biofuels and fuel blends. The terminal will enable the two companies to expand their wholesale capabilities and provide fuel products to their customers from southern Georgia to northern Maryland. Western Refining operates refineries in El Paso, Texas, and Gallup, New Mexico. The company also runs products terminals in Albuquerque and Bloomfield, New Mexico. Hydrocarbon Processing | OCTOBER 20127

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Impact

Increased coal-to-olefins processes in China China’s significant domestic supply of coal, combined with a domestic shortage of several key chemical feedstocks, especially ethylene and propylene, are driving increased Chinese demand for more production of chemical feedstocks from coal, according to a new IHS study that assessed the key technologies and economics of coal-to-olefins (CTO) processes employed in China. The study noted that, in 2011, China had an ethylene capacity of 15.7 MMt and production of 14.4 MMt. On the demand side, China’s total ethylene equivalent consumption (including imports of first-order derivatives such as polyethylene) far exceeded its domestic ethylene supply. China imported nearly 8 million tons of polyethylene alone in 2011, accounting for 42% of total Chinese demand. In a new five-year plan covering 2011–2015, the Chinese set a target that 20% of the country’s ethylene production will come from other diversified sources, which for China—a country with abundant coal supplies that is a netimporter of oil—practically means coal. According to IHS, China’s domestic demand for oil was 9.4 million bpd in 2011, of which 57% was imported. Likewise, China’s propylene production was 13.1 MMt in 2011. On the demand side, China’s total propylene equivalent consumption, including imports of first-order derivatives such as polypropylene, also far exceeded its domestic propylene supply. China imported nearly 5 MMt of polypropylene alone in 2011, accounting for 30% of total demand. The propylene shortage in China is projected to stay at about 5 MMtpy until 2020. The processes studied included the gasification of bituminous coal by GE Texaco or Shell gasifiers to produce synthetic gases (syngas), followed by methanol synthesis and methanol-to-

olefins (MTO) production. The MTO technologies studied included UOP/ Hydro MTO and Lurgi methanol-topropylene (MTP) technologies. Economic evaluations were based on a US Gulf Coast location. However, since most coal-based olefin projects are occurring in China, the economics in the review were adjusted to reflect production and capital costs for a Chinese location. The adjustment was achieved by examining the variations in technologies deployed in China and accounts for capital investment, raw materials, utility and labor costs relative to the design basis used in the report. To address the country’s chemical feedstock shortage, China has built or is planning many high-capacity, integrated CTO and coal-to-propylene (CTP) plants. Thirteen plants are in the works, with four of those currently operational. According to the IHS review, all coalbased processes analyzed in the review showed lower direct costs, but higher indirect costs (due to high capital investments) as compared to competing (petroleum-based) processes for CTO and CTP, respectively. To enable baseline comparisons of chemical engineering processes for this review, return on investment (ROI) was the primary factor considered, and the costs were not weighted for environmental impact. For olefins production, based on the market price of olefins at the time of analysis, the MTO process based on outsourced methanol offers the highest ROI, followed by the integrated GE/ MTO process, and finally, steam-cracking of naphtha, which is a petroleumbased process. In terms of propylene production, based on the market price of propylene at the time of analysis, the MTP process based on outsourced methanol offers the highest ROI, followed by the integrated Shell/MTP process using bituminous coal, the integrated Shell/MTP using lignite, and finally, the integrated Siemens/MTP.

New nanoscale reference material to be known as P25 The National Institute of Standards and Technology (NIST) has issued a new nanoscale reference material for use in a wide range of environmental, health and safety studies of industrial nanomaterials. The new NIST reference material is a sample of commercial titanium dioxide powder commonly known as “P25.” NIST standard reference materials (SRMs) are typically samples of industrially or clinically important materials that have been carefully analyzed by NIST. They are provided with certified values for certain key properties so that they can be used in experiments as a known reference point. Nanoscale titanium dioxide powder may well be the most widely manufactured and used nanomaterial in the world, and, not coincidentally, it is also one of the most widely studied (FIG. 1). In the form of larger particles, titanium dioxide is a common white pigment. As nanoscale particles, the material is widely used as a photocatalyst, a sterilizing agent and an ultraviolet blocker (in sunscreen lotions, for example).

FIG. 1. The nanoscale crystalline structure of titanium dioxide in NIST SRM 1898 (color added for clarity). Hydrocarbon Processing | OCTOBER 20129

Impact “Titanium dioxide is not considered highly toxic and, in fact, we don’t certify its toxicity,” said NIST chemist Vincent Hackley. “But it’s a representative industrial nanopowder that you could include in an environmental or toxicity study. It’s important in such research to include measurements that characterize the nanomaterial you’re studying—properties like morphology, surface area and elemental composition. We’re providing a known benchmark.”

The new titanium dioxide reference material is a mixed phase, nanocrystalline form of the chemical in a dry powder. To assist in its proper use, NIST has developed protocols for properly preparing samples for environmental or toxicological studies. The new SRM also is particularly well suited for use in calibrating and testing analytical instruments that measure specific surface area of nanomaterials by the

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widely used Brunauer-Emmett-Teller gas sorption method.

Marginal increase forecast in North American lubricant market Although it is estimated that there will be a 3% increase in tonnage carried by private fleet operators in the US through 2016, this is expected to translate to a marginal increase in commercial lubricant consumption according to a new lubricants study from Kline and Company. On-highway activity saw a surge in the latter half of 2010 that continued well into 2011. Similarly, the lackluster performance of the construction industry between 2008 and 2010 has begun to show signs of a rebound. However, increased service implementation of longer drain interval oils due to a higher penetration of synthetics, growth in oil analysis practices, and an overall increase in commercial vehicles’ mechanical efficiency, mean that commercial lubricant consumption is expected to fractionally increase by a compound annual growth rate of just 0.4% to 1.0% to 2016. Shell remains the leading supplier of lubricants in North America and accounts for an estimated 12% of the market share in 2011, followed by ExxonMobil, Chevron and BP. With the growing realization of the benefits of synthetics and their consequent steady uptake, value is rising, while overall demand is being suppressed through inherently longer service intervals. Similarly, oil analysis—the laboratory analysis of a lubricant’s properties, suspended contaminants and wear debris—is being increasingly performed during routine preventive maintenance to provide meaningful and accurate information on lubricant and machine condition. By tracking oil analysis sample results over the life of a vehicle, lubricant consumption is optimized. Re-refined engine oils are slowly making their way into the commercial automotive segment; however, a majority of respondents participating in a survey for the research cited concerns about OEM approvals of such grades and the possible non-availability on the highways, as major deterrents. In particular, the US commercial trucking industry generally appears not yet prepared to accept re-refined oils;

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Impact with a majority of equipment/maintenance managers interviewed conceding that reliability and logistics issues are prime considerations and impediments. A number of farmers and farm cooperatives interviewed for this study showed minimal interest in using re-refined oils, believing that lubricants made out of re-refined basestocks are of an inferior quality. However, Tushar Raval, director of Kline’s energy practice, notes the opportunity by saying, “An immediate connect can be made by the way of marketing re-refined oils as ‘sustainable’

FIG. 2. Natural gas vehicles, like this Honda Civic, are starting to gain traction in the US.

products and consequently more easily find favor from the farming community. “Another way of successfully propagating the acceptance of these grades is by way of approvals and recommendations from OEMs, such as John Deere,” Mr. Raval said.

Natural gas vehicles could be gaining traction

A new report from PIRA Energy Group says that the sheer volume of US recoverable gas resources relative to expected demand suggests that benchmark Henry Hub gas prices will remain deeply discounted relative to oil prices beyond this decade. Furthermore, the lengthy period of low-cost gas relative to oil has tremendously broadened support for the view that inexpensive North American gas is here to stay. According to the report, by employing off-the-shelf technologies, consumers could be able to accrue substantial savings given the latent expected price advantages of natural gas vs. diesel. Such savings can also be attained in the transportation sector, particularly

with regard to the much discussed development of natural gas vehicles (NGVs) (FIG. 2). The report concludes that future gas demand in such NGVs has enormous upside potential, led by private sector initiatives, with or without federal government assistance. Adoption of natural gas into both US commercial trucking and all varieties of fleets is approaching a critical threshold, which ultimately could lead to enormous gas demand growth at the expense of diesel fuel. In an overall high case scenario, NGV gas demand would be capable of reaching 14 Bcfd by 2030, suggesting that as much as 2.4 MMbpd of diesel fuel demand could be at risk. Liquefied natural gas (LNG) consumed in Class 8 trucks would be responsible for approximately 70% of that total, 10 Bcfd. Fleet vehicles typically consuming compressed natural gas (CNG) would account for the additional 4 Bcfd. PIRA forecasts natural gas will capture a more moderate, but also impressive, 7 Bcfd share of the US on-highway transportation fuels market by 2030.

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ADRIENNE BLUME, PROCESS EDITOR [email protected]

Innovations Invensys introduces new technology offerings Software and technology provider Invensys Operations Management recently released a program to help clients modernize and improve the performance of aging control systems and other plant equipment. The program guides clients in calculating modernization costs, reducing risk, deploying advanced technology, and approaching plant upgrades strategically and systematically. Under the program, Invensys will deliver full-scope consulting, project management, engineering, installation and maintenance services, and products and solutions that minimize the risk of operating obsolete technologies. Invensys starts with an assessment to understand the company’s business initiatives and issues. The input received is used to develop a strategic plan that meets the plant’s business and technology needs. As part of the assessment, Invensys also helps clients establish return-on-investment targets. The company’s hardware and software offerings address all operational areas of the plant, including instrumentation, input/output (I/O) and human/machine interface (HMI), safety and critical control systems, turbomachinery assets, process safety lifecycle components, cyber security systems and other assets. In another development, Invensys has extended its virtualization technology offerings. Initially focused on the Microsoft HyperV and VMware platforms within its software product lines, the new Invensys offering now includes thin client support and intelligent solutions for the company’s Foxboro I/A series distributed control system (FIG. 1). Intended to lower total cost of ownership and promote successful project delivery, the new offerings will help customers cut implementation costs, reduce risks, shorten project schedules, improve scheduling integrity, strengthen the ability to respond to project changes, and improve global collaboration.

The hardware offerings are formulated to maximize the advantages of virtualization technology. Along with intelligent marshalling and engineering services, the offerings include a new range of servers specifically selected and qualified as an optimized virtual machine-hosting appliance, a new range of solid-state operator client terminals, thin client management software, a USB modular alarm annunciator keyboard, virtual machine-hosting software, recommendations on cybersecurity best practices, guest operating system licenses, and specialized support for Invensys control and safety offerings.

and timed events on chromatograms following instrumental variation over time. Select 2 at www.HydrocarbonProcessing.com/RS

Largest German cellulosic ethanol plant starts up Swiss specialty chemicals company Clariant recently inaugurated Germany’s biggest pilot plant (FIG. 3) in Straubing, Bavaria. The €28 million (MM) plant, which is based on Clariant’s sunliquid

Select 1 at www.HydrocarbonProcessing.com/RS

Integrated chromatography aids fuel producers Bruker’s Chemical and Applied Markets (CAM) division’s CompassCDS data handling system (FIG. 2) networks gas chromatograph (GC) instruments into closed-loop information systems in industrial and applied environments. The system is capable of interfacing with multiple middleware systems, such as supervisory control and data acquisition (SCADA) systems and laboratory information management systems (LIMS). This ensures an unbroken flow of information and rapid feedback of analytical results to support optimum processing and product validation. Additionally, by removing the need for human intervention, the risk for errors is reduced. The CompassCDS product is built around a central administrative core, known as the “configuration manager.” There are several customized modules that are specific to the petrochemicals industry, including simulated distillation, hydrocarbon analysis and PIONA+ (paraffins, isoparaffins, olefins, naphthenes and aromatics, plus oxygenates). A simple graphical user interface allows all operations to be carried out from only two screens, which enables ease of use and expedites training. Additionally, the system’s added IntelliUpdate feature automatically corrects both retention time

FIG. 1. Invensys’ virtualization system allows the user to consolidate many PCs and servers into a high-availability virtual host server.

FIG. 2. Bruker CAM’s CompassCDS system networks gas chromatograph instruments with infosystems. Hydrocarbon Processing | OCTOBER 201215

Innovations technology, will produce up to 1,000 metric tons of cellulosic ethanol from around 4,500 metric tons of wheat straw. The pilot plant will confirm the technological feasibility of the sunliquid technique, and the process will later be used in an industrial-scale plant. According to studies, Germany potentially has around 22 MM metric tons of straw that could be used for energy production, which would be sufficient to cover around 25% of the country’s current gasoline requirements. German Federal Minister Annette Schavan commented, “This plant clearly demonstrates that products traditionally based on petroleum can be manufactured to the same standard using biomass. This new plant serves as an important contribution to a sustainable bioeconomy.” Select 3 at www.HydrocarbonProcessing.com/RS

Software protects against cyber attacks Honeywell’s Management of Change (MOC) is an integrated, add-in module that runs on top of DOC4000 assessment software and leverages Web 2.0 technologies to facilitate information flow and collaboration. MOC enables increased safety and compliance, and it helps protect against threats of cyber attacks and safety

FIG. 3. Clariant’s cellulosic ethanol pilot plant in Straubing is the largest in Germany.

hazards at plants, by effectively managing changes and approvals. FIG. 4 illustrates the workflow process for MOC. MOC also enables improved handling of critical issues, including undocumented changes, enhanced regulatory compliance, reductions in error-prone manual MOC tasks, and unauthorized changes that increase risk. The module is specifically designed to automatically detect all automation changes, to reconcile MOC cases to changes in the automation system, and to automatically generate reports of unreconciled changes, all at a 45% lower cost than manual methods. This enables rapid root-cause analysis to ensure business continuity, and it can reduce potentially significant financial impact on production. Select 4 at www.HydrocarbonProcessing.com/RS

Technology enables ethanol production breakthrough As countries and companies evaluate their supply options to meet growing transportation fuels demand, they will need to balance four priorities: safe and clean fuel blendstocks, cost, energy security, and global environmental impact. Celanese believes that ethanol produced using Celanese TCX Technology (FIG. 5) is the best fuel choice to meet these considerations. Ethanol has already gained acceptance in most global markets as a high-octane, nontoxic, biodegradable fuel. However, traditional production processes are not economically viable, as they compete for arable land and typically require government mandates or subsidies. Celanese TCX Technology produces ethanol in a commercially viable, lowcost manner, from locally available hydrocarbon resources such as natural gas and coal, rather than from corn or sugar cane. For these reasons, no arable land use or government support is required. Select 5 at www.HydrocarbonProcessing.com/RS

FIG. 4. Honeywell’s MOC software helps protect plants against safety threats.

FIG. 5. Celanese’s TCX Technology produces ethanol from hydrocarbons.

16OCTOBER 2012 | HydrocarbonProcessing.com

FIG. 6. Yokogawa’s STARDOM FCN controller has been certified for use as a flow computer.

Yokogawa’s controller certified as flow computer Yokogawa Electric Corp.’s STARDOM FCN autonomous controller (FIG. 6) was recently certified by Measurement Canada for use as a flow computer. The certification is based on the determination that the controller has the same accuracy as a conventional flow computer. Devices subject to its approval are used to measure gas, electricity, mass and volume, and they are tested on a broad range of criteria including design, construction, marking, accuracy and sealing method. While conventional flow computers meet all metering requirements, there is now a trend toward embedding this functionality in programmable logic controllers (PLCs) and remote telemetry units (RTUs), which are valued for their durable construction and versatile control capabilities. In addition to conventional analog transmitter signals, which can be affected by noise and variations in the ambient temperature, the STARDOM FCN controller supports field digital communication protocols such as HART, Modbus, and Foundation fieldbus for use with a wide range of transmitters. Yokogawa’s plant resource manager (PRM) asset management system increases maintainability while reducing both engineering time and the cost of monitoring widely distributed facilities. Select 6 at www.HydrocarbonProcessing.com/RS

SPECTRO wins ACHEMA Innovation Award At the ACHEMA chemical engineering and biotechnology trade show in Frankfurt, Germany, in June, SPECTRO Analytical Instruments received the Innovation Award for its SPECTROBLUE ICP-OES spectrometer (FIG. 7). Introduced in 2011, the SPECTROBLUE ICP-OES spectrometer is targeted for environmental laboratories in need of quick and accurate analyses of water, wastewater, sewage sludge and soil samples for toxic heavy metals. SPECTROBLUE’s air-cooled, optical plasma interface diverts heat away with an air stream, marking an advance in spectrometer technology. Another innovative feature of SPECTROBLUE is its improved sample introduction. SPECTRO has significantly

Innovations shortened the path of the sample into the plasma, which decreases the duration of the analysis and reduces carryover effects. SPECTROBLUE’s operating software also includes new, user-friendly functions, such as a comprehensive Smart Analyzer Vision software package and a Smart User Interface that simplifies routine operation. Select 7 at www.HydrocarbonProcessing.com/RS

Mobile tool enables portable pH reading Sensorex has developed a mobile accessory for pH measurements that is compatible with Apple iPod, iPhone and iPad devices. The patent-pending PH-1 pH meter accessory (FIG. 8) measures and records pH values in the lab or field for use in environmental, educational and industrial applications. The PH-1 accessory plugs into the standard Apple dock connector and is powered from the Apple device, requiring no supplemental energy source. It uses a Sensorex pH electrode to measure pH in a range of 0–14, with accuracy to 0.01 pH. It operates in ambient temperatures of 0°C–40°C and in solutions of 0°C–100°C. The free Sensorex app displays pH, millivolts, ambient temperature and solution temperature in real time. The CEmarked device supports one, two, three or more calibration points, and it sends readings by email for later analysis. Also, when used with a GPS-enabled device, the pH meter application will record measurements with both timestamp and

geographic coordinates, eliminating transcription errors and improving efficiency. Select 8 at www.HydrocarbonProcessing.com/RS

French consortium eyes BioOil upgrading Axens, IFP Energies nouvelles (IFPEn) and Dynamotive recently announced completion of agreements for the development, industrialization and commercialization of a proprietary process to produce transportation fuels from Dynamotive’s BioOil pyrolysis oil. The process is said to have competitive advantages compared to existing processes and competing technologies. Dynamotive will provide pyrolysis oil to IFPEn for the development program, while Axens will lead the development, industrialization and commercialization of the upgrading technology. Laboratoryscale units have been developed and operated in Canada and at IFPEn facilities in Lyon, France, where Dynamotive’s BioOil was upgraded to synthetic hydrocarbons. Dynamotive’s BioOil technology is based on the application of fast pyroly-

sis (burning without oxygen) to biomass waste (agricultural and forestry) to produce a high-quality, versatile and economic biofuel. BioOil can be further converted into vehicle fuels and chemicals. Select 9 at www.HydrocarbonProcessing.com/RS

FIG. 8. Sensorex’s mobile accessory for pH measurements is compatible with a range of Apple devices.

Recruiting “A-level” candidates for your C-level positions (Management & Sales positions also) Providing executive recruiting services to the energy markets.

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For a confidential C-level executive search or placement of management or sales positions, please call Thomas Brinsko or Raul Hernandez in Houston at 281-538-9996 or visit www.bicrecruiting.com.

FIG. 7. SPECTRO Analytical Instruments was awarded at ACHEMA for its SPECTROBLUE spectrometer.

For more information on strategic marketing through BIC Alliance, investment banking services through IVS Investment Banking or custom books, event planning or speaker services through BIC Media Solutions, contact Earl Heard or Thomas Brinsko at (800) 460-4242, or visit www.bicalliance.com.

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HELEN MECHE, ASSOCIATE EDITOR [email protected]

Construction

North America Jacobs Engineering Group Inc. has a contract from Methanex Corp. to provide engineering, procurement and construction services for a methanol production facility in 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, Louisiana, from its offices in Baton Rouge, with support for the disassembly from its Santiago, Chile, office. The plant is expected to be operational in the second half of 2014. KBR has a general works contract for phase-two construction at a raw gasprocessing and compression facility near Dawson Creek, British Columbia, Canada. KBR’s Canadian subsidiary, KBR Wabi, will execute construction and related site support for the facility’s expansion, increasing the existing capacity to 100 million scfd. The award follows KBR’s recent work—delivering pipe-rack fabrication and module assembly for phase one of the Dawson Creek plant. A joint-development agreement, focusing on bio-based butadiene, has been signed by INVISTA and LanzaTech to develop one-step and two-step technologies for converting industrial waste-gas carbonmonoxide (CO) into butadiene. Initial commercialization is expected in 2016. Initially, the focus will be on producing butadiene in a two-step process from LanzaTech CO-derived 2,3-butanediol (2,3 BDO). A direct single-step process will also be developed to produce butadiene directly through a gas-fermentation process. INVISTA and LanzaTech will also jointly collaborate on developing tools that will extend this technology—once developed—to directly produce other industrial chemicals. These include nylon intermediates, from CO containing waste gases, using LanzaTech’s gas-fer-

mentation technology and proprietary biochemical platform. INVISTA is building internal biotechnical capability to develop biological routes to its products and feedstocks. Praxair, Inc., has broken ground on its new air-separation unit in Memphis, Tennessee. With a capacity of 600 tpd, the new plant is scheduled to start up in the second quarter of 2013. INVISTA has selected its production facility in Orange, Texas, as the initial location to install its next-generation adiponitrile (ADN) technology. ADN is a critical intermediate chemical used in the manufacture of nylon 6,6. The project to convert the Orange site to the new technology is well underway, and INVISTA is expected to invest more than $100 million at the facility in the next 18 months. The technology, a new butadienebased chemistry, is said to improve product yields and ease of operations, while requiring a lower annual-maintenance investment compared to existing technology. Evidenced through operation of a pilot-scale facility, also located in Orange, the technology also delivers significant air emission and waste reductions. The company hopes to be in full production by mid-2014. Cheniere Energy Partners, L.P. has completed all milestones and has issued Bechtel Oil, Gas and Chemicals, Inc., with a full notice to proceed on construction of the Sabine Pass Liquefaction Project’s first two liquefaction trains. The first liquefaction train is expected to start operations as early as 2015. The second liquefaction train is expected to commence operations six to nine months after the first train’s startup. Flint Hills Resources is considering spending more than $250 million to enable its West refinery in Corpus Christi, Texas, to process more Eagle Ford crude

oil, while extending its ability to reduce criteria air emissions. The company operates two Corpus Christi refineries: the West refinery, with a capacity of about 230,000 bpd, and the East refinery, with a capacity of about 70,000 bpd. Flint Hills Resources expects to submit the permit applications to the Texas Commission on Environmental Quality and the US Environmental Protection Agency in the coming weeks.

South America A subsidiary of Foster Wheeler AG’s Global Engineering and Construction Group has a contract from Petrobras for a world-scale grassroots gas-to-chemicals complex—Complexo Gás-Químico UFN-IV—in Linhares, Espirito Santo State, Brazil. Foster Wheeler will provide basic engineering design (BED), front-end engineering and design (FEED), as well as technical assistance and training during the engineering, procurement and construction (EPC) phase through to successful completion of plant performance tests. The BED and FEED will be included in the company’s third-quarter 2012 bookings. The provision of technical assistance and training will be booked at a later date, after the FEED is complete, when Petrobras advises that it is proceeding with the project’s EPC phase. TREND ANALYSIS FORECASTING Hydrocarbon Processing maintains an extensive database of historical HPI project information. The Construction Boxscore Database is a 45-year compilation of projects by type, operating company, licensor, engineering/constructor, location, etc. Many companies use the historical data for trending or sales forecasting. The historical information is available in commadelimited or Excel® and can be custom sorted to suit your needs. The cost depends on the size and complexity of the sort requested. You can focus on a narrow request, such as the history of a particular type of project, or you can obtain the entire 45-year Boxscore database or portions thereof. Simply send a clear description of the data needed and receive a prompt cost quotation. Contact Lee Nichols at 713-525-4626 or [email protected]

Hydrocarbon Processing | OCTOBER 201219

Construction Foster Wheeler will act as integrator for the entire complex, managing the overall BED and FEED, including managing the process licensors and Brazilian subcontractors. The BED/FEED phase is scheduled for completion at the end of 2013. The complex is expected to produce in excess of 1 million tpy of ammonia and urea fertilizers, methanol, acetic acid, plus formic acid and melamine, helping to reduce Brazil’s imports of these products.

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Clariant has inaugurated what is said to be Germany’s biggest pilot plant for producing climate-friendly cellulose ethanol from agricultural waste. Located in Straubing, Bavaria, and supported by the Bavarian government and the Federal Ministry for Education and Research, the futuristic project will produce up to 1,000 tons of cellulose ethanol from around 4,500 tons of wheat straw based on Clariant’s sunliquid technology. It represents an investment of around €28 million. The sunliquid process is an innovative biotechnological method that turns plant waste products, such as grain straw and corn straw, into second-generation cellulose ethanol. Marquard & Bahls, through its subsidiary Bomin, and The Linde Group, will establish a joint-venture ( JV) company to build infrastructure for liquefied natural gas (LNG) in Europe’s maritime sector. The transaction is subject to the approval of the relevant antitrust authorities. The 50/50 JV is due to start its operations in the latter part of 2012, with its headquarters based in Hamburg, Germany. The JV will set out to establish an LNG supply chain and to provide reliable, safe and environmentally friendly fuel to ship owners and operators. Linde will contribute its vast experience in cryogenics and its best-in-class engineering know-how, while Bomin will support the JV with its excellent track record in maritime bunker-fuel trading and operations. The new company will establish operations in a number of key ports throughout the so-called “emission control areas” in Northwest Europe. CB&I has an award from BASF for the engineering, procurement and construction management of a new butadieneextraction plant in Antwerp, Belgium.

The contract, which is valued in excess of $50 million, is an essential part of the total BASF investment amount, which will be in the high double-digit million euro range. The plant is scheduled to start up during 2014. Jacobs Engineering Group Inc. has a five-year enterprise frame agreement (EFA) from Shell Global Solutions International B.V. to provide engineering and project management services to Shell’s European downstream assets. The contract has the options to be renewed for an additional five years and/or to be extended to other Shell businesses such as upstream, and beyond Europe to the Middle East and Africa. Under the EFA, Jacobs will provide services ranging from feasibility studies and small plant modifications to discrete projects for Shell’s major refining and chemical sites in Pernis, The Netherlands, and in Rhineland, Germany. UOP LLC, a Honeywell company, has been selected by Lukoil to provide technology to produce blending components used to make high-octane gasoline and petrochemicals at Lukoil’s 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 new units, expected to start up in 2015, will produce more than 1 million metric tpy of gasoline-blending components and more than 170,000 metric tpy of propylene. In addition to technology licensing, Honeywell’s UOP and a number of its affiliates will provide engineering design, catalysts, adsorbents, equipment, staff training and technical service for the project. Honeywell’s UOP technology to be used in this project includes: Honeywell’s UOP FCC process, to convert straightrun atmospheric gasoils, vacuum gasoils, certain atmospheric residues and heavy stocks recovered from other refinery operations into high-octane gasoline, propylene and light fuel oils; Honeywell’s UOP HF Alkylation process to produce a high-quality gasoline-blending component, typically referred to as alkylate; Honeywell’s UOP Caustic Merox process to remove sulfur from liquefied petro-

Construction leum gas (LPG) streams; Honeywell’s UOP Huels Selective Hydrogenation Process (SHP) to minimize acid consumption in the alkylation unit, produce 2-butene and maximize alkylate yields; and Honeywell’s UOP Butamer process to convert butane to isobutane, a primary feedstock used to produce alkylate in the HF Alkylation process. LANXESS has chosen Burckhardt Compression to deliver one process gas compressor for its chemical production site in Leverkusen, Germany. The compressor will be used to compress ethylene from 17 bara to 495 bara. In addition, Burckhardt Compression (Deutschland) GmbH has been awarded an order from LANXESS to revamp two existing process gas compressors. A gas-to-liquids (GTL) project in Uzbekistan was named OLTIN YO’L GTL at a formal ceremony in Tashkent involving representatives from the three jointventure ( JV) companies: Uzbekneftegaz, Sasol and PETRONAS. The naming of the JV project followed a ceremony to mark the start of infrastructure development by the Government of Uzbekistan at the proposed GTL plant site at Shurtan in the south of Uzbekistan. It also aimed at supporting the project schedule to enable a final investment decision, which is expected during the second half of 2013. When commissioned, the 38,000-bpd plant will produce a combination of GTL diesel and GTL naphtha and, in an important development in the application of GTL fuels, GTL kerosine for the aviation sector. Neste Oil has completed the first phase of its project to build a pilot plant for producing microbial oil. Plant construction is on schedule and on budget. The first phase will enable the growth of oil-producing microorganisms, and the following phases will concentrate on raw material pretreatment and oil recovery. The goal is to develop the technology so that it is capable of yielding commercial volumes of microbial oil for use as a feedstock for NExBTL renewable diesel. Commercial-scale production is expected by 2015 at the earliest. The pilot plant is expected to be fully complete in the second half of 2012, and

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21

Construction it represents an investment of approximately €8 million by Neste Oil. Microbial oil technology is attractive because of its efficiency and sustainability. Neste Oil has carried out pioneering research in the field and has applied for numerous patents covering its microbial oil technology. A number of partners have been involved in this work, including Aalto University.

pacity of several thousand metric tpy, is scheduled for completion in mid-2013. The investment, in the company’s largest production site worldwide, is in the mid double-digit million euro range. The new plant can make optimum use of the existing infrastructure and raw material supplies, and utilize synergies with the current polybutadiene plants in the Marl Chemical Park.

In May 2012, ThyssenKrupp Uhde won a front-end-engineering and design contract for a single-train polypropylene (PP) plant based on LyondellBasell’s Spheripol process technology for ZapSibNeftekhim L.L.C, a wholly owned subsidiary of SIBUR. The 500,000-tpy plant is planned to be constructed in Tobolsk, Russian. The plant will produce a wide range of highquality PP brands.

Middle East

Evonik Industries has laid the foundation stone for a new, large plant to produce functionalized polybutadienes in Marl, Germany. The plant, with a ca-

KAR Group has announced the third expansion of its Kalak refinery to 185,000 bpd. Process units and utilities are being provided by Ventech Engineers LLC of Pasadena, Texas. Ventech has provided modularized crude-distillation units, naphtha hydrotreaters, catalytic reformers, isomerization units and demercaptanization systems, as well as gas plants and supporting utilities to the project. This is the refinery’s third expansion, and is a continuation of Ventech’s modular construction methods. The first phase utilized 26 process modules to add 20,000 bpd of refining capacity to KAR’s

existing 20,000-bpd plant. The subsequent second phase provided an additional 60,000 bpd of total refining capacity and was completed in 2011. The third expansion consists of two 30,000-bpd modular complexes at the same site, as well as a 15,000-bpd condensate-processing facility. Once this latest phase is complete and operational, total capacity at the Kalak refinery will be over 185,000 bpd, and it will reportedly remain the country’s sole producer of unleaded gasoline, as well as the largest privately owned refinery in Iraq. Construction has started in Abu Dhabi, of what is said to be the largest Claus plant in the world. By the end of 2013, once construction is complete, Haldor Topsøe will supply the plant with 380 tons of the gas-treating catalyst TK-220. TK-220 is a CoMo hydrotreating catalyst specifically developed for treating tail gases derived from Claus or other similar units. The delivery is part of an agreement that Haldor Topsøe has made with BASF.

Simultaneous heat transfer and mass transfer model in column. Good thinking. Feedback from our users is what inspires us to keep making CHEMCAD better. Many features, like this one, were added to the software as a direct response to user need. That’s why we consider every CHEMCAD user part of our development team.

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Construction Asia-Pacific Jilin Qianyuan Energy Development has selected Chemtex, along with Black & Veatch’s patented PRICO LNG technology, to deliver a major liquefied natural gas (LNG) facility. Expected to be completed in late 2013, the 500,000-Nm3/d plant will reportedly be the largest of its kind in Northeast China. It will be delivered by the Chemtex/Black & Veatch team using a complete lump-sum engineering, procurement and construction package. The new facility will liquefy inlet pipeline natural gas. The LNG will be used primarily by trucks and other vehicles as an alternative fuel to diesel and petrol. In addition to utilizing PRICO technology, the plant integrates a nitrogen-stripping process. This will contend with high nitrogen levels in the pipeline feed gas. A special boil-off gas reliquefaction system will also be installed to prevent unnecessary fuel loss and increase plant efficiency. GTC Technology US, LLC, is licensing its GT-BTX extractive distillation

process to produce high-purity aromatics at Reliance Industries’ Jamnagar refining and petrochemical complex in Gujarat, India. This license is part of a consortium with CB&I Lummus Technology to supply technology for a multiunit complex for benzene and paraxylene production. Australia Pacific LNG has selected technology developed by Honeywell Process Solutions (HPS) Advanced Solutions business to deliver a data consolidation and reporting technology framework. The solution, built on Intuition Executive, will support the production, operations and asset-management functions of its world-class coal-seam gas (CSG) to liquefied natural gas (LNG) project. Origin, the upstream operator of the Australia Pacific LNG project, is the largest producer of CSG in Australia, supplying gas to power stations to produce electricity with lower greenhouse gas emissions. Australia Pacific LNG’s operational framework, built on Intuition Executive,

will support improved communication and data management, cross functional workflows and improved notification of key operational events to better analyze, prioritize, automate, and manage operational tasks and abnormal situations. Air Liquide has laid the first stone of a new hydrogen plant through a longterm agreement with Zhejiang Huafon Spandex Co., Ltd. (Huafon) to supply hydrogen for its 120,000-tpy cyclohexanone project located in Liaoyang Aromatics and Fine Chemical Park, Liaoyang city, China. Under the agreement, Air Liquide will invest in a new steam methane reformer (SMR) unit that will supply 13,000 Nm3/ hr of hydrogen, as well as steam to Huafon via pipelines. This new unit, which is expected to be commissioned by the end of 2013, uses Lurgi’s latest technologies providing high reliability, world-class safety and energy efficiency, and will be designed and manufactured by the Air Liquide engineering and construction team based in Shanghai.

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Hydrocarbon Processing | OCTOBER 201223

Construction SIBUR Petrochemical India, a subsidiary of SIBUR, has started operations in Mumbai, India. The company’s primary focus is to construct a butyl-rubber facility in Jamnagar. The plant, which will operate at a capacity of 100,000 tpy, is being built as a joint venture with Reliance Industries. The new subsidiary will work alongside Indian partners, as well as provide support to SIBUR employees coming to India to carry out installation and startup work at the new plant. Synthesis Energy Systems, Inc.’s syngas production facility for its Yima joint-venture ( JV) coal-to-methanol project in Henan Province, China, completed a test run of the first of three gasifiers currently under commissioning. During the commissioning phase, each of the three gasifiers will be operated under various test conditions to vet the gasifier and support systems to prepare the facility for commercial operation. This test was the first for this gasifier system operating on oxygen from the project’s air-separation unit.

Coal supplied by Yima was introduced into the gasifier, which operated for several hours while the Yima JV team successfully gathered data that will help in preparation for plant startup. The project will continue in the commissioning phase for several more weeks and is expected to move into commercial operation later in 2012. Intergraph has a contract with Santos for the use of SmartPlant Enterprise for Owner Operators (SPO), along with other SmartPlant Enterprise solutions. Santos will use Intergraph technology to manage its existing facilities and those in its Gladstone liquefied natural gas (GLNG) project in Queensland, Australia. Santos GLNG will use world-leading technology to process coal-seam gas (CSG) into LNG. The project is a partnership between Santos (operator), PETRONAS, Total and KOGAS. SPO enables Santos to address interoperability issues, while enhancing plant safety and reliability, quality and

productivity. In addition to SPO, Santos has implemented SmartPlant 3D, SmartPlant Foundation, SmartPlant Instrumentation, SmartPlant Electrical, SmartPlant P&ID and Leica Geosystems laser-scanning solutions, and also used the Intergraph Data Conversion Center for converting P&ID drawings into intelligent data. Besides the GLNG project, Santos will also use these design and engineering solutions for the entire life cycle of its facilities for both greenfield and brownfield projects, with plans to extend these solutions to its existing facilities within the Asia-Pacific region. CB&I has a contract with the Hebei Haiwei Group for the license and basicengineering design of a grassroots propane dehydrogenation unit to be located in Jingxian, Hebei Province, China. The unit will use the CATOFIN propane dehydrogenation process from Lummus Technology, which uses Süd-Chemie’s latest CATOFIN catalyst to produce 500,000 metric tpy of propylene. The unit is expected to start up in 2015.

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ZZZDPDFVFRP‡KU(0(5*(1&W'ƌĞĐŽǀĞƌLJĂŶĚĨƌĂĐƟŽŶĂƟŽŶƉƌŽĐĞƐƐ ͻZĂƚĞŚĞĂƚĞdžĐŚĂŶŐĞƌƐŝŶĐůƵĚŝŶŐďƌĂnjĞĚĂůƵŵŝŶƵŵ ͻWƌĞĚŝĐƚŽƉƟŵĂůĞdžĐŚĂŶŐĞƌƉĞƌĨŽƌŵĂŶĐĞǁŝƚŚĂĐƟǀĞƌĂƟŶŐĚƵƌŝŶŐƐŝŵƵůĂƟŽŶ ͻĞƚĞƌŵŝŶĞŚLJĚƌĂƚĞĨŽƌŵĂƟŽŶĂŶĚK2ĨƌĞĞnjĞͲŽƵƚƚĞŵƉĞƌĂƚƵƌĞƐƵƐŝŶŐďĞƐƚͲŝŶͲŝŶĚƵƐƚƌLJƉƌĞĚŝĐƟŽŶƐ ͻ^ŝnjĞƚǁŽĂŶĚƚŚƌĞĞƉŚĂƐĞƐĞƉĂƌĂƚŽƌƐ ͻhƐĞdžĐĞůƚŽƉĞƌĨŽƌŵƉĂƌĂŵĞƚƌŝĐƐƚƵĚŝĞƐĂŶĚĞĐŽŶŽŵŝĐĂŶĂůLJƐĞƐ ͻĂůĐƵůĂƚĞŚLJĚƌĂƚĞŝŶŚŝďŝƚŽƌƌĞƋƵŝƌĞŵĞŶƚƐƵƐŝŶŐƵŶƐƵƌƉĂƐƐĞĚDĞK,ͬ,2Kͬ,ƉƌĞĚŝĐƟŽŶƐ ͻ^ŝŵƵůĂƚĞĂŶĞŶƟƌĞƉƌŽĐĞƐƐĨĂĐŝůŝƚLJƵƐŝŶŐŵƵůƟƉůĞŇŽǁƐŚĞĞƚĚĞƐŝŐŶ ͻDŽĚĞůĂŵŝŶĞƚƌĞĂƟŶŐ͕ĚĞŚLJĚƌĂƟŽŶ͕ĐƌLJŽŐĞŶŝĐ͕ĂŶĚĨƌĂĐƟŽŶĂƟŽŶĨĂĐŝůŝƟĞƐŝŶƚŚĞƐĂŵĞƉƌŽũĞĐƚ

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Special Report

Process Control and Information Systems J.-M. BADER and G. ROLLAND, Axens, Rueil-Malmaison, France

Use a systematized approach of good practices in pygas hydrogenation via APC As illustrated in FIG. 1, steam crackers produce many basic building blocks for the polymer industry, along with aromatic-rich gasoline (pygas). When naphtha is used as the feed for cracking furnaces, pygas yields increase significantly. TABLE 1 shows the typical pygas yield and composition for naphtha cracking. Pygas is a large contributor to benzene production capacities. Before the pygas can be routed to downstream units (aromatics extraction, etc.), unstable compounds such as diolefins and styrenics must be removed. Also, olefins and sulfur must be eliminated to ensure that final products will meet their specifications. This pygas treatment is achieved through hydrogenation steps. However, if the pygas treating is not optimized, then other undesired processing operations—including hydrogen flaring, reactor channeling, poor use of the second beds, and other issues—have a greater possibility of occurring. Optimizing control. Advanced process control (APC) offers a solution to systematize implementing best practices, avoid mis-operation, and generate substantial benefits. The following case study describes the operational improvements and steps necessary when applying APC. This case study will apply actual plant data to demonstrate and quantify the benefits attainable from APC installations.

PROCESS A case study will describe the industrial results obtained with the two-stage pygas hydrogenation process (PGH), as TABLE 1. Typical naphtha cracker pygas (C5–200°C) yield and composition

shown in FIG. 2. This PGH unit includes a first-stage process (GHU-1) to improve the stability of the raw pyrolysis gasoline by selectively hydrogenating diolefins and alkenyl compounds, thus making it suitable for further processing in the second stage. The reaction is carried out mainly in the liquid phase on a specific catalyst in a fixed-bed reactor. The selected operating conditions maximize conversion of the diolefins and alkenyl aromatics, while minimizing the formation of heavy products by polymerization. These operating conditions minimize aromatics loss. In the second stage of PGH (GHU-2), the C6–C8 heart cut is further processed to prepare a feedstock suitable for H2 + CO C2 C3 Steam cracker

Feed

C5 – C10

Propylene

C3 hydrogenation

Butene, butadiene

C4 hydrogenation

C5 – BTX –C9+

Pygas hydrogenation

Fuel

FIG. 1. Pygas production and other products from a steam cracker. H2

Pygas feed D

Rx 1

Paraffins + naphthenes

11.8

Olefins

5.5

Diolefins

18.1

Benzene

28

Toluene

13.9

Xylenes

7.2

Styrene

3

Total aromatics

Ethylene

C2 hydrogenation

200° +

Composition, wt%

C9+ aromatics

C4

High-purity hydrogen

Methanation

Q

C5 Q

C9+

Rx 2

C 6 – C8 A

12.5 64.6

FIG. 2. Pygas hydrogenation flow scheme. Hydrocarbon Processing | OCTOBER 201241

Process Control and Information Systems aromatics recovery, by selectively hydrogenating the olefins and removing sulfur via hydrodesulfurization (HDS). The reactions are conducted through a series of specific catalysts in fixed-bed reactors. The operating conditions are selected to prevent aromatics losses by hydrogenation and to minimize heavy product generated by polymerization.

HYDROGEN NETWORK For APC of the hydrogenation processes, the hydrogen network plays a major role, and it needs to be studied carefully. Both pygas-treating stages consume hydrogen. Several configurations are possible to supply hydrogen to the pygas reactors, as shown in FIG. 3: • High-purity hydrogen option • Low-purity hydrogen option • First-stage purge in the second stage. One concern that cannot be ignored is that other facility processes are also hydrogen users, such as selective hydrogenation of C2, C3 and C4 streams. In a situation of low-hydrogen availability, these processes have priority. As a consequence, pygas can reach a situation in which the first stage is temporarily operated with insufficient hydrogen, which has negative consequences on process performance and catalyst life. When excess hydrogen is available, it is important to reduce wasteful To flare

hydrogen flaring and to improve pygas operation by utilizing all available hydrogen. Efficient pygas operation can ensure that the best use is made of available hydrogen.

POSSIBLE OPERATING IMPROVEMENTS There are four key areas that have the potential to deliver operational improvements. These areas are: improving first-stage product quality, reducing the risk of channeling, maximizing second-bed usage, and optimizing global hydrogen usage. Improving first-stage product quality. The product enter-

ing the second stage must be hydrogenated to the correct level to prevent polymerization of any remaining diolefins or alkenyl aromatics in the second-stage reactor, which is operated at a higher temperature and in the vapor phase. If the hydrogenation process lacks sufficient hydrogen or has a low temperature profile, there will be a high tendency to form gums at the inlet of the second-stage reactor, thus generating unacceptable pressure drop and performance reduction. A good indicator of the hydrogenation of diolefins or alkenyl aromatics is the styrene content of the first-stage reactor product. Normally, the styrene specification is set at 1,500 ppm to efficiently protect the second-stage catalyst. In addition, reasonable catalyst cycles are followed. FIG. 4 presents a statistical distribution of the styrene content at the outlet of the first-stage reactor without APC. The

C2 hydrogenation High-priority H2 consumer

H2

FC Pygas feed

C3 hydrogenation

Liquid load Diluent

C4 hydrogenation FC = Manipulated variable Liquid load = Controlled variable

H2 network

FC Quench

Rx 1 Product to 2nd stage

H2 purge Pygas feed

1st stage

To BTX extraction

2nd stage

FIG. 5. Diluent flow adjustment in first-stage reactor.

FIG. 3. Hydrogen network summary.

Feed flow

Temperature profile in first bed of first-stage reactor

Reducing the channelling On specification

No APC APC on

Off specs

Large giveaway 500 600 700 800 800 1,000 1,100

1,300

1,500

1,700 1,800 1,900 2,000

Styrene distribution, ppmwt

FIG. 4. Typical styrene statistical distribution in a first-stage reactor outlet (ppmwt) from an online analyzer.

42OCTOBER 2012 | HydrocarbonProcessing.com

75

80 85 90 95 First bed temperature of first-stage reactor, °C

FIG. 6. Improving from bumpy to smooth temperature profile with APC.

100

Process Control and Information Systems histogram is characterized by a small number of off-specification values that could have damaged the second-stage catalyst. Also, a large proportion of product was well below the required specification. This over-quality is translated as a cost or giveaway due to the unnecessarily high reactor temperature in the first stage that would reduce the catalyst cycle. Reducing channeling by appropriate diluent flow. In the first-stage reactor, the flow entering the reactor is mainly in liquid phase, and it is constituted of fresh pygas feed, diluent cooled and recycled from the first-stage reactor outlet and hydrogen makeup, as shown in FIG. 5. If the diluent flow is too low, then the hydraulic loading of the catalytic bed may become too small, and thus possibly cause channeling. If the diluent flow is too high, then the velocity in the reactor may be excessive. More importantly, it will lower the average bed temperature, thus a higher inlet temperature will be required to maintain performance. The higher operating temperature will negatively impact the stability of the catalyst. The total flow to the first-stage reactor (fresh feed + diluent), also called “liquid load,” must be adjusted to an optimal target value close to the design value to produce the most continuous temperature profile. This condition is illustrated in FIG. 6. With an inappropriate liquid load, the irregular temperature profile reveals the occurrence of channeling. Maximizing second-bed usage by quench flow. In both pygas reactors (first and second stage), there is usually a quench injection between the first and second beds, to control the reactor temperature profile. The quench flow is often kept too high by panel operators to prevent temperature runaways. In the first-stage reactor, as illustrated in FIG. 7, the consequences of excessive quench flow are a lower bed ΔT, which results in lower hydrogenation levels in the second bed. This leads to increased styrene content in the product. To compensate for this case, the first-bed temperature is frequently increased, which is detrimental to catalyst life cycles. APC objectives for the first-stage reactor include the balance of the hydrogenation between the first and second reactor beds.

Optimizing hydrogen usage by minimizing flaring. This principle is described in FIG. 8. The hydrogen-network purge to the flare is piloted by a hydrogen-network pressure controller. If the valve of this pressure controller is not fully closed, then hydrogen is wasted and sent to flare. In this case, it is possible to increase hydrogen flow to the pygas unit, until the pressure controller valve is fully closed, thus optimizing usage of all available hydrogen In reality, the hydrogen-network pressure-control strategy implemented in the distributed control system (DCS) can be much more complex than presented in FIG. 8. Using in-depth knowledge of DCS capabilities, a new method was developed to minimize hydrogen loss and further increase the hydrogen makeup for the pygas unit without affecting the network pressure. This approach uses pressure controller parameters (setpoint, process value, valve opening, etc.) and dynamic models derived from step-test data. The benefits from this approach are to deliver more hydrogen to the pygas unit and thus improve hydrogenation performance.

APC STRATEGY This novel approach on APC strategy was successfully applied to optimize industrial pygas process operations. It incorporated several key control methods to improve the hydrogenation process: To flare H2 available

PC C2 hydrogenation

Send all flared H2 to pygas

C3 hydrogenation C4 hydrogenation

FC

H2 network

H2 purge Pygas feed

1st stage

To BTX extraction

2nd stage

FC = Manipulated variable H2 available = Infered controlled variable

FIG. 8. Using hydrogen network information to maximize hydrogen supply to pygas.

Styrene in product Diluent

Quench

Diluent

1st stage

2nd stage

1st stage reactor 2nd bed ΔT

Lab data đƫ05.!*! đƫ. đƫ!*/%05 Feed quality estimation

Quench flow steps

FIG. 7. Effect of quench flow changes (during 14 hours) in the second bed of first-stage reactor.

Quench

Lab data

Reactor model

05.!*! diolefins .

Reactor model

BI index aromatics

Periodical manual catalyst activity update

FIG. 9. Inferential model to maximize hydrogen management while minimizing styrene content. Hydrocarbon Processing | OCTOBER 201243

Process Control and Information Systems Maximize feed. Common practice is to place an intermediate product tank between the steam cracker and the pygas unit. The volume of this tank can usually absorb one day’s production of pygas. The inventory of this tank should be minimized to reduce the risk of polymerization of unsaturated components present in the raw pygas, until downstream constraints have been saturated. Use all available hydrogen. Optimize the global hydrogen management. First-stage reactor. The first target is to do ultra-deep hydrogenation of diolefins and alkenyl aromatics, by controlling the styrene content, as measured by an online analyzer, in the first-stage product. The next step is to stabilize reactor operation by controlling the reactor liquid load at an ultimate level to avoid channeling. Hydrogen partial pressure is maximized to promote hydrogenation by increasing the reactor pressure while maximizing the dissolved hydrogen fraction in the liquid phase. The process is operated to ensure a minimal gas purge flow to prevent concentration of inert species in the hydrogen recycle gas. (This is applicable if the unit is equipped with a recycle-gas compressor.) The temperature profile is optimized, using reactor inlet temperature, diluent and quench flow to prevent temperature runaway, to balance reactor ΔT between the two beds, and to maximize catalyst cycle length.

Styrene online analyzer

Fractionation. APC needs to identify the right compromise

between the quality of the separation and energy savings. Second-stage reactor. The first target is to perform com-

plete hydrogenation of olefins and sulfur removal by controlling the bromine index (BI) and sulfur content of the reactor effluent. The next step is to minimize hydrogenation of aromatics by avoiding unnecessarily high-temperature process conditions. Finally, stable reactor operation will be achieved by the control of reactor ΔT and hydrogen-recycle gas density.

PYGAS INFERENCE AND OPTIMIZER The pygas inferential model proposed for APC, as shown in FIG. 9, is based on highly evolved kinetic models that enable online styrene content and BI estimation, and, consequently, reactor optimization. Laboratory analyses of the first-stage effluent are used to estimate the first-stage feed quality (styrene content, bromine number and density). The first-stage reactor model integrates the estimated feed quality and measured reactor operating conditions, continuously inferring the firststage product quality: styrene, diolefins and bromine number. FIG. 10 illustrates the prediction of the styrene compared with online analyzer measurement. The second-stage reactor model integrates estimated feed quality and measured reactor operating conditions, continuously inferring the second-stage product quality. FIG. 11 illustrates the estimation of the BI in the effluent of the secondstage reactor. Using spot-detailed analyses and collection of operating conditions, APC users can generate the best tuning parameters to fit the current operation, thus allowing “realtime” control moves to improve performance.

1st stage optimizer Styrene inferred

Pygas inference

Reactor temperature optimal target Reactor quench flow optimal target

Styrene Bromine index

MVAC multivariable controller FIG. 10. Styrene estimation in first-stage effluent by first-stage reactor model. Temperatures

Pressure

Reboiler

Flows

FIG. 12. APC architecture to optimize pygas hydrogenation.

BI inferred FC

H2 FC

TC

Pygas feed

Quench flow FC Diluent

Inlet temperature

Quench

Rx 1

ΔT B2 Styrene

TC = Manipulated variable Styrene = Controlled variable

FIG. 11. BI estimation in second-stage effluent by second-stage reactor model.

44OCTOBER 2012 | HydrocarbonProcessing.com

Product to 2nd stage

FIG. 13. Simplified APC variables used for simulation example.

Process Control and Information Systems Recommended APC architecture. All APC components are embedded in an APC server connected to the DCS architecture, as depicted in FIG. 12. The control and optimization application consists of these modules: • MVAC module: State space multivariable predictive controller (MVPC) • Pygas inference • First-stage optimizer. The application provides one-minute cycles for MVAC (the MVPC) and 60-minute cycles for the optimizer. Controller execution time was determined by the process dynamics. FIG. 14. Eight-hour closed-loop APC simulation example.

APC PERFORMANCE Here is a simple example of APC potential, illustrated by the application to a real pygas unit optimization project. The control matrix components are presented in FIG. 13. The inputs or manipulated variables (MVs) are: • Feed flow to be maximized when available to reduce tank inventory • H2 flow used as long as available to prevent flaring • Reactor inlet temperature to control styrene content, but minimized when possible to lengthen catalyst cycles • Quench flow to control styrene content. The outputs or controlled variables (CVs) are: • Styrene in product, which should stay below the maximum limit • Reactor second-bed ΔT, which should stay below the maximum limit. When APC in turned ON, the styrene analyzer is at 1,300 ppm, below its 1,500-ppm maximum limit, and the reactor second-bed ΔT is at 65°C, below its 73°C maximum limit. As far as the operation is concerned, quench flow is too high, resulting in excessive cooling of the second bed. When the reactor inlet temperature is too high, a styrene giveaway occurs. More feed is available; the intermediate tank is not empty; and additional hydrogen is available, but is flared. APC actions on the process, as plotted in FIG. 14, can be summarized as making use of all available hydrogen to reduce styrene at the first-stage reactor outlet and thus reducing quench flow as far as the second-bed ΔT allows. These conditions will also reduce styrene content. Simultaneously, the reactor inlet temperature is reduced and feed flow is maximized within the constraints of the maximum styrene content limits. By better operation of the second bed, and using the 10% additional hydrogen available, this APC system was able to increase production by 10%, while decreasing reactor inlet temperature by 4°C. APC with inferential modeling has been successfully applied to pygas hydrogenation units. The overall benefits are: • On-specification product without giveaway • Ability to treat more feed : +10% • Reduction of first-stage reactor inlet temp.: –4°C • Catalyst run length maximization: +4 months/ current • Reduction of aromatics hydrogenation: –10%

• Reduction of H2 waste to flare: –10% • Energy savings: 5% The lengthening of the catalyst run length limits downtime for both the pygas unit and upstream units such as the steam cracker. An additional benefit observed by the operating staff was, with the ease of setting targets and the confidence that the APC system would meet these targets, they were free to concentrate on other plant activities. BIBLIOGRAPHY Bader, J.-M. and S. Guesneux, “Advanced process control optimization increases MTBE plant productivity,” Hydrocarbon Processing, October 2005. Bader, J.-M. and S. Guesneux, “Use real-time optimization for low-sulfur gasoline production,” Hydrocarbon Processing, February 2007. Tona P. and J.-M. Bader. “Efficient System Identification for Model Predictive Control with the ISIAC Software,” (ICINCO), Sétubal, Portugal, 2004. Grosdidier P. and J.-M. Bader, “Supervisory Control of an FCC unit through Sequential Manipulation,” Instrument Society of America, 1996. ACKNOWLEDGMENTS The authors express their gratitude to Joël Chebassier, Orionde, for his contribution to this article and also to the customers for making this article possible. This article is a revised and updated version from an earlier presentation at the American Fuels and Petrochemical Manufacturers (AFPM) Annual Meeting, March 11–13, 2012, San Diego, California. JEAN-MARC BADER is project manager at Axens’ Performance Programs Business Unit. His background is in energy engineering with over 23 years of experience in APC projects (design, development, implementation and maintenance) for refineries, petrochemicals and chemical plants (including ADU, FCC, CCR, alkylation, hydrotreating, ethylene, ammonia, blending), with several APC tools, on various DCS. He joined Axens in 2001, after several years with Elf and Total. His responsibilities include proposal and project management for APC projects. He graduated with honors from I.N.S.A. engineering school. GILDAS ROLLAND is a deputy product line manager— hydroprocessing and olefins for Axens. He started his career in 1998 at IFP Energies nouvelles as a process engineer in the R&D department. In 1999, he joined the process design department of the North American office in Princeton, New Jersey. In 2001, he moved back to Axens’ head-office where he served successively as start-up and tech service advisor, specialist in olefins technologies including R&D activities related to technology and catalyst improvement. Mr. Rolland was appointed to his current position in 2010. He is a graduate of the Ecole Centrale de Lille (E.C.Lille) and holds a master’s degree in refining and petrochemicals from the IFP School. Hydrocarbon Processing | OCTOBER 201245

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Special Report

Process Control and Information Systems M. J. KING, Whitehouse Consulting, Isle of Wight, UK

Why don’t we properly train control engineers? While there are managers in the process industry that see training control engineers as a “no-brainer,” these are very much in the minority. They may send staff on courses covering configuration of the distributed control system (DCS) and implementation of multivariable predictive control (MPC), but some managers seem to miss the point that engineers also need to develop expertise in basic control techniques. It appears to be a case of not knowing what they don’t know—i.e., there is a lack of appreciation of what a fully trained engineer can achieve. Without an injection of expertise, so-called “experienced” staff lack the knowledge to pass on to new recruits. Of the engineering disciplines relevant to the process industry, process control is probably the least well-taught at universities. Often handled by lecturers with backgrounds having little to do with chemical engineering, the courses are laden with complex mathematical techniques that have little relevance to the industry. While all graduates need additional training to advance their careers, this is particularly true for those destined to work in the field of process control. Process control engineers have an immediate impact on the process. Today’s systems permit the engineer to move from idea to commissioning with little involvement of other staff. Most other engineers develop recommendations that are reviewed with others, move on to designs that are also reviewed, and work with others during commissioning. Control engineers are more akin to process operators in the way they work. Operators are well-trained, so why aren’t control engineers? Questions to consider. The following 10 questions are designed to expose common gaps in a reader’s knowledge. If you are a control engineer, be honest in answering them: 1. Have all of the controllers been configured with the best choice of a proportional/integral/derivative (PID) algorithm? For example, am I aware that most systems support the option to have proportional action based on the process variable (PV), rather than on error? Do I believe that this algorithm is inferior because it gives a slow response to setpoint (SP) changes, or do I know that, for many controllers, applying this option with the correct choice of tuning can reduce, by a factor of three, the time that it takes the process to recover from a disturbance? (See FIG. 1.) 2. Am I using trial-and-error as the main tuning method? Am I aware that this increases, by a factor of around 50, the time taken to properly tune a controller? Do I know that, because of the time required, the controller is unlikely to ever be properly tuned? Am I aware that there are over 200 tuning methods published for PID control, and that most—if not all—of them

have some major deficiency? Does my chosen method properly compromise between a fast return to SP and the movement of the manipulated variable (MV)? (See FIG. 2.) Is this method designed to be used with the chosen version of the PID algorithm? 3. Do I know that applying derivative action can greatly improve controller performance if the process deadtime is large compared to the lagtime? (See FIG. 3.) Am I reluctant to use it because it makes tuning more complicated? Do I abandon its use if the measurement is noisy, or do I know how to solve this problem? Do I know how to resolve the spiking problem that derivative action causes with regard to discontinuous signals? 4. Is maximum use made of the surge capacity in the plant? (See FIG. 4.) Are vessel levels maintained close to SP, or are they allowed to approach alarm limits to minimize downstream flow disturbances? Are level gauges ranged to maximize vessel working volume? Do I know that nonlinear algorithms such as “error squared” and “gap control” can be used to more fully exploit surge capacity? SP PV (proportional-on-error) PV (proportional-on-PV)

FIG. 1. Response to a load change.

PV (limiting MV overshoot) PV (ignoring MV) SP MV (acceptable overshoot) MV (unacceptable overshoot)

FIG. 2. Taking account of MV overshoot. Hydrocarbon Processing | OCTOBER 201247

Process Control and Information Systems 8. Do I apply density compensation to fuel gas flow controllers to display flowrates in standard volumetric units (e.g., Nm3/ hr or standard cubic feet per minute)? Do I know that this worsens the disturbance caused by changes in gas heating value? 9. Are my inferential property calculations automatically updated using laboratory data? Am I aware that, in most cases, this can cause the inferential to become less accurate? 10. Have I been persuaded to locate my compressor controls in specialist hardware rather than in the DCS? Do I know that, if I apply the correct tuning method, this may not be necessary? How did you do in the test? If it has exposed even one area where your knowledge is incomplete, then chances are that there is an opportunity to improve process performance that will capture benefits far excost ceeding the cost of effective training.

5. Are filters being used mainly to reduce the visual impact of noise on trended variables? Filters can significantly reduce the controllability of the process and may not be necessary in all cases. Do I know that I should instead check what impact the noise has on the final control element (usually a control valve)? Do I know of other readily available filtering techniques that cause less distortion to the base signal? Am I aware of the importance of eliminating noise at the source, particularly with level measurements, and how this can be achieved?

Winning even one more contract by demonstrating a higher level of expertise more than justifies the of developing that expertise.

6. Am I aware of other algorithms that can outperform even an optimally tuned PID algorithm? Do I know that these can be easily implemented in most DCSs? 7. Do I know that most MPC packages provide bias rather than ratio feedforward? In many cases, performance can be substantially improved by implementing ratio feedforward at the DCS level. Do I know how to properly tune the dynamic compensation in such controllers? Do I know of the benefit that ratio feedforward gives in automatically maintaining optimum PID tuning in all of the unit’s controllers as the feed rate is changed?

SP PV (PID) PV (PI)

FIG. 3. Use of derivative action.

Averaging control Tight control Vessel level

Downstream flow

FIG. 4. Use of surge capacity.

48OCTOBER 2012 | HydrocarbonProcessing.com

Training costs. What does it cost to train a control

engineer, and what are the economic benefits? In addition to the time spent on learning how to configure the DCS and how to apply the chosen MPC, a control engineer will need around three weeks of further training. This training should cover basic control techniques, “conventional” advanced control, process-specific techniques, inferentials, etc. Such courses can cost $1,000 per day. Factoring in travel and living expenses, the total price of training could be $20,000. A manager might view this as costly, but it is insignificant compared to the benefits to be achieved through additional training. For example, a control engineer typically will be responsible for control applications that are capable of capturing in excess of $500,000 per year. Commissioning a project of this value just two weeks sooner would be enough to justify the training. If maintaining existing applications (for example, over a two-year period), then a 2% increase in their utilization would generate the same savings. Also, if the company relies on external specialists during implementation, then reducing the involvement of a top-grade consultant by two weeks would yield similar savings. While such benefits apply to operating companies, similar benefits can be achieved by those companies offering advanced process control (APC) implementation and process engineering services. With only minor differences between competing technologies, the main criterion in selecting an APC implementation company is the expertise of the engineers it offers. Winning even one more contract by demonstrating a higher level of expertise more than justifies the cost of developing that expertise. Similarly, plant owners are increasingly expecting engineering contractors to be more aware of the importance of good basic control design. Too many processes with inherent control problems exist, along with missed opportunities that could have been avoided at negligible cost, if considered at the process design phase. Which course should an engineer choose? More than any other engineering subject, process control training requires practical, “hands-on” exercises. Most engineering disciplines work with steady state. It is relatively easy to demonstrate steady-state behavior in a computer slide presentation. However, it is not so easy to show parameters changing over time.

Process Control and Information Systems Student-friendly, dynamic simulations take far more time to build; it can take 50 hours or more to develop the material covered in one hour on the course. The ratio for the preparation of more conventional teaching material is likely less than 10:1. More effective courses are necessarily more costly. This is particularly true if they are presented by the more experienced— and, therefore, usually more highly paid—engineer. The value of a course should be assessed on what impact the participant can have on process profitability upon returning to work. He or she should return with several ideas that can be put into practice immediately. Presenting the course on a manufacturing site provides the opportunity for practical exercises to be carried out on real controllers. The resulting improvements have a noticeable impact on process performance, and they greatly increase the confidence of the engineer to implement other ideas. Who should present the course? It might be easier to answer this question by identifying potentially poor choices. The DCS vendor is best placed to instruct staff in the use of the system. However, vendors are generally more effective at explaining the “how” than the “why.” For example, they can describe the multiple versions of the PID algorithm available in their systems, but they are generally less adept at explaining when each algorithm should be used. Similarly, the MPC suppliers will be able to describe how to effectively design, implement and monitor their technology, but they will not go into detail about the basic controls that should be in place before step-testing is undertaken. While MPC suppliers are concerned that such controllers operate well, they generally place less demanding criteria on their performance. With a few notable exceptions, most academic institutions treat process control as a highly theoretical subject. Their courses tend to be cheaper because the tutor’s time and the facilities have already been paid for; however, their usefulness is often questionable. Should the course be held in-company? There is the

temptation, particularly if only one or two engineers need training, to send them on an open-access course. It costs the supplier more to run these types of courses than it does to run in-company courses since open-access courses must be marketed to a wide client base, there is a greater administrative load, and the course facilities must be rented. For the customer, an open-access course may be the less costly option, even with the inclusion of travel and living expenses. Also, engineers may have the opportunity to develop valuable contacts in other organizations. However, the following points should be considered: • An in-company course opens up the opportunity for others to attend; the most successful APC projects are those in which the entire staff is involved. • Plant supervisors, process engineers and production planners normally do not attend open-access process control courses; however, they will usually sit in on at least part of an in-company course. An in-company course provides a valuable opportunity for these personnel to develop an awareness of technology and the role they can play in its successful implementation.

• An in-company course can be customized to closely match the company’s needs. • Some material included in an open-access course may not be relevant; it may assume less previous knowledge, and its timing may be inconvenient. When should training take place? Training budgets, like

many expenses that are perceived as optional, are often the first to be cut when the economic climate is poor. However, this is precisely the time when control engineering expertise should be developed. The likelihood is that no major APC projects will be approved, and so releasing engineers for training does not disrupt their schedules. Furthermore, engineers will have time to identify and exploit the many zero-cost improvements revealed by the training. Also, when major investments are again considered, the basic process control layer will already be ready to receive APC— therefore, substantially shortening its commissioning. MYKE KING is the author of Process Control: A Practical Approach, as well as the director of Whitehouse Consulting. Previously, he was a founding member of KBC Process Automation. Prior to that, Mr. King was employed by Exxon. He is responsible for consultant services, assisting clients with improvements to basic controls, and with the development and execution of advanced control projects. Mr. King has 35 years of experience in such projects, having worked with many of the world’s leading oil and petrochemical companies. He holds an MS degree in chemical engineering from Cambridge University, and he is a Fellow of the Institution of Chemical Engineers (IChemE).

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RAISING PERFORMANCE. TOGETHER™

Special Report

Process Control and Information Systems A. J. SZLADOW, REDUCT & Lobbe Technologies Inc., Richmond, British Columbia, Canada

Consider automated fault detection systems to improve facility reliability Automated fault detection and diagnosis systems (AFDDSs) are well established in many consumer and industrial sectors.1 The conventional limit-value based (high/low alarms) fault detection and diagnosis systems have the advantage of simplicity and reliability. Yet, they also have a major weakness. These systems can only react to the deterioration of system conditions, and they do not provide sufficient time and information to detect and diagnose anomalous conditions proactively. TABLE 1 summarizes the relative advantages of AFDDS vs. standard FDDS control. This article addresses how to implement an AFDDS in a refinery, and discusses the advantages and key issues with AFDDS.

AFDDS APPLICATIONS There are numerous publications on fault detection and diagnosis in electrical systems, including application of statistical and soft computing methods. However, very little of the knowledge and experience gained from AFDDS application from other industrial sectors has been applied to the refining industry. A literature review regarding methods applied in AFDDS in heavy industry lists 367 references.1 None of the 367 listed references refers to applications found in petroleum refining. In 1995 and 1997, similar literature reviews identified over 250 applications of intelligent systems including, AFDDS in heavy-industry operations.2 Again, the majority of the applications addressed process control and optimization, scheduling, and design for productivity and product quality. Less than 10% of the applications described fault detection and diagnosis systems, and most cases were not automated; they primarily provided decision support to process operators and engineers. The number of AFDDSs applied appears to be related to the automation level of the site plant and the risks associated with unsafe operating conditions. The aerospace sector has a very high level of AFDDS applications due to the risk associated with this sector and corresponding levels of regulation. Given the listed considerations and that very few AFDDSs have been implemented in oil refineries, we will discuss AFDDS application in petroleum refining and also review systems implemented by industry to manage process and equipment failures.

of $7.5 million with the application of predictive diagnosis in critical refinery process units.3 An EPRI report examined present adoption of control technologies in California refineries and the move to use of distributed control systems (DCSs), multivariable, neural networks and future self-learning tools as shown in TABLE 3.4 Such progression of technological changes has a large potential benefit. But, this progression will require investment. Following the methodology outlined in the EPRI report, Table 4 shows the avoided maintenance cost for refineries “before and after” implementation of advanced control technologies. We assign any reduction in maintenance costs to AFDDS. TABLE 4 depicts three levels of technology implementation: 1. Present level with advanced technologies 2. Application of marketable (present available cost-effective) technologies 3. Application of “technical potential” (future cost-effective) advanced technologies. A large difference (double) between marketable and technical potential technologies indicates possible gains in technology capacity through research. Cost reduction. The maintenance cost was estimated at 7% of

the total operating cost (Salomon 2006), which yields a benefit of over $1.3 million/yr from increased penetration of available technologies and a further $1.7 million/yr from implementing future (hybrid and self-learning) technologies (see TABLE 4). The annual total reduced maintenance cost is estimated at over $3 million for an average refinery. TABLE 1. Standard controls vs. AFDDS Issue

AFDDS

Alarm detection

Reactive

Proactive/Prognosis

Alarm management

Non-deductive

Deductive notification

Personnel guidance

Little

Significant

Inputs

Largely from sensors

Sensors and expert knowledge

Corrective action

Operator initiated Automatic

Automatic

Used by

Operating personnel

Operating, maintenance, engineering and safety personnel

Examples. There are very few published references to the ben-

efits of AFDDS within the petroleum sector, as summarized in TABLE 2. A report by Berra indicates that one client gained savings from the reduction of unplanned shutdowns on the order

Standard control

Hydrocarbon Processing | OCTOBER 201251

Process Control and Information Systems TABLE 4. Avoided maintenance costs of Canadian refineries depending on the level of automation

TABLE 2. Summary of methods used and process units studied Reference Wang11

ES

MPC

NN

PCA

FL

SI

v

Vedan12

v

Huang13

FCC

v

14

v

Yang

Yamamoto15

Process Distillation column

v

Pranatasta

Coker v

FCC

v

FCC v

Pranatyasto16

v

CC v

17

FCC v

Gofuku Du18

Refinery

v 19

Wilson

FCC

v

ES—Expert systems MPC—Model predictive control NN—Neural networks

Utility PCA—Partial component analysis FL—Fuzzy logic SI—Semantic interface

TABLE 3. Present state of adoption of control technology in California refineries Sub-section of the refinery, %

Whole refinery, %

Move to DCS

90

90

Move to multivariable

40

0

Move to neural network

5

0

Future self-learning control

0

0

Present control technology

Current level with the use of advanced control technologies

Avoided cost, $ million 0

Application of “marketable” (cost-effective today) advanced control (AFDDS) technologies

> 1.3

Application of “technical potential” (cost-effective in the future) advanced control (AFDDS) technologies

> 1.7

FCC

v

Patan

Level of automation

Source: EPRI, 20044

The lost production due to unscheduled shutdowns is typically reported to be between 10% to 20% of operating costs.5 Assuming a potential 50% reduction in unscheduled shutdowns, etc., from installing an AFDDS, the estimated annual benefits would exceed $3 million for an average refinery. However, to achieve this level of benefits, an AFDDS would have to be applied on half of the following unit operations and processes: 1. Unit operations: Distillation, absorption columns, furnaces, heat exchangers and compressors. 2. Unit processes: Fluid catalytic cracking (FCC), catalytic reformer, hydrocracking, delayed coking, hydrotreating and alkylation. About six AFDDS models would be required to gain the benefits listed.

AFDDS PERFORMANCE Heavy industry has used advanced process control (APC) systems for optimization projects and has given much less attention to AFDDSs. However, depending on the level of automation, benefits from managing abnormal process and equipment conditions can increase reliability; the benefits often exceed the gains found through process optimization. For example, for a large continuous operation, such as a refinery, process optimization can typically yield a 3% improvement in productivity.6 In contrast, a well-implemented AFDDS may yield up to a 5% improvement in profitability. This is because management for reliability improvement goes beyond fault avoidance by providing the ability to: 52OCTOBER 2012 | HydrocarbonProcessing.com

1. Handle large disturbances and control variables at their optimal values 2. Ensure and upgrade dynamic process models, including factors omitted in initial implementation 3. Explain the behavior of controllers and, when needed, correct controllers to meet planned targets 4. Provide advice on alarm management, including early detection of problems before more serious problems develop. As summarized in TABLE 5, it is possible to classify fault detection and diagnosis methods into quantitative using models based on first principles, qualitative using models describing lumped system responses, or process history methods matching fault patterns derived from historical data.7–9 The methods are similar and, yet, different from each other. They can identify the relative strengths and weaknesses from methods when building diagnostic methods for fault detection and diagnosis (anomaly detection, disturbance detection and controller diagnostics) and supervisory control (controller tuning, control reconfiguration and online optimization). AFDDS not only address typical maintenance functions such as better root-cause analysis or optimized inspection frequencies, but, in 7 out of 10 cases, they also address processing issues. Safety and reliability. Improving operational safety and meeting regulatory requirements are critical to industry operations and businesses. For example, AFDDSs have been applied for safety and regulator reasons in the automotive and aerospace sectors. This article does not discuss using AFDDSs to enhance safety and meet regulatory requirements in refineries. It is assumed that, where needed, the refining industry would implement such systems as required. Higher reliability due to AFDDS results in a more energy efficient and profitable facility. However, AFDDS-driven energy savings are often indirect through less production waste, reduced plant outages, less plant startups and/or shutdowns, and more optimal equipment/process performance through better control systems management, etc. All lead to reduced net energy consumption per product unit made, or higher overall plant energy efficiency.

RELIABILITY FOCUS A simple focus on benefits/cost analysis does not reflect the true opportunities created by AFDDS technology. For such an analysis, it may not include technologies that can be adopted easily and will later lead to significant learning and a significant cost reduction. Therefore, broader adoption criteria, such as those listed in TABLE 6 can provide better guidance as to the best AFDDS projects and development directions to support.

Process Control and Information Systems TABLE 5. Summary of fault detection and diagnosis methods Quantitative methods

Qualitative methods

History methods

Given required measurements can distinguish known from unknown faults

Can provide explanation for fault propagation

Fault rules can be used where fundamental principles are lacking

Can detect faults for systems with process and measurement noise

Can generate and recognize full set of faults

Have been demonstrated to perform well in terms of robustness to noise and resolutions of parameters

Effectiveness is determined by sensor data and system knowledge

May have poor resolution due to ambiguity of qualitative reasoning

Easy (time and cost) to implement

Approximation of disturbances can create modeling errors

Resolution problems can be addressed with quantitative information

Poor fault generalization from historical data only

Complex systems modeling may generate spurious solutions because of computational complexity

May have difficulty with multiple faults depending on algorithm used Limited by a finite set of data

TABLE 6. Summary of potential AFDDS benefits and costs, millions of dollars

TABLE 7. Examples of industry-wide AFDDS adoption criteria Overall

Cost element

Detail

Must represent a forward step

Potential for learning by doing and/or research

Average benefit

Average cost1

Reduction in maintenance cost

1.4

1.1–2.1

Cross-cutting potential

Reduction in cost of outages

3.1 1.1–2.1

Customization requirements

Plants

Total reduction and cost Benefit/cost ratio 1 2 3

Comments

Petroleum

2

4.5

2.1–4 (1.5–2.8)3

Have clear adoption AFDDS barriers issue Host plant expertise

Based on six AFDDSs models per plant Inline with $4 to $6 million reported by Stout21 and Kant20 Based on reduction in cost of outages only

However, in each technology stage, there are niches or specialized markets that often experience adopting new technology much sooner. Some general criteria for applications of AFDDSs in oil refineries sector should be sought, explored and emphasized to commercialize AFDDSs at a faster rate in areas such as FCC. Implementing an AFDDS requires a high investment in knowledge of refining operations, plant controls and automation, information technologies and software, advanced technologies for data analytics and visualization, plant-wide information systems, etc. The market size of the petroleum refining industry, therefore, is critical for the private sector to justify investment of the large amount of resources and manpower required. A more detailed discussion of the barriers to the introduction of advanced control technologies in the refinery sector and other heavy industry sectors can be found in the literature.10 The progress in AFDDS is not likely to come from a large breakthrough in science and technology, but from incremental improvement in the cost of AFDDS and the gradual acceptance by industry. TABLE 6 shows the estimated potential benefits and costs for an AFDDS, and a few observations are evident: 1. Because of the large difference between an average AFDDS cost (about $200,000) and the cost of improving plant digital infrastructure ($500,000 to $1.5 million), it is the plant’s existing infrastructure (or required improvement in infrastructure) that drives the benefit/cost ratio for implementating an AFDDS at any plant/refinery. 2. Assume that in all AFDDS cases, some infrastructure will have to be updated. In spite of that, in all cases, benefit/cost ra-

Lack of support/ sponsorship

Doesn’t have to be new AFDDS technology

Clear and doable Technology is easy— People are hard

Securing technical expertise Business ownership Innovative financing options Supports areas of major interest

Relevance or impact on oil refineries sector Proponent expertise A niche application

Identification of applications relevant to the sector’s strategic investments will accelerate AFDDS adoption and increase capacity

tios of > 0.4 (with approximately 1 most likely) and paybacks of less than two years (about one year most likely) were projected. In the final analysis of AFDDS adoption, one has to ask: What if the oil refining industry or a large industrial segment does not adopt AFDDS technologies? It is difficult to predict the future of a specific industry, but strong conclusions can be made based on what is known about the role of technology in industry growth: 1. Technical progress is the most important factor in economic growth, and, typically, it accounts for more than half of growth in developed countries. 2. Industries that use advanced technology are more productive and profitable and have higher wages. 3. Industries that use advanced technologies have higher job growth. 4. New technologies revitalize old industries, e.g., steel, automobile, textile, etc. Hydrocarbon Processing | OCTOBER 201253

Process Control and Information Systems Also, industry-wide AFDDS adoption criteria can be formulated, as shown in Table 4. Failure to implement AFDDS or slow progress to adopt is likely to result in a loss of opportunities as measured by productivity within the petroleum refining industry. LITERATURE CITED Chiang, L. H., E. L. Russel, and R. D. Braatz, Fault detection and diagnosis in industrial systems, Springer, 2001. 2 REDUCT and Lobbe, Technologies, “Application of Intelligent Systems to increase productivity, quality and energy efficiency in heavy industry,” and “Advances in the application of Intelligent Systems in heavy industry,” CANMET Technology 1995 and 1997. 3 Berra, J., “The digital refinery: A look at the future of automation,” NPRA Computer Conference, 2002. 4 EPRI Report 1007415, Using advanced control and power technologies to improve the reliability and energy efficiency of petroleum refining and petrochemical manufacturing in California, 2004. 5 White, D., “The 21st century refinery: Impact of modeling and predictive analytics,” NPRA Technical Forum on Plant Automation, 2007. 6 Gosh, A. and D. Wall, “Abnormal conditions management–The missing link between sustained performance and costly disruptions,” ARC Advisory Group, March 2001. 7 Venkatasubramanian, V., R. Rengaswamy, S. N. Kavuri and K. Yin, “A review of process fault detection and diagnosis, Part III: Process history based method,” Computers & Chemical Engineering, 2003. 8 Venkatasubramanian, V., R. Rengaswamy and S. N. Kavuri, “A review of process fault detection and diagnosis, Part I: Quantitative model-based methods,” Computers & Chemical Engineering, 2003. 9 Venkatasubramanian, V., R. Rengaswamy and S. N. Kavuri, “A review of process fault detection and diagnosis, Part II: Quantitative models and search strategies,” Computers & Chemical Engineering, 2003. 10 Szladow, A., “Developing intelligent systems for heavy industry: The adoption of 1

intelligent technologies,” PCAI, Vol. 17.6, 2005. Wang, X. Z., et al., “Learning dynamic fault models based on a fuzzy set covering method,” Computers & Chemical Engineering, Vol. 21, No. 6, 1997. 12 Vedam, H. and V. Venkatasubramanian, “PCA-SDG based process monitoring and fault diagnosis,” Control Engineering Practice, Vol. 7, No. 7, 1999. 13 Huang, B., et al., “Fault diagnosis of an industrial CGO coker model predictive control system,” IEEE Canadian Conference, 1999. 14 Yang, S. H., B. H. Chen and X. Z. Wang, Engineering applications of Artificial Intelligence, Vol. 13, No. 3, 2000. 15 Yamamoto, J., et al., “Application of a cooperative control system to residue fluid catalytic cracking plant using a knowledge based system and model predictive multivariable control,” IECON 2000. 16 Pranatyastos, T. and S. J. Qin, “Sensor validation and process fault diagnosis for FCC units under MPC feedback,” Control Engineering Practice, Vol. 9, No. 8, 2001. 17 Gofuku, A., and Y. Tanaka, “Display of diagnostic information from multiple viewpoints in anomalous situation of complex plants, systems, man and cybernetics,” IEEE International Conference, 1999. 18 Du, D., et al., “Expert System for diagnosis and performance of centrifugal pumps,” 1996. 19 Wilson, D., A. Jumenez and J. Souza, “An on-line advisory system for optimizing refinery utilities systems,” NPRA Technical Forum on Plant Automation, 2006. 20 Kant, R., and K. Pihlaja, “Abnormal situation prevention (ASP) in complex system,” NPRA Plant Automation Conference, 2006. 21 Stout, J., “Reliability and operations management applications in olefins plants,” AIChE Spring National Meeting, Houston, April 2001. 11

ADAM J. SZLADOW is president of REDUCT & Lobbe Technologies. He has over 30 years of experience in the development and application of advanced technologies in energy and heavy industry. He held management and research positions in utility industry, energy development companies and government research laboratories. Dr. Szladow was chairman of the Business Committee of the National Advisory Council to CANMET, Natural Resources Canada; and a member of the Minister’s National Advisory Committee, Natural Resources Canada. He holds a PhD in materials sciences and chemical engineering from Pennsylvania State University, and has authored over 70 scientific publications including patents.

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Process Control and Information Systems

Special Report

V. YADAV, P. DUBE, H. SHAH and S. DEBNATH, Indian Oil Corp., Ltd., Mathura, Uttar Pradesh, India

Optimize desulfurization of gasoline via advanced process control techniques At Indian Oil Corp.’s (IOC’s) Mathura refinery, a selective desulfurization unit was commissioned to reduce the sulfur content of fluidized catalytic cracked (FCC) gasoline—a blending component for finished motor spirit (MS). The objective of this new unit was lowering the sulfur content of FCC gasoline from 500 ppmw to 100 ppmw, thus meeting Euro IV product specifications for the refinery-gasoline blending pool. However, along with desulfurization, some undesirable olefin saturation reactions occurred, resulting in octane losses for the product gasoline. As per design, the octane loss in the desulfurization reactors is 1.3 units. With Euro IV specifications in place, the octane loss negatively impacted the refinery’s economics. This refiner applied an advanced process control (APC) solution to minimize octane loss. The objective of the desulfurization unit’s APC program is to maximize sulfur content in the gasoline while still complying with Euro IV specifications and other process operating constraints. The control philosophy depended on sulfur estimations of the stabilizer-bottom product. An inferential property was developed for online estimation of the sulfur content, and it was used as a controlled variable in the multivariable predictive controller (MVPC). This case history describes the development of the inferential models used in open-loop and closed-loop applications, laboratory and analyzer update mechanisms, and APC model generation. With APC, it was possible to increase the sulfur content in product gasoline by 10 ppm–12 ppm, along with an average octane gain of 0.11 units; all improved the Flow of SHU refinery’s bottom line.

reactor effluent is separated into light-cut naphtha (LCN), heart-cut naphtha and heavy-cut naphtha (HCN) in the FCCGS unit. In the third step, the heavy fraction from the splitter bottom, containing high-sulfur content material, is processed in the HDS unit. This processing step converts heavy sulfur compounds into hydrogen sulfide (H2S). In addition, significant saturation of olefins occurs along with the HDS reactions. Saturating olefins reduces the final research octane number (RON) and is an undesirable condition.

ADVANCED APC OBJECTIVES AND DESIGN In the Mathura refinery application, the control objectives are achieved by utilizing MVPC in conjunction with supporting predictions provided by an inferential property prediction package (IPPP). Supporting calculations are required to supplement existing process measurements. MVPC applications incorporate process models that permit forward-feed disturbance rejection and intermediate variables feedback, as well as constraint control. In configuring the controller, there is one main controller. The objectives for the main controller are: • Maximizing stabilizer-bottom product sulfur level within permissible limits, so that the upper limit of the total rundown sulfur for the desulfurization unit is maintained per Euro IV gasoline blending. Minimizing RON loss is also achieved. • Minimizing steam consumption by the stabilizer section • Maintaining safe unit operations.

gasoline recycle

FCC GASOLINE DESULFURIZATION PROCESS IOC’s Mathura refinery implemented a new gasoline desulfurization process. It is a two-step selective hydrotreating method. This processing unit consists of three major operations: • Selective hydrogenation unit (SHU) • FCC-gasoline splitter (FCCGS) unit • Hydrodesulfurization (HDS) unit. In the first step, FCC gasoline is treated in the SHU, which selectively converts di-olefins into olefins and light mercaptans into heavier sulfur-containing compounds. In the second step, the SHU

306FIC0101 FCCU debutanizer flow

306-E-02 306TIC0270

306-E-01B

306FI0105

307-R-01

306LIC103

306-V-01

306FIC0104

306-E-01A

Steam

306TI0263 306-V-04

306FIC0203 To FCCGSU gas feed

Manipulated variables Controlled variables Disturbance variables

306-P-01A/B 306FIC0202

306-V-05

Controller: MainCON Sub-Controller: SHUCON

To FCCGSU liquid feed

FIG. 1. Block diagram of the sub-controller for the selective hydrogenation unit. Hydrocarbon Processing | OCTOBER 201255

Process Control and Information Systems To achieve these objectives, a main controller (MAINCON) and two sub-controllers are used: • Selective hydrogenation unit—SHUCON • Hydrodesulfurization unit—HDSCON. Note: The stabilizer section of the HDS unit is considered part of HDSCON.

ering the debutanizer flow (hot feed) as a DV. The SHU feed/ effluent exchanger bypass flow, along with steam to the SHU preheater, is used to control the SHU reactor-inlet temperature. FIG. 1 shows the same sub-controller (SHUCON) for the SHU. HDS unit sub-controller. Before the APC implementation,

the HDS unit was operated by controlling the severity conditions of the reactors. The unit operator conThe objective of the desulfurization unit’s trolled HDS reaction (first-bed inlet temperature and second-bed inlet temperature) based on daily sulfur APC program is to maximize sulfur content levels in the stabilizer bottom product and rundown in the gasoline while still complying with Euro IV. product. Sulfur levels were determined by analyzers and lab testing. The fuel gas was cascaded with firstbed inlet temperature, and the quench flow was cascaded with second-bed inlet temperature. To maintain stable Sub-controller objectives. Before the APC installation, reflux flow to the stabilizer, unit operators adjusted the stabithe SHU was operated to maintain stable flow to the reactor. lizer reboiler temperature and reflux pressure by continuous Flow from the FCCU debutanizer (hot feed—70% of total) monitoring of the light-end flow to the column. was routed to a feed-surge drum. A recycle stream (HDS stabilizer bottom stream) from a nitrogen-blanketed storage (cold feed—30% of total) was also sent to the feed-surge drum. Unit Post-APC operations. The HDS reactor is set by the APC operators manually controlled the level of the SHU feed-surge based on sulfur levels of the stabilizer bottoms. The IPPP estidrum by adjusting the recycle stream. mation is done on a 15-second basis. Also, the APC will maxiTo maintain the SHU reactor inlet temperature, feed from mize the sulfur level within given operator limits, thereby by the surge drum is heated by the SHU feed-effluent exchanger adjusting the reactor severity. The stabilizer-bottom reboiler on the tube side by exchanging heat from the SHU effluent. The temperature is controlled by APC and facilities minimizing the resulting mixture is heated in the SHU preheater using steam. steam consumption by the reboiler. However, the reflux flow to After the APC installation, the control objective was to the stabilizer is also controlled by APC, along with stabilizerkeep steady flow to the SHU feed and maintain the surge-drum bottom re-boiler temperature. The process equipment manlevel by adjusting the FCCU debutanizer flow as a disturbance aged via APC includes: variable (DV) and adjusting the recycle stream. The control • HDS reactor (307-R-01) objective is to maintain a stable SHU RIT, by manipulating the • HDS heater (307-F-01) effluent exchanger bypass flow and steam flow to the SHU pre• HDS feed-effluent exchanger (307-E-01 A/B/C/D) heater under allowable limits. The process equipment to be • Stabilizer section (307-C-02). managed via the APC included: TABLE 2 summarizes the sub-controller design for the HDS • SHU feed-surge drum (306-V-01) unit. FIG. 2 shows the same sub-controller (HDSCON) for the • SHU feed-effluent exchanger (306-E-01A/B) HDS unit. • SHU preheater (306-E-02). TABLE 1 summarizes the sub-controller design for the selecModels. As shown in FIG. 3, the simple first-order process models tive hydrogenation unit. The SHUCON sub-controller was dewere not providing tight control on the HDS reactor-inlet temsigned to manage steady flow to the SHU reactor while considperatures. In response, a ramp transfer function block was added into the model, along with the first-order transfer function block. The exothermic Steam 307TI0607.PV 307-E-06 reaction in the reactor behaves in a “ramp” 307TI0642.PV manner (unbounded runaway even in the 307-V-04 case of a bounded input disturbance). 307FIC0605.SP 306FIC0502.PV Due to “ramp” behavior of the process, fast 307-E-01 action is required in manipulated variables 307FIC1003.PV 307-R-01 (MVs), such as fuel-gas flow and quench 307-E-01 307TIC0635.PV flow, to quickly control the exotherm (by 307-C-02 307-F-01 controlling the first-bed and second-bed 307-E-01 inlet temperatures) before they rise too 307-E-04 Manipulated variables 307-E-05 307TI0630.PV Controlled variables high. The inherent instability of the reacDisturbance variables tor was countered via a ramp block, plus 307TI1014.PV Controller: MainCON Sub-Controller: HDSCON the normal first-order block, to relate the STABBTM_SULFUR PV(RQE) MVs and DVs with the inlet temperatures. 307FIC0684.SP 307-V-06 307PIC1003.SP For a step change in DVs, this combina20TI0804.PV 307FI0606.PV To rundown 307AI1001.PV tion predicts an unbounded response in the inlet temperatures—thus, moving the FIG. 2. Block diagram of the sub-controller for the hydrodesulfurization unit. MVs quickly to reject the disturbance. 56OCTOBER 2012 | HydrocarbonProcessing.com

Process Control and Information Systems SUPPORTING CALCULATIONS IPPP DEVELOPMENT To calculate the sulfur content of the FCC feed inlet, several predicted values were considered. By using the flowrate and sulfur quantity of all streams listed in TABLE 3, the total sulfur value can be calculated at the FCCU feed inlet. The calculation used to estimate the sulfur content is: =(79FC803.PV  S1  density) + (79FC802.PV  S2  density) + (79FC801.PV  S3  density) + (7FC6701.PV  S4  density) + (12FIC100.PV  S6 (if crude_select.op=1)  density) or (MRA.12FIC100.PV  S7 (if crude_select.op = 2)  density) or (MRA.12FIC100.PV  S8 (if crude_select.op = 3)  density) + ((2FC0708.PV  S5)/1000) / (79FC803.PV + 79FC802.PV + 79FC801.PV + 7FC6701.PV + 12FIC100.PV + 2FC0708.PV) where S1–S8 are sulfur values that are entered by the operator.

FCCDSU feed sulfur. This model used several inputs:

Tag name FCCUFD_SULFUR.PV 19TRC153.PV

Tag description Sulfur at FCCU (calculation) FCCU main fractionator top temperature 20TI99.PV FCCU debutanizer bottom temperature. To estimate the sulfur content of DSU feed, the following linear equation is used: P = Ax1 + Bx2 + Cx3 + Bias where: P = DSU_SULFUR.PV (FCCDSU feed sulfur in hot feed) A = Coefficient 0.041417 x1 = FCCUFD_SULFUR.PV B = Coefficient 1.6497 x2 = 19TRC153.PV C = Coefficient 5.736500 x3 = 20TI99.PV Bias = –1067.4

Sulfur content of FCC gasoline splitter. Feed to FCCGSU

is compensated by two streams—hot feed from the debutanizer (306FI0105.PV) and cold feed from recycle (306FIC0101. PV). Calculations to estimate sulfur at FCCGSU feed are: = ((DSU_SULFUR.PV  306FI0105) + (STABBTM_ SULFUR  306FIC0101.PV-5.5*)) / {(306FI0105) + (306FIC0101-5.5*)} where DSU_SULFUR.PV and STABBTM_SULFUR are the IPPP sulfur estimations. * 5.5 is the flow correction since the control valve has a zero error. IPPP applications. Several IPPP models were developed for

the FCC gasoline desulfurization unit and include: • FCCDSU hot feed sulfur estimation • HDS feed sulfur estimation • Stabilizer bottom sulfur estimation.

FIG. 3. First-order process model response to reactor inlet temperature control.

TABLE 1. APC variables for the sub-controller for the selective hydrogenation unit—SHUCON Description

Interface point

Manipulated variables: Flow of SHU gasoline recycle

306FIC0101.SP

SHU feed/effluent excahnger bypass

306FIC0202.SP

Steam flow to SHU pre heater

306FIC0203.SP

Disturbance variables: FCCU debutanizer flow

306FI0105.PV

Flow to SHU from surge drum

306FIC0104.PV

Controlled variables: Feed surge drum (306-V-01) level

306LIC0103.PV

SHU reactor (306-R-01 B) inlet temperature

306TIC0270.PV

SHU pre-heater inlet temperature

306TI0263.PV

FIG. 4. Quality and process improvement achieved through APC IPPP. Hydrocarbon Processing | OCTOBER 201257

Process Control and Information Systems TABLE 2. APC variables for the sub-controller for the HDS unit— HDSCON Description

Interface point

Manipulated variables: Fuel gas flow

307FIC0684.SP

HDS reactor 2nd bed quench

307FIC0605.SP

Stabilizer bottom steam pressure

307PIC1003.SP

Disturbance variables: HDS feed from GSU

307FI0606.PV

Stabilizer light end feed from GSU

306FIC0502.PV

HDS reactor 2nd bed bottom temperatue

307TI0630.PV

HDS feed temperature at GSU

20TI0804.PV

HDS feed sulfur

HDSFD_SULFUR.PV

Controlled variables: HDS reactor 1st bed inlet (307R01) temp

307TI0642.PV

HDS reactor 2nd bed inlet (307R01) temp

307TIC0635.PV

Feed effluent exchanger inlet temp

307TI0607.PV

Stabilizer (307-C-02) bottom temp

307TI1014.PV

Reflux flow to the stabilizer

307FIC1003.PV

Online stabilizer bottom sulfur

307AI1001.PV

Stabilizer bottom sulfur (inferred)

STABBTM_SULFUR.PV

HDS feed sulfur. This model used several inputs:

Process inputs used Tag name Tag description GSUFD_SULFUR.PV Feed to FCCGSU (calculation) 20PI0802.PV FCCGSU top pressure 20FC0306.PV FCCGSU light cut draw flow 20FC0404.PV FCCGSU heart cut draw flow The following linear equation is used: P = Ax1 + Bx2 + Cx3 + Dx4 + Bias where: P = HDSFD_SULFUR.PV A = Coefficient 1.097890 x1 = GSUFD_SULFUR.PV B = Coefficient –272.28299 x2 = 20PI0802.PV C = Coefficient 7.0273 x3 = 20FC0306.PV D = Coefficient 3.291770 x4 = 20FC0404.PV Bias = 598.81 Stabilizer-bottom sulfur. This model used several inputs:

Process inputs used Tag name Tag description HDSFD_SULFUR.PV HCN sulfur (HDS feed sulfur IPPP estimation) TABLE 3. Process monitoring points used to estimate sulfur level for the FCC feed inlet Description

Tag name

OHCU bottom from tank

79FC803.PV

LS VGO from tank

79FC802.PV

BH VGO from tank

79FC801.PV

OHCU bottom hot feed

7FC6701.PV

HOT feed from AVU

12FIC100.PV

DHDS VGO flow

2FC0708.PV

AVU crude select tag*

crude_select.op

*The sulfur quantity for each of the flow was operator entry. AVU crude select tag is a digital tag pulled from the AVU having three values.

Tag value

Crude type

1

Bombay High

4,000

2

High Sulfur

30,000

3

Nigerian

6,000

Description

0.875

LS VGO from tank

0.9

BH VGO from tank

0.9

OHCU bottom hot feed

0.875

HOT feed from AVU

0.9

AVU crude select tag Select 165 at www.HydrocarbonProcessing.com/RS

Densities

OHCU bottom from tank

DHDS VGO flow

58

Sulfur quantity, ppm

Process Control and Information Systems 307TI0642.PV

HDS reactor 1st bed inlet temperature 307TI0630.PV HDS reactor 2nd bed bottom temperature 307TI1014.PV Stabilizer bottom temperature. To estimate the sulfur content of HDS feed, the following linear equation is used: P = Ax1 + Bx2 + Cx3 + Dx4 + Bias where: P = STABBTM_SULFUR.PV A = Coefficient 0.115679 x1 = HDSFD_SULFUR.PV B = Coefficient –3.90 x2 = 307TI0642.PV C = Coefficient –3.59673 x3 = 307TI0630.PV D = Coefficient –0.341067 x4 = 307TI1014.PV Bias = 1067.5 TABLE 4. Economic benefit and octane conservation possible through APC Economic function name

Maximization of sulfur

Speed factor

From FIG. 4, the quality estimation using the IPPP has good agreement with the actual sulfur content as measured from unit and lab analyzers. TABLE 4 summarizes the economic functions and RON improvement possible with APC.

PROJECT MILESTONES Implementing APC on the HDS unit has yielded substantial tangible and intangible benefits. While the annual monetary gain is of the order of Rs. 39 lakhs, significant improvement via process control and optimization was achieved as measured through tighter control of the SHU and HDS reactor inlet temperatures. More accurate estimation of the stabilizer-bottom sulfur inferential was possible, which facilitated proper control action via the APC. With tighter control and action via APC, adjusting and preferentially lowering the reactor-inlet temperatures were possible. The effect of crude changes in the atmospheric and vacuum distillation unit is also incorporated into the model. The resultant sulfur changes in the FCC feed are transmitted via means of intermediate calculations and inferential estimations to the final stabilizer-bottom sulfur prediction. Operators now have more confidence when implementing control and optimization strategies. This has resulted in better operations of the refinery. Accordingly, APC was successfully implemented and is yielding expected benefits.

0.10

Economic coefficients

LITERATURE CITED Perry, R. H., Chemical Engineers Handbook, Sixth Ed., New York, McGraw Hill, 1984. 2 Levenspiel, O., Chemical Reaction Engineering, Third Ed., Singapore, John Wiley and Sons, 1999. 3 Stephanopoulos, G., Chemical Process Control, Dorling Kindersley (India) Pvt. Ltd., 2007. 1

MAX_AI

10

STEAMMIN

10

MAX_SULFUR

10

MINFG

100

MINRIT1

0

MINRIT2

0

RON improvement RON improvement after MVPC implementation from the rundown stream (MS) of HDS unit

0.114

1 unit of RON improvement corresponds to (1 metric ton of MS processed)

Rs. 91.30

Annual processing of feed (MS) in the HDS unit (not considering the heart cut drawn from FCCU-GS)

376,487 metric ton

Estimated annual benefit due to MVPC application in HDS unit

Rs. 39,32,517.86 ≈ Rs.39. 32 Lakhs (Rupees thirty nine lakhs thirty two thousand five hundred and seventeen only)

Sulfur in the stabilizer bottom MS stream improved

15 ppmw

Sulfur in the rundown MS improved

11 ppmw

Targeted benefits due to RON improvement Targeted annual benefit due to MVPC application in HDS unit Targeted sulfur improvement in the rundown MS

Rs. 24.46 Lakhs 10 ppmw

SHYAMAL DEBNATH is the chief technical services manager at Indian Oil Corp. (IOC) Ltd.’s Mathura refinery. His primarily responsibilities include providing technical services for strategic initiatives and advanced process control (APC). Mr. Debnath has more than 25 years of experience in unit operations, strategic initiatives (process and projects), research, troubleshooting and APC for all the major process units at various IOC refineries. He holds an MS degree in chemical engineering from Indian Institute of Technology, Kharagpur, India. HITESH SHAH is a senior technical services manager with Indian Oil Corp. (IOC) Ltd.’s Mathura Refinery. His primary responsibilities include providing technical services for strategic initiatives and APC. Mr. Shah has more than 14 years of experience in strategic initiatives, planning and coordination, and APC. At present, he is working as a senior technical services manager at IOC’s Gujarat refinery. Mr. Shah holds an MS degree in chemical engineering from Indian Institute of Technology, Bombay, India. PRASHAT DUBE is a senior process engineer at Indian Oil Corp. (IOC) Ltd.’s Mathura Refinery. He is primarily responsible for providing technical services for APC implementation and maintenance. Mr. Dube has five years of experience in APC for all major process units at the Mathura Refinery and holds a BS degree in chemical engineering from Indian Institute of Technology, New Delhi, India. MS. VARSHA YADAV is a senior process engineer at Indian Oil Corp. (IOC) Ltd.’s Mathura refinery. She is primarily responsible for providing technical services for APC implementation and maintenance. Ms. Yadav has three years of experience in APC for all major process units at the Mathura Refinery and holds a BS degree in chemical engineering from Regional Institute of Technology, Raipur, India. Hydrocarbon Processing | OCTOBER 201259

UV/Vis and NIR SPECTROP HOTOMET ERS WANTED F OR PROCESS ENGINEER ING.

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Put AMETEK’s new IPS-4 on the job. High performance, low maintenance and now available in Infrared! Put next-generation technology to work to verify the quality of your feedstocks, intermediates, final products and more. The new IPS-4 spectrophotometer detects and quantifies thousands of chemical species — up to eight at once. With an IP-65-compliant housing and a 2-year-life lamp, the IPS-4 needs no annual maintenance. So it’s perfect for outdoors, next to inaccessible areas along your process. Just 31 inches wide, the IPS-4 is packed with features including 22-key keypad, analog signal output, 3 digital signal ports, high-speed Ethernet port, plug-and-play/web-based queries, alarm contacts, RS232 and RS485 ports. Plus, its multilingual interface includes English, French, German, Russian and Spanish. The IPS-4 is available in UV/Vis and NIR versions with fully integrated sampling systems. AMETEK’s entire family of spectrophotometer-based analyzers is proven in applications from chemicals and petrochemicals to pharmaceuticals, food and metals processing. To learn more call 412-828-9040 or visit our web site.

www.ametekpi.com Select 96 at www.HydrocarbonProcessing.com/RS

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

Maximize diesel production in an FCC-centered refinery, Part 2 Part 1 of this article, published in September, presented several methodologies for maximizing the production of high-quality diesel in a refinery that relies on fluid catalytic cracking (FCC) as its principal means of heavy oil conversion. Part 2 focuses on the selection of FCC catalysts, methods for hydroprocessing light cycle oil (LCO) from the FCC unit, and the production of diesel fuel from FCC byproducts, among other topics. FCC catalyst selection. Some catalyst recommendations apply to both high-severity and low-severity FCC operations. Low-hydrogen-transfer FCC catalyst is recommended for maximizing refinery diesel production, as this type of catalyst will generally produce a higher-yield and higher-quality LCO that can be hydroprocessed, while increasing the yield of FCC olefins that can be oligomerized. Similarly, active matrix functionality improves LCO yield and quality. H2 transfer reactions strip H2 from saturated LCO molecules (such as naphthenes) and transfer it into gasoline boilingrange olefins. The net impact of these H2 transfer reactions is that the LCO becomes more aromatic (lower cetane number and more dense), the gasoline becomes more saturated (lower olefin content and lower octane), naphtha yield increases, and LPG olefin yield declines. In FCC operations intended to maximize gasoline production, the H2 transfer reactions provide a net benefit due to the increased gasoline volume resulting from the saturation of the gasoline olefins before they catalytically crack into LPG olefins. The negative impact of H2 transfer activity on LPG olefins, and on naphtha yields and naphtha octane, has been widely documented, while the negative impact on LCO quality has been less publicized. In high-LCO-yield FCC operations where LCO quality, gasoline octane and LPG yield considerations are more important than sheer gasoline volume, H2 transfer reactions are counter-productive. Refer to TABLE 1 for an example of how the rare-earth content of FCC catalyst can impact FCC yields and product qualities.1 The base catalyst can also be used in combination with a ZSM-5-containing catalyst additive to further preserve the gasoline octane and C3/C4 olefins at low conversion levels. The ZSM-5 additive is applicable to maximizing olefins production from high-severity FCC operations.1, 5 The data in TABLE 2 provide an example of how a ZSM-5 additive can change the yields and product qualities in a moderate-severity FCC operation.2

In low-severity, high-LCO-yield FCC unit operations, ZSM-5 additives have also been shown to convert higher-boiling FCC products into both gasoline and LPG. Two examples of the impact of ZSM-5 additions in low-severity FCC operations are shown in TABLE 3. These data show that the cracking of heavier molecules in the low-severity FCC products by the ZSM-5 results in a loss of total cycle oil (302°F–698°F) production, along with increases in both 302°F true-boiling-point (TBP) gasoline and LPG production.3 Based on a large sampling of pilot plant product from runs having an average conversion level of 40% and a 0.5-wt% ZSM-5 crystal addition, the average Research Octane Number (RON) changes were as follows: • Increase of 2.4 numbers for the initial boiling point (IBP) to 302°F gasoline • Increase of 3.3 numbers for the IBP to 410°F gasoline. Low-equilibrium catalyst micro-activity testing (MAT) activity is often employed when maximizing LCO production. Active-matrix FCC catalysts are also recommended for LCO TABLE 1. FCC pilot plant comparison of yields and product qualities with different catalysts* Catalyst Conversion, vol%

Higher-rare-earth REY catalyst

Lower-rare-earth USY octane catalyst

72.5

72.5

0.02

0.02

1.28

1.13

1.9

1.4

Yields H2, wt% C1 + C2, wt% C3, vol% C3 =, vol%

6

7.6

C4s, vol%

13.6

15.1

Gasoline, vol%

59

58

LCO, vol%

18.1

19.5

640°F residue, vol%

9.4

8

Coke, wt%

4.6

4

86

90.4

Gasoline octane, RON + 0 Gasoline octane, MON + 0 LCO gravity, °API LCO aniline point, °F

78

80

18.4

20.1

62

75

*Constant pilot plant feedstock and operating conditions: 23.9°API VGO, 40 weight hourly space velocity (WHSV), 4 catalyst:oil weight ratio (C/O), and temperature of 950°F.

Hydrocarbon Processing | OCTOBER 201261

Refining Developments maximization, as they enable the cracking of LCO boiling-range aliphatic side chains from high-molecular-weight feed components. In addition to increasing LCO yield, the aliphatic side chains that report to the LCO boiling range improve LCO cetane. The active matrix also contributes to cetane improvements because matrix cracking does not possess the higher H2 transfer characteristic of a zeolite. Refer to TABLE 4 for representative data concerning the impact of changing the catalyst matrix activity.4 Maximize LCO endpoint. The maximization of LCO endpoint is a common operating strategy for increasing LCO production at the expense of low-value FCC slurry oil. In many FCC operations, concern for coking in the FCC main fractionator bottoms circuit limits the LCO endpoint. A number of FCC operating parameters influence the propensity of the bottoms circuit to suffer coking problems: TABLE 2. Effect of ZSM-5 additive on yields and product qualities in FCC pilot plant* Catalyst

Octane-barrel Catalyst with 4% FCC catalyst ZSM-5 additive

Conversion, vol%

Delta

68

68

NA

2.38

2.49

0.11

Yields H2, C1+ C2, wt%

2

1.9

−0.1

C3=, vol%

C3, vol%

6.8

7.4

0.6

C4=, vol%

6.1

6.9

0.8

iC4, vol%

4.2

4

−0.2

nC4, vol%

1.1

0.9

−0.2

Total LPG

20.2

21.1

0.9

Gasoline (450°F TBP), vol%

57.6

56.8

−0.8

LCO, vol%

18

17.9

−0.1

Bottoms, wt%

14

14.1

0.1

3.9

3.8

−0.1

Gasoline octane, RON + 0

Coke, wt%

90.2

91.6

1.4

Gasoline cetane, MON + 0

79.2

79.6

0.4

*Constant pilot plant feedstock (27.0°API VGO) and operating conditions (960°F).

TABLE 3. FCC plant data showing effect of ZSM-5 additive on yields and product qualities Low-conversion FCC operation Catalyst system

FCC product considerations. Changes in FCC cracking

severity directly impact FCC product yield distribution and qualities. In the FCC pilot plant example presented in TABLE 5, the VGO is of average quality as an FCC feedstock, and the catalyst is a low-rare-earth catalyst with some matrix activity. The pilot plant runs covered reactor temperatures and conversion levels ranging from low to high, relative to industry norms. The pilot plant data show the tradeoffs between LCO production and quality, and the production and quality of FCC naphtha. As shown in TABLE 5, even without adjusting the LCO cutpoints, the LCO yield changes by a factor of almost 2 by adjusting the FCC reaction severity. At the same time, among the runs presented in TABLE 5, the gravity of the LCO increases by about 11°API as the operating severity is lowered. FIG. 1 summarizes the positive relationship between increasing LCO production rate and LCO quality, as observed in a TABLE 4. FCC pilot plant study results Catalyst matrix surface area

Low

High

Conversion

69.5

69.7

53

53.1

Gasoline (C5 at 421°F) Yield RON

87.7

90

MON

77.8

78.5

36/23/15/27

26/36/14/24

Paraffins/olefins/napthenes/ aromatics (PONA) LCO (421°F–602°F) Yield

16.3

19.2

Cetane index

24.5

28.5

API

21.8

23.8

Aromatic carbon, %

49.5

45.9

Aliphatic carbon, %

50.5

54.1

Carbon NMR

Plant A

Plant B

REY zeolite with ZSM-5 additive

REY zeolite with ZSM-5 additive

Incremental yields from ZSM-5 addition Dry gas, wt%

• Bottoms circuit temperature • Bottoms circuit liquid residence time • Concentration of unconverted paraffins in the slurry oil. In high-conversion FCC operations, the slurry oil is more aromatic and can be held at higher temperatures and longer residence times without coking. Some of the slurry oil quality data that FCC operators monitor as indicators of coking tendency are gravity and viscosity. The more aromatic slurry oil produced by high-conversion FCC operations will allow the unit to operate with lower API gravities while respecting bottoms viscosity targets selected to avoid fractionator coking.

Bottoms (602°F+) Yield

14.2

11.1

13

7.6

+0.3

–

Gravity, °API

LPG, vol%

+2.4

+2.9

Carbon NMR

Gasoline (302°F IBP), vol%

+4.8

+3.3

Aromatic carbon, %

39

57.4

Total cycle oil (302°F–698°F)

–3.2

–6.7

Aliphatic carbon, %

61

42.6

Bottoms (698°F+)

–4.5

+0.2

Viscosity at 210°F, cst

7.87

5.8

–

+0.2

Viscosity at 100°F, cst

116.4

68.14

Coke, wt%

62OCTOBER 2012 | HydrocarbonProcessing.com

Refining Developments larger sampling of the same pilot plant study data. Conversely, FIG. 2 and FIG. 3 show a very direct and negative correlation between LCO yield and FCC naphtha octane. FIG. 2 demonstrates that, irrespective of the indicated FCC reaction temperature, FCC naphtha motor octane will suffer as LCO yield increases. FIG. 3 shows that the negative impact of increasing LCO yield on the olefin-dependent RON can be mitigated to some extent, if a high FCC reaction temperature is maintained. The data in TABLE 5 also provide examples of how changing FCC reaction severity can impact LPG yield and naphtha octane. Comparing the low-conversion and high-conversion cases, the data show that the low-conversion case produces less than one-half the LPG and 3 to 4 numbers lower octane than the high-conversion case. TABLE 5 also provides an example of the degradation of LCO as a potential feedstock for upgrading into diesel as the FCC

conversion is increased; the LCO H2 content decreases from 10.7 wt% to 8.8 wt% as the FCC conversion level is increased from 59 wt% to over 76 wt%. Hydroprocessing options. Processes for the upgrading of LCO range from mild hydrodesulfurization to full-conversion hydrocracking. FIG. 4 depicts some of the chemistry responsible for improving the cetane, density and aromatics content of the LCO. For the purposes of this article, three upgrading processes (hydrotreating, aromatics saturation and mild hydrocracking) are described as representative examples of some of the processes being used today.5 LCO hydrotreating. Mild hydrotreating of LCO will reduce its sulfur content significantly, but this will only modestly improve the product qualities related to aromatic content. In examples presented in TABLE 6, LCO in a 10% concentration, in

TABLE 5. FCC pilot plant data showing impact of changing operating severity Low conversion

Medium conversion

High conversion

FCC feed properties Gravity, °API

22.5

22.5

22.5

50 vol% boiling point, °F

851

851

851

Aniline point, °F

176

176

176

Sulfur, wt%

0.55

0.55

0.55

CCR, wt%

0.89

0.89

0.89

FCC pilot plant operating conditions 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

0.6

0.6

0.6

Dry gas, wt%

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

Coke, wt%

5.59

5.27

7.99

58.98

66.47

76.33

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

Conversion, wt% FCC pilot plant product qualities C3 LPG olefinicity, wt%

83.8

83.8

85.7

C4 LPG olefinicity, wt%

66.7

68.5

67

Naphtha gravity, °API Naphtha octane, RON/MON Naphtha PONA, 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 | OCTOBER 201263

Refining Developments a mixture including straight-run gas oil (SRGO), is hydrotreated. Two options are presented, with the latter representing a higher degree of desulfurization and greater aromatics reduction. These examples demonstrate that it is possible to include about 10% LCO in the diesel pool by hydrotreating the LCO/ SRGO mixture. Aromatics saturation. To accommodate larger concentrations of LCO in the diesel pool, more complete aromatics LCO quality

30

saturation and cetane improvement are required. These goals can be achieved through varying degrees of ring saturation and ring opening, as shown in FIG. 4. TABLE 7 shows what is possible utilizing a two-stage aromatics saturation unit to process 100% LCO.5 The drawback of ring saturation is high H2 consumption. Mild hydrocracking. Another alternative is to rely on ring opening with mild hydrocracking to move some of the aromatics out of the LCO boiling range into gasoline, as shown TABLE 6. Processing a 10% LCO blend with ULSD catalyst systems

940°F 980°F 1,020°F

25

Product

Gravity, °API

Operating pressure 20

Feed: 90% SRGO/10% LCO

CoMo

NiMo

Medium

High

880

863

853

15,300

50

10

543

534

523

Density, kg/m3 Sulfur, wppm

15

D86 T10, °F

10 5 10

20

586

579

570

D86 T90, °F

660

657

649

IP391 monoaromatics, wt%

16.7

22.6

21.4

15

9.2

2.8

31.8

31.8

24.2

IP391 PNA, wt%

30

LCO yield, wt%

D86 T50, °F

IP391 total aromatics, wt% FIG. 1. Relationship between increasing LCO production rate and LCO quality.

47

51

52.5

H2 consumption, Nm3/m3

NA

37

72

FCC naphtha quality

85

TABLE 7. Two-stage LCO aromatics saturation 940°F 980°F 1,020°F

84 Naphtha MON

Cetane number

100% LCO

Two-stage

Operating mode

83

Product

Medium

Operating pressure 960

859

7,300

< 10

79.1

2.5

Density, kg/m3

82

Sulfur, wppm 81

Total aromatics (FIA), vol%

24.1

40.2

< 20

44.9

NA

25+

Liquid yield, vol%

NA

115.7

H2 consumption, Nm3/m3

NA

473

Cetane index, D976

80 10

15

20

25

30

35

Cetane number

LCO yield, wt%

Delta cetane number FIG. 2. Relationship between FCC naphtha quality (MON) and LCO yield.

FCC naphtha quality

96

940°F 980°F 1,020°F

Naphtha RON

95

Aromatic saturation

1 2H2

Diesel

3H2

94 93

H2

92

C5H11

91 90 10

20

LCO yield, wt%

30

FIG. 3. Relationship between FCC naphtha quality (RON) and LCO yield.

64OCTOBER 2012 | HydrocarbonProcessing.com

H2

2

Diesel Selective ring opening

3H2 3

FIG. 4. Three reactions to upgrade LCO quality.

C5H11

Hydrocracking Diesel

Refining Developments TABLE 8. ULSD and mild hydrocracking on feed blend containing 10% LCO and 35% coker diesel* Property

Feed

ULSD product

MHC product

MHC product

Density, kg/m3

866

842

829

822

Delta density

NA

24

37

44

Sulfur, wppm

8,000

< 10

< 10

< 10

42.4

23

13.2

14

Mono

30

20

12.8

13.5

PNA

12.4

3

0.4

0.5

36.8

43.8

46.2

46.8

SFC aromatics (total), wt%

Total product cetane index, D4737 Delta cetane index

NA

7

9.4

10

Chemical H2 consumption, Nm3/m3

NA

116

150

155

Incremental 379°F minus, vol%

NA

1.1

10

20

*For MHC cases, diesel product is 2 to 3 cetane numbers higher than total product.

100 80 Cetane number

LPG Naphtha

N-paraffin Mononaphthenes

60

Selective ring opening

40 20

Aromatic naphthene

0

Diaromatics

-20 100

150

Aromatic saturation

FCC C3/C4 LPG

Monoaromatics

Diesel

HDS H2

Dinaphthenes

H2S

FCC recycle

Raffinate: paraffins + olefins FCC naphtha

200 Molecular weight

Olefin oligomerization unit

LCN

250

Extract: sulfur + aromatics

MCN

H2

FIG. 5. Hydrocarbon comoponents and cetane number.

in FIG. 5. This approach can provide substantive LCO quality improvement with lower H2 consumption. TABLE 8 provides an example of coprocessing LCO along with straight-run distillate and other cracked products.5 Creating diesel from FCC byproducts. Two processing op-

tions with limited application to date are the creation of synthetic diesel from FCC olefins and the extraction of aromatics from FCC naphtha. These options can be integrated into the overall processing scheme, along with the other options described earlier. Reprocessing of C3–C9 olefins into distillate. Olefins can be used to produce good-quality diesel with oligomerization processes. For example, an oligomerization unit distillate yield from a C3–C9 olefin feed was reported to be 78% distillate with a byproduct gasoline yield of 19%, based on a zeolite catalyst, as shown in TABLE 9. After hydrotreating to saturate the olefins, the distillate was reported to have a cetane number of 52 to 54, zero sulfur and less than 2% aromatics.6 Therefore, for FCC-based refineries working to maximize diesel production, oligomerization of olefins-containing FCC light gasoline and LPG may provide viable investment opportunities. FCC naphtha extraction. Extractive techniques are available for separating a middle boiling fraction of FCC gasoline into a higher-octane, aromatics-rich fraction and an olefinsand paraffin-rich fraction.7 A recently granted patent describes a combined FCC/extraction process wherein an aromatics-

H2S

Solvent HCN

5

Aromatics

HDS

300

Severe HDS

ULS gasoline blending

FIG. 6. Production of diesel from FCC LPG and FCC naphtha.

rich, higher-octane fraction of FCC gasoline can be produced as a gasoline product, while a paraffinic/olefinic naphtha fraction can be produced for recycle to an FCC riser for the purpose of producing propylene and other olefins.8 This FCC naphtha extraction concept and oligomerization technology can be used together, as shown in FIG. 6, to maximize the production of synthetic diesel from FCC olefins. The combination can be especially useful in the context of a high-LCO-yield, low-severity FCC operation because the lowseverity FCC naphtha will have a higher olefins content than the more aromatic, more paraffinic naphtha from a high-severity FCC operation. Thus, the non-aromatic naphtha raffinate from a low-severity FCC operation will make a better-quality oligomerization feedstock—or a better-quality FCC recycle stream—for the purpose of increasing lighter FCC olefins production, as olefins are easier to crack than paraffins. Refinery diesel balance. With all the processing options presented in this article, an obvious question is, “How much can the refinery diesel production be increased if many of these options are applied in a retrofit of an existing refinery?” The answer depends on the specifics of the application. TABLE 10 shows estimated results from isolated examples provided in this article, giving insight into the question. Hydrocarbon Processing | OCTOBER 201265

Refining Developments Takeaway. Assuming demand for diesel continues to increase faster than growth in gasoline, a number of reactions can be expected from the refining industry: • The loss of virgin diesel to the FCC unit will diminish through crude distillation unit improvements • FCC gasoline endpoint will be minimized • Hydrocracking and hydrotreating units designed to upgrade LCO quality will proliferate • Low-H2 -transfer, higher-matrix-surface-area FCC catalyst will be used to improve LCO yield and quality, while increasing LPG olefins production and naphtha octane • In some cases, ZSM-5 catalyst additives will be used to further increase LPG olefins production and octane, but in low-severity FCC operations, this may come at the expense of some LCO yield. For refiners that also place high value on propylene production, high-octane gasoline, and minimization of refinery bottoms production, the high-severity FCC route to making more diesel will gain favor through the oligomerization of C4 and higher FCC olefins while continuing to hydroprocess the LCO production. If a refiner has a more singular focus on the production of diesel, the low-severity, traditional FCC route to increasing diesel can be optimized and economically favored, with some enhancements: • The loss of LCO in slurry oil product or recycle will diminish through the use of dedicated slurry distillation hardware TABLE 9. Product yields and properties from oligomerization of olefins Feed composition

82% C3–C9 olefins

Product yields (based on feed olefins), vol% Gasoline

19

Distillate

78

• Some of the stripped slurry oil may be recycled to the FCC reactor to produce more LCO and help maintain FCC heat balance, while HCO recycle may also be advantageous • Low-severity FCC operations will rely on increasing feed temperature and, in some cases, direct firing of the regenerator with a liquid or gaseous fuel using technology designed to minimize damage to the catalyst • FCC-produced LPG and naphtha olefins will be converted into diesel blending stock using oligomerization processes. An ultimate vision for maximizing diesel production in a specific FCC-centered refinery may also include a selective combination of elements: • Extraction processes will separate aromatics-rich fractions of FCC gasoline from fractions enriched in olefins and paraffins. The aromatic fraction can be used for BTX production or high-octane motor fuel; the non-aromatic fraction can be recycled to the FCC reactor for the production of more olefins (diesel precursors), or the olefins in the non-aromatic fraction may be directly oligomerized into diesel. • FCC C4s and FCC light naphtha can be recycled to an ultra-high-severity FCC riser to increase propylene and aromatic naphtha yields, without diminishing LCO production. A case-by-case analysis based on refinery-specific data is needed to accurately contrast the costs and benefits associated with the application of various options for increasing diesel production from the FCC-centered refinery. The performance of the study requires both refinery-wide and FCC-specific experience and related modeling capabilities. In the final analysis, it is simply a question of economics; technologies are available to maximize diesel production from the FCC-centered refinery. LITERATURE CITED Complete literature cited available online at HydrocarbonProcessing.com.

Distillate qualities after mild hydrotreating Boiling range, °F (IP 123/84)

388–676

Density, kg/m3 at 20°C Cetane number

787 52 to 54

Aromatics content, wt%