HP_2013_02 by androsov.info

CLEAN FUELS

HydrocarbonProcessing.com | FEBRUARY 2013

Innovative licensed technologies and catalysts solve the problems of processing cleaner transportation fuels and improving profits; case history investigates operating a ‘green’ refinery

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FEBRUARY 2013 | Volume 92 Number 2 HydrocarbonProcessing.com

6 95

SHOW PREVIEW: EASTERN MEDITERRANEAN GAS CONFERENCE

33 Discover what opportunities the Eastern Mediterranean holds for you A. Blume

SPECIAL REPORT: CLEAN FUELS

37 Refinery optimization: Closing the gap between planned and actual performance E. Petela

DEPARTMENTS

4 6 9 13 102 105

Industry Perspectives Brief Impact Innovations Marketplace Advertiser index

41 New residue-upgrading complex achieves Euro 5 specifications D. de Haan, M. Street and G. Orzeszko

45 Operator training simulators for brownfield process units

COLUMNS

Reliability Top three ways to improve pump service life

Integration Strategies US biodiesel industry regains momentum

Boxscore Construction Analysis 2013 global construction outlook

Viewpoint Interview with UOP

offer many benefits T. Ayral and P. De Jonge

49 How to choose a refiner for your precious metals catalyst K. M. Beirne

57 Select new production strategies for FCC light cycle oil R. Pillai and P. K. Niccum

63 Use an innovative cracking catalyst to upgrade residue feedstock Y.-A. Jollien, C. Keeley, J. Mayol, S. Riva and V. Komvokis

69 The next generation of interfaces for engineering software S. Brown

75 Consider advanced technology to remove benzene from gasoline blending pool T. Thom, R. Birkhoff, E. Moy and E-M El-Malki,

106

Automation Safety It’s all about the safety PLC—not!

HEAT TRANSFER—SUPPLEMENT

H-81 Improve the performance of your existing steam system R. O. Pelham

HPI FOCUS: THE GREEN REFINERY

95 Venice’s biorefinery: How refining overcapacity can become an opportunity with an innovative idea G. Rispoli, A. Amoroso and C. Prati Cover Image: A new delayed coker was added to the Marathon Petroleum Co. LP refinery in Detroit, Michigan. The coker was built as part of the Detroit Heavy Oil Upgrade Project (DHOUP), which will allow the refinery to process heavier, more viscous crude oils. DHOUP has increased the Detroit refinery’s capacity from approximately 106,000 bpd to 120,000 bpd, resulting in an increase of more than 400,000 gpd of transportation fuel production. Photo courtesy of Marathon Petroleum Co.

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Industry Perspectives Energy industry expects approval on the Keystone XL With US President Barack Obama’s second four-year term now secure, most in the global hydrocarbon processing industry (HPI) expect the Obama administration to ultimately approve the controversial Keystone XL pipeline system. Out of hundreds of votes cast on HP’s website, 68% believe the US president will give the green light to TransCanada to build the expanded system, which could connect the US Gulf Coast refining base with crude oil feedstock from Canadian oil sands. The president previously denied TransCanada the Keystone XL permit in January 2012, citing an arbitrary deadline from Republicans. Several political pundits said Obama also might have been apprehensive about going against the demands of the wealthy environmental lobby during campaign-financing season. Obama then asked TransCanada to reapply with an alternate route to avoid the Sand Hills in Nebraska, an important aquifer in the region. The revised route was recently reviewed and largely approved by state environmental regulators, though the US State Department is conducting its own review as well. The HPI favors moving forward on the pipeline for a number of reasons including energy security, jobs creation and economic growth. “With poll after poll continuing to show strong public support for this project, we (API) remain hopeful that the president will soon conclude this project is indeed in our nation’s interest. It’s a huge job creator, yes. But it will also bring secure supplies of oil to our Gulf coast refineries from not only Canada, but [also] from North Dakota and other plains states as well.”

—CINDY SCHILD, American Petroleum Institute Manager of Downstream and Industry Operations

The proposed system would result in a 1,700-mile oil pipeline stretching from Canada to Texas, carrying nearly 1 million bpd of oil. TransCanada says it expects to receive a permit from the US government by the end of the 2013 first quarter. If that happens, the project could be completed and in operation by early 2015. HydrocarbonProcessing.com reader response poll questions:

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With a second term as US president now secure, will the Obama administration approve the proposed Keystone XL pipeline system? Yes ........................................................................................................................................ 68% No ..........................................................................................................................................32% Visit HydrocarbonProcessing.com to participate in future polls.

President/CEO Vice President Vice President, Production Business Finance Manager

John Royall Ron Higgins Sheryl Stone Pamela Harvey

Part of Euromoney Institutional Investor PLC. Other energy group titles include: World Oil and Petroleum Economist Publication Agreement Number 40034765

4 FEBRUARY 2013 | HydrocarbonProcessing.com

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| Brief Bakken oil destined for New Jersey Phillips 66 has signed a five-year contract to use Global Partners LPâ&#x20AC;&#x2122;s rail transloading, logistics and transportation system to deliver crude oil from the North Dakota Bakken region to the Phillips 66 Bayway refinery in New Jersey. The terms of the contract include a take-or-pay commitment from Phillips 66 to receive approximately 91 million barrels of crude oil over the contract term, which equates to approximately 50,000 bpd. The contract will utilize Globalâ&#x20AC;&#x2122;s network of loading facilities and offloading terminals. Phillips 66 is one of the first energy companies to move shale crude to the East Coast. Last year, the company expanded its capability to deliver shale crude to its refineries by truck, rail, barge, ocean going vessels and pipeline. Photo: The Phillips 66 Bayway refinery in Linden, New Jersey.

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

Brief

The American Fuel and Petrochemical Manufacturers (AFPM) has petitioned the US Environmental Protection

Agency (EPA) to waive the 2012 cellulosic biofuel mandate, citing a lack of domestic supply available for commercial use. The AFPM said the EPA Moderated Transaction System (EMTS) demonstrates that there has been, and continues to be, an inadequate domestic supply of cellulosic biofuel. In 2011, American refiners were required to use 6 million gallons of cellulosic biofuel to meet the EPA-established mandate, yet according to EMTS, zero cellulosic biofuel was actually produced. To date in 2012, just 20,069 gallons of cellulosic biofuel has been produced, all of which was exported. This amount falls far short of the EPA-mandated 10.45 million ethanol-equivalent gallons of cellulosic biofuel. In addition, since the cellulosic biofuel that actually was produced was exported, refiners cannot use credits generated from these biofuels for complying with the federal mandate. The AFPM has stated that if the EPA fails to grant the waiver, refiners will be forced to pay several million dollars for a product that does not exist. The industry group further believes that this mandate is a hidden tax on the refining industry and is not what Congress intended when it incorporated the waiver provisions into the RFS. Emerson Process Management is offering a cash-back valve and instrument recycling program through its

instrument and valve services business. The new recycling program gives plant sites with a control valve boneyard greater residual value for used or inoperable control equipment. Using bins provided by Emerson, the recycling effort provides free pickup and shipment from the plant site to an instruments and valve services recycle center, rapid evaluation of valve and instrument cores and prompt payment with an itemized transaction report. The recycling program provides greater return on original investment than traditional scrapping practices, according to the company. It also helps prevent unnecessary waste of potentially useful materials. The program focuses on Fisher control valves and Rosemount instruments. But, to keep recycling efforts seamless and simple, Emerson is accepting non-Fisher valves as well, the company said. NuStar Energy has closed on the sale of its San Antonio, Texas, refinery and related assets, including a terminal

in Elmendorf, Texas, to Calumet Specialty Products Partners for $100 million, plus closing date inventory of approximately $15 million. NuStar purchased the refinery and terminal out of bankruptcy in April 2011 for $41 million, and the company has invested approximately $54 million since then on improvements. NuStar sold the refinery as part of its strategic redirection away from the earnings volatility associated with the margin-based refining business in order to further grow its fee-based pipeline and storage operations. The 14,500-bpd refinery produces and sells various products, including jet fuels, ultra-low-sulfur diesel, naphtha, reformates, liquefied petroleum gas, specialty solvents

and other highly specialized fuels, to commercial and retail customers and the US military. The Elmendorf terminal, which is approximately 12 miles away from the refinery, stores the crude oil that is processed at the refinery. Tesoro will stop producing fuel at its refinery in Kapolei, Hawaii, and convert the facility to an import, storage and

distribution terminal. Tesoro had been trying to sell the 94,000bpd refinery since January 2012 because of declining profit margins. The conversion to an import facility, expected to occur in April, will allow Tesoro to cut costs related to processing fuel there while still allowing the company to distribute fuel in the state. The conversion is expected to add as much as $350 million in cash to the company’s bottom line by the end of 2013 as working capital costs decrease. Valero Energy has formed a 50-50 joint venture with TGS Development to build a new marine terminal on the lower

Sabine-Neches Waterway near Port Arthur, Texas. As participants in the joint venture, known as PI Dock Facilities, TGS will act as the site developer and Valero will act as the operator. The marine terminal will receive crude tankers of up to Suezmax class, and will be able to operate without the daylight restrictions imposed on other terminals in the upper Sabine-Neches Waterway. The crude dock, which is scheduled for completion in the fourth quarter of 2013, will deliver crude oil through a new 36-inch pipeline to Valero’s Port Arthur refinery and will have the flexibility to connect to other local refineries. The marine terminal site spans over 100 acres and has space for two additional berths suitable for LPG and refined product exports or additional crude receipts. Motiva Enterprises said the crude unit of its Port Arthur refinery expansion in Texas leaked while being restarted

in early January and was shut down. The company said it still plans to have the VPS 5 crude distillation unit fully restarted soon. The new crude unit, first commissioned in May 2012, has experienced several setbacks. In December, Motiva began the process of bringing the unit back online after six months of repairs, but a small mechanical fire and then the possibility of another leak thwarted the effort. The Motiva refinery is jointly owned by Shell and Saudi Aramco. Qatar Petroleum, Qatar Airways and Royal Dutch Shell have teamed up to unveil a new aviation jet fuel. Gas-to-

liquids (GTL) jet fuel blended with synthetic paraffinic kerosine (SPK) at the Pearl GTL plant in Qatar is now flowing into airplane tanks at Doha International Airport. The companies said this is the first new aviation fuel to be approved globally in two decades. Fully approved for use as an aviation fuel, GTL jet fuel is a blend of up to 50% GTL SPK meeting the requirements of ASTM-D-7566 and conventional crude oil-derived standard jet fuel ( Jet A-1). Hydrocarbon Processing | FEBRUARY 2013

AD00387P

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

Impact

Russia’s interest in accessing the Asian gas market A recent briefing paper from Chatham House thoroughly examines natural gas security issues in northeast Asia. The authors assert that northeast Asia will become a major market for gas in the coming decade, led by China, which plans to quadruple its gas demand by 2030. Their conclusion is that closer collaboration between Russian and Chinese national oil companies and a gas importers union between China, Japan and South Korea would support an equitable pipeline deal and lay the foundation for regional energy security. For Russia, China’s escalating gas demand presents an unparalleled new market opportunity for its Far Eastern gas production. Russia’s energy strategy aims at sending 20% of its natural gas exports to the Asia-Pacific market by 2030. As of 2012, the only gas exported

eastward came from the 9.6 MMtpy of Sakhalin liquefied natural gas (LNG), mainly destined for Japan. For Russia to achieve large-scale gas export to Asia, it needs to start developing the super-giant onshore gas fields in East Siberia without delay. But to do this requires securing a market of sufficient size to justify the infrastructure costs. China is an essential part of the picture but the Russian government is keen to avoid being locked into a relationship with it as the single dominant customer. Russia has therefore pursued a number of LNG and pipeline options that could expand trade with other Asia-Pacific Economic Cooperation (APEC) countries as well as penetrate the Chinese market. FIG. 1 shows the various sources of Russian gas earmarked for Asian markets and transit routes under consideration. It also illustrates the four main gas supply sources for Russia’s gas exports to Asia: Sakhalin Island, the Sakha Republic (chiefly the Chayanda field), the Irkutsk region 1

Urengoy

RUSSIA Nizhnevartovsk

Tyumen

Novosibirsk Barnaul

Astana

KAZAKHSTAN

Krasnoyarsk Abakan Novokuznetsk Biysk Gorno-Altaisk

5 OKHA Malositinskoye UGS Facility

Nizhnaya Poyma 3

Lake Baikal

To China

Chita Balagansk Irkutsk

Korsakov To Asia-Paciﬁc

Birobidzhan Dalnerechensk To China To China

Vladivostok To Korea and Asia-Paciﬁc

MONGOLIA

CHINA

Sakhalin Island

Khabarovsk

Blagoveshchensk

Ulan-Bator Gas pipelines In operation Gas deliveries Under construction Projected gas processing plants and gas-chemical facilities

Komsomolsk-on-Amur Skovorodino

Boguchany Omsk

5 Sakhalin I-II Yurubcheno-Tokhomskoye 3 Kovyktinskoye Reserves: 980 billion m3 Reserves: 2,000 billion m3 Reserves: 337 billion m3 Sobinsko-Paiginskoye 4 Chayandinskoye 6 Sakhalin offshore prospects Reserves: 170 billion m3 Reserves: 1,240 billion m3

Sakha Republic-Khabarovsk-Vladivostok Pipeline 2 4

Tomsk Proskokovo

(chiefly the Kovykta field) and West Siberia. The earliest production date that Gazprom has projected for the onshore Siberian fields is 2016, but 2017–2018 currently looks more realistic. On Sakhalin Island, only the Sakhalin II project is producing LNG. The Sakhalin I project and Sakhalin III project’s Kirinskoye block and Yuzhno- Kirinskoye block are in preparation for production but require more exploration. Russia’s Far East program aims to combine two trunk pipelines—SakhalinKhabarovsk-Vladivostok and Sakha Republic (Chayandagas)-Khabarovsk-Vladivostok—to bring more gas eastward. Gazprom plans to export 10 MMtpy of LNG from Vladivostok—chiefly to Japan—by 2020, with the potential to send more to South Korea, China and beyond. Gazprom is also under significant political pressure to develop East Siberia and Russia’s Far East. Immediately after the presidential election in March 2012, President Vladimir Putin urged

Beijing

NORTH K O REA

JAPAN Tokyo

SOUTH K O REA

Source: Adapted from Gazprom. Reserves adjusted based on Rosneft and ExxonMobil ﬁgures.

FIG. 1. Russia’s Far East gas program. Hydrocarbon Processing | FEBRUARY 2013

Impact the company not to ignore the exploration and development of gas resources there. He said that Russia should try to gain a significant share of the global LNG market, focusing first on supplies to promising Asian markets. Gazprom then announced that it would draw up an investment study for Vladivostok LNG in the first quarter of 2013, stating that it considers 2017–2020 the “most favorable period” for targeting Asia.

But there is clearly tension between the political priority and the commercial logic. In late October, Putin urged Gazprom Chief Executive Officer Alexei Miller to ensure that work on the trunk gas pipeline from the Chayanda field in the Sakha Republic to Vladivostok began “as quickly as possible.” The questions for Russia are how much gas will be able to be marketed as LNG, given that the price may not be competi-

tive enough for China’s subsidized domestic market, and what volume of sales can be secured through pipeline contracts. Sino-Russian gas cooperation. In

2006, Russia agreed in principle to supply China with 68 Bcm of its gas over 30 years. However, negotiations between the two parties for a deal to establish the necessary pipelines have been frustrated by disagreements on the linked issues of price and whether to prioritize a western pipeline into Xinjiang or an eastern pipeline into northeastern China. National development and geopolitical aspirations underpin the position of each party. China wants Russian gas primarily to supply its northeastern provinces of Heilongjiang, Jilin and Liaoning. Russia favors prioritizing the Altai route from its West Siberian gas fields to western China, which would enable Gazprom to divert its surplus European volume to China. This would effectively make Russia a swing supplier, increasing its ability to use gas as a political bargaining tool with countries such as Ukraine. Gazprom has tried to gain access to China’s West-East Pipeline (WEP) corridor through a joint investment proposal in the past, but to no avail. For Russia, China’s three northeastern provinces offer only a 20-Bcm/y gas market, whereas at least 30 Bcm/y would be needed to justify the development of an eastern pipeline. While Gazprom announced in September 2010 that a legally binding agreement had been reached with CNPC, setting out the commercial parameters for deliveries through the western route, no agreement on the border benchmark price for Russian gas deliveries has been reached to date.

A big market for catalytic and thermal treatment In 2013, just under $26 billion will be spent to remove carbon monoxide, volatile organic compounds and particulate carbon from stationary and mobile sources. Ninety-two percent of the market purchases will be for mobile sources (TABLE 1). This is the conclusion reached in a report published by the McIlvaine Company. Gasoline-fueled vehicles typically use a three-way catalyst (TWC) to convert three pollutants: carbon monoxide (CO), hydrocarbons (HCs) and oxides 10

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Impact of nitrogen (NOx ) to carbon dioxide (CO2 ), water (H2O) and nitrogen (N2 ). Diesel-fueled vehicles use a diesel oxidation catalyst (DOC), which uses oxygen (O2 ) in the exhaust gas stream to convert CO to CO2 and HCs to H2 O and CO2 . These converters often operate at 90% efficiency, virtually eliminating diesel odor and helping to reduce visible particulates (soot). A DOC can reduce particulate matter (PM) by up to 50%, but more effective PM removal may be required and is achieved with diesel particulate filters (DPF). NOx emissions are more challenging, with selective catalytic reduction (SCR) and NOx traps (or NOx absorbers) as the two main removal techniques used. DPFs remove particulate matter found in diesel exhaust by filtering exhaust from the engine. The filters are commonly made from ceramic materials such as cordierite, aluminum titanate, mullite or silicon carbide. To ensure that particulates are oxidized at a sufficient rate, the filter must operate at a sufficient temperature and with oxidizing gases, which can be supplied by the exhaust gas stream in some systems. This filter is referred to as the “passive” filter, and it regenerates continuously during the regular operation of the engine. Passive filters usually incorporate some form of a catalyst. Sales of emission control systems are being driven by increased regulations. European standards are setting the pace for the world, and many countries have adopted these or similar standards. Low emissions zones are progressively implemented in many urban areas in Europe and these request that diesel vehicles to meet a satisfactory level of exhaust emisTABLE 1. Mobile catalyst sales, $ millions Diesel catalyst

6,782

Gasoline catalyst

4,727 23,929

TABLE 2. Stationary thermal treatment, $ millions Catalytic oxidizer

RTO

906

TOTAL

Complete Level Measurement for Harsh Environments

VEGA offers a complete line of level measurement instruments using radiation-based technology for accuracy in the most extreme environments. VEGA detectors supply the following beneﬁts: ϶ Non-contact measurement is unaffected by corrosive process properties and internal obstructions ϶ Patented ﬂexible detector follows vessel contours and avoids obstructions ϶ External mounting reduces both short and long term maintenance costs

432

RCO

Thermal

under $1.9 billion in 2013 (TABLE 2). The biggest investment will be for regenerative thermal oxidizers (RTOs). Regenerative catalytic oxidizers (RCOs) were once thought to be an important development, but have never met expectations. Direct thermal is used where there is ample fuel value in the gas being treated. Catalytic oxidation is used where there is enough fuel value that combustion will take place in the presence of a catalyst.

12,420

Diesel particulate

TOTAL

sions before they are allowed to drive inside the zone. In the state of California, the California Air Resources Board has mandated that all Class 7 and Class 8 heavy diesel trucks meet certain emission targets by 2016, with interim targets established for 2011, 2012 and 2013 such that 90% of current operating diesel trucks will be required to meet these targets by 2014. The industrial market for thermal treatment, not including flares, will be just

484

www.vega-americas.com americas@vega.com 1-800-FOR-LEVEL

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KEEP THE CONTAMINATION OUT IN CR E A S IN G E F F I CIE N C Y IN CR E A S E S P R O F I T S High performance, advanced technology separation and filtration systems that dramatically decrease or eliminate contamination downstream. High efficiency means increased profits. Reduce or eliminate: ɒ )RXOLQJ ɒ )RDPLQJ ɒ &RUURVLRQ ɒ 6KXW GRZQV For any separation or filtration solution; Solid-Liquid, Liquid-Liquid, Liquid-Gas, or Solid-Gas, call Pentair Porous Media.

POROUS MEDIA® (936) 788-1000 www.porous.com

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ADRIENNE BLUME, PROCESS EDITOR Adrienne.Blume@HydrocarbonProcessing.com

Innovations

UK firm patents mid-scale for laboratories and online process ap- explosion. According to Dantec, the hose plications, developed the ISL PMD 110 is flexible, durable and flame-resistant for LNG technology Gasconsult Ltd. has announced the award of a patent for its new ZR-LNG liquefaction process. ZR-LNG has bestin-class energy efficiency for mid-scale liquefied natural gas (LNG) applications. Specific power consumption for the liquefaction section will typically be in the range of 310 kWh/ton to 350 kWh/ton of LNG, which is marginally higher than current baseload plants but significantly better than single mixed-refrigerant cycles (350 kWh/ton to 400 kWh/ton) and dual nitrogen-expander cycle technology (400 kWh/ton to 500 kWh/ton). The capital efficiency of the technology, combined with its low operating cost, opens the possibility of monetizing smaller gas fields that are unable to support the cost of sophisticated baseload technology. Having a low equipment count, small footprint, low weight, high tolerance to ship motion and no requirement for storage of flammable refrigerants, the process is particularly suited to the floating LNG (FLNG) concept. Gasconsult also sees opportunities for the technology in “end-of-pipe” applications to make LNG for heavy-goods vehicles and as a marine fuel, thereby providing a lower-cost, environmentally benign fuel for these applications. Additionally, Gasconsult is seeking business partnerships or the appointment of licensors in key LNG production markets. Select 1 at www.HydrocarbonProcessing.com/RS

ASTM diesel standard now includes PAC distillation method ASTM recently published its latest version of the ASTM D975-12 Standard Specification for Diesel Fuel Oils, which includes an alternate distillation method, ASTM D7345. This alternate method achieves significant response-time improvements compared to the conventional ASTM D86 method. PAC, a global provider of advanced analytical instruments

and ISL MicroDist instruments, both of which utilize this alternative method. The ISL PMD 110 (FIG. 1) is a laboratory instrument that determines the complete distillation curve within eight minutes, using data from one phase transition (evaporation), thus eliminating the process of condensation. The analysis is based on fundamental thermodynamic dependencies. Immediately after test completion, distillation characteristics are calculated from collected data with an ASTM D86/ ISO 3405-compliant, detailed report. This instrument is universal, reliable and applicable to any petroleum product, without prior knowledge of its properties. Since the ISL PMD 110 instrument is a portable unit requiring no sample preparation, it is also a perfect solution for terminals and mobile labs. It is able to compare the measured distillation curve with up to 80 user-defined specifications and give an in-spec/off-spec answer. The ISL MicroDist instrument (FIG. 2) utilizes the same technology in the process that the ISL PMD 110 uses in the lab. The MicroDist is used for process optimization and product certification, as well as control of blending processes for various refining streams, including motor gasoline, fuel oils, naphtha and diesel.

more than 30 minutes. Even at temperatures approaching 1,200°C, the hose will protect its contents and not burn.

FIG. 1. The ISL PMD 110 instrument determines a complete distillation curve within eight minutes, using evaporation data.

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FIRESAFE hose available for US market Composite hose manufacturer Dantec has launched FIRESAFE, a product it claims is “the safest composite hose ever seen on the US market.” The hose (FIG. 3) is made from a series of specially designed ceramic cloths and heat-reflective films to counter the radiant heat effects of fire. This allows vapor to burn off slowly as the increased heat of the liquid inside the hose vaporizes and seeks to escape. Designed as a safeguard of flammable, hazardous and volatile liquids, the FIRESAFE hose is built for use in environments where there is increased risk of

FIG. 2. The ISL MicroDist instrument is used for process optimization and product certification, as well as control of blending processes for various refining streams. Hydrocarbon Processing | FEBRUARY 2013

Innovations The FIRESAFE hose first gained prominence in Europe in 1994 when it began its association with Formula One racing. During the German Grand Prix in Hockenheim, driver Jos Verstappen was engulfed in flames when a refueling hose breached. Formula One contacted Dantec and placed an order for the hose, which was delivered in time for the next race. The company went on to supply the sport for 15 years. Dantec produces a range of composite hoses designed for the loading, unloading and transfer of oil, gas and petrochemicals. The hoses are used in ship-to-ship, shipto-shore, ship-to-tank, plant-to-truck, truck-to-tank, in-plant and railcar-transfer applications. Select 3 at www.HydrocarbonProcessing.com/RS

New indicator monitors machine health

Experience real capacity control and energy savings

HydroCOM HydroCOM is an efďŹ cient, stepless, dynamic and fully-automated control system. Several different methods are available for capacity control for reciprocating compressors. Only HydroCOM, however, achieves best results in terms of energy savings, speed and accuracy. It improves process control, optimizes

SKF recently launched the SKF Machine Condition Indicator, a low-cost vibration- and temperature-monitoring device designed for rotating machinery with constant operating conditions. The indicator provides the ability to track basic machine health on assets that are not currently being monitored on a regular basis. The device can be used indoors or outdoors, in almost any industry where rotating machines are used, such as oil and gas; pulp and paper; power; food and beverage; machine tools; and heating, ventilation and air conditioning (HVAC). The indicator periodically makes two types of vibration measurement. Velocity measurements are made to keep track of overall machine health and to highlight potential problems related to misalignment and imbalance. Enveloped acceleration measurements are used to detect possible bearing degradation. The indicator features built-in intelligence for evaluating measurements and

performance and pays for itself within a short period of time.

For more information: compressor-mechatronics@hoerbiger.com

www.hoerbiger.com

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FIG. 3. Dantecâ&#x20AC;&#x2122;s FIRESAFE hose is made from a series of specially designed ceramic cloths and heat-reflective films to counter the radiant heat effects of fire.

Innovations also avoiding false alarms, with an alarm status visually indicated via three LEDs. The indicator is fixed to the machine and runs on battery. The device also monitors machine operating temperature. By utilizing the SKF Machine Condition Indicator, plant operators can save both time and money by freeing up maintenance engineers to spend less time on problem detection and more time focusing on root cause analysis and other, more significant issues. Maintenance schedules for noncritical equipment can be assigned at less frequent intervals, as the indicator will provide feedback via its LEDs. The device costs less than a standard industrial accelerometer, which makes the indicator a good solution for manufacturers seeking an economical way to ensure that their semi-critical machine assets are kept up and running. Select 4 at www.HydrocarbonProcessing.com/RS

Pressure transmitters lower plant costs Honeywell’s new SmartLine industrial pressure transmitters (FIG. 4) enhance communication abilities, improve operational efficiency and reduce lifecycle costs for process manufacturers. In industrial process plants, field devices that measure pressure, flow and level are used throughout the manufacturing process to support safe and efficient production. Large industrial complexes, such as those for refining crude oil, can have thousands of these devices to support their manufacturing processes. The SmartLine pressure transmitters make it easier to support field devices and promote plant reliability with their unique efficiency-enhancing features, such as a graphic display capable of showing process data in graphical formats and communicating messages from the control room. The transmitters also feature modular components to simplify field repairs and reduce the inventory required to make those repairs. The new display supports graphical process data in easy-to-read trend lines and bar graphs while also providing a unique platform for operator messages, comprehensive diagnostic warnings, and loop status for maintenance. These capabilities, which are part of the transmitter’s Smart Connection Suite, allow control room operators to send messages to the display. This makes it easier and faster

for field operators to identify the correct transmitter and determine the required maintenance tasks. When integrated with Honeywell’s Experion Process Knowledge System (PKS), the transmitter can also display its maintenance mode, telling field operators if the control loop is in a safe state to perform maintenance. Even installation is made easier with this new display. Three buttons at the top of the transmitter are used with the graphic display to completely configure the transmitter, with no external handheld devices required. The modular design streamlines maintenance by allowing the replacement of individual transmitter components instead of the entire unit, even in hazardous locations. This design reduces plant lifecycle costs by providing purchasing flexibility, lowering inventory costs and reducing maintenance and repair work. Other safety and efficiency features include enhanced security alerts and wiring polarity insensitivity. Tamper reporting alerts the control room and records any change in the transmitters’ configuration, or writes a protection setting to allow operations to investigate any unauthorized access. Unlike most other transmitters, SmartLine transmitters cannot be damaged by reversed wiring polarity and will function correctly if connected as such. This protection is useful during a plant startup, when time can be wasted locating and repairing incorrectly wired devices. Select 5 at www.HydrocarbonProcessing.com/RS

gases, particulates and dioxins in one system. The companies will conduct extensive air emissions testing on a wide range of biomass fuels (FIG. 5). Select 6 at www.HydrocarbonProcessing.com/RS

Valve line receives fire-safe approval AS-Schneider’s ISO FE Series monoflanges are fire-type tested and certified

FIG. 4. Honeywell’s SmartLine industrial pressure transmitter line enhances communication abilities, improves operational efficiency and reduces lifecycle costs.

Strategic alliance advances biomass initiatives Tri-Mer Corp., a developer of advanced technologies for the control of NOx , fine particulate and industrial gases, has partnered with Enginuity Energy LLC, a renewable energy company and holder of the patented Ecoremedy gasification technology. The two firms have established a research agreement for the testing of biomass fuels at Enginuity Energy’s research and development lab in Harrisburg, Pennsylvania. The agreement gives Tri-Mer Corp. access to Enginuity Energy’s Ecoremedy gasification technology, which economically gasifies a wide range of extremely high-moisture and high-ash content material. Enginuity Energy will have access to Tri-Mer’s patented UltraCat catalyst filter system, which removes NOx , acid

FIG. 5. A Tri-Mer UltraCat catalyst filter pilot unit was tested by Enginuity Energy in a series of three burns averaging 40 hours each. Hydrocarbon Processing | FEBRUARY 2013

Innovations to guarantee protection for the plant and personnel in the event of a fire (FIG. 6). AS-Schneider’s monoflanges, VariAS blocks and K-Series ball valves are tested and approved for fire safety as standard. The test bases at AS-Schneider are ISO 10497: Testing of Valves—Fire-Type Testing Requirements and API 607: Fire Test for Quarter-Turn Valves and Values Equipped with Non-Metallic Seats. The type test is monitored and certified at AS-

Schneider by the Technical Inspection Authority TÜV SÜD. The term “fire-safe design” is encountered often. However, this term is no guarantee that the valve will offer safe emergency operation in the event of a fire. Only if the valve undergoes an appropriate type test can it be ensured that the medium will be safely shut off in the event of fire. ISO 10497 defines the requirements and the process for evaluating the func-

Problem Solving Synthetic Lubricants Reduce overheating, oxidation, excessive bearing and mechanical seal wear Improve your pump reliability, extend MTBO*, reduce downtime and energy consumption with Summit Syngear SH®-7000 Series and Barrier Fluid Series. These synthetic lubricants are resistant to rust, oxidation, corrosion and improve wear protection. They have excellent low temperature fluidity and high temperature stability. Summit Syngear SH®-7000 Series and Barrier Fluid Series are compatible with most process fluids being pumped and commonly used seal materials. These PAO based lubricants come in a wide range of viscosities. Summit Barrier Fluids are NSF H1 Registered. *mean time between overhaul

tionality of valves and fittings that are exposed to fire. These requirements are identical to API 607 in terms of content. In this test, the valve to be tested is exposed to fire and to water under pressure for a period of 30 minutes. There are strict specifications for the temperature of the flames and of the valve body that are measured with the help of thermocouples for the entire duration of the fire. After being allowed to burn for a period of 30 minutes, the burners are switched off, and within 10 minutes the valve is force-cooled to below 100°C. The 30-minute burning period corresponds to the maximum period required by the fire brigade to extinguish the fire in a plant. The leakage from the valve seat and the external leakage are measured for the entire duration of the test. The leakages may not exceed a specific limit value. The valve is then tested again to ensure that it is operable. To guarantee the external tightness, only graphite or metallic seal rings are used for stem and body seals. Spring washers ensure guaranteed internal tightness for outside screw and yoke needle valves that compensate for the different length expansion of the individual parts and, therefore, prevent the valve tip from lifting off the valve seat. Concerning ball valves, a secondary metal sealing guarantees the internal tightness. Under normal operating conditions, a polymeric seat provides a bubble tight sealing. In the event of fire, the secondary metal sealing will ensure the tightness instead of the burned polymeric seat. Select 7 at www.HydrocarbonProcessing.com/RS

Summit 9010 CR 2120 Tyler, TX 75707

Industrial Products 800.749.5823 www.klsummit.com

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Made in USA

FIG. 6. AS-Schneider’s ISO FE Series monoflanges are fire-type tested and certified to guarantee protection in the event of a fire.

remoteness loves proximity Gas treatment plants are often located in the loneliest corners of the planet. We at BASF ensure that all plants working with our gas treatment technology run smoothly, regardless of where they are. Under its new OASEÂŽ brand, BASF provides gas treatment solutions consisting of technology, services and products. We at BASF combine the experience of more than 40 years and about 300 distinct references with the latest innovations to provide you with your unique solution. So if going to the ends of the earth results in us being your best neighbor, itâ&#x20AC;&#x2122;s because at BASF we create chemistry. www.oase.basf.com

GAS TREATING EXCELLENCE

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Reliability

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

Top three ways to improve pump service life Experienced reliability professionals know that even the premier equipment standards used in the hydrocarbon processing industry (HPI) occasionally fall short of defining the best, most reliable, or safest available technology. A widely used industry standard begins by stating: “The purchaser may desire to modify, delete or amplify sections of this standard.” The preface to another standard is worded: “Standards are not intended to inhibit purchasers or producers from purchasing or producing products made to specifications other than this one.” In a third location, a well-known industry standards organization expressly declines any liability or responsibility for loss or damage resulting from the use of its standards, or for the violation of any regulation with which the standards publication may conflict. Know about better bearings. For rea-

sons of standardization and overall practicality, pump standards allude to thrust bearing sets comprising two mirror-image, mounted, 40°, angular contact bearings oriented back-to-back. In most cases, with adequate lubrication, these paired bearings will not be a problem. At high loads, however, one of the two bearings may skid, as shown by the skidding bearing in FIG. 1. It will usually overheat and cause premature bearing failure. The corrective action may be installing an upgrade set of angular contact bearings, ones with unequal contact angles, in problem pumps. Superior bearing housing protector seals can be a surprise. Although

buying in accordance with proven industry standards is recommended, many clauses in these standards deserve clarifying statements. Bearing housing protector seals are an excellent example. A good bearing protector seal is a must.1 But here are three caveats users should know: • If the pump manufacturer has provided a bearing housing design with bal-

ance holes that equalize the pressures on one side of a set of angular contact (“AC”) bearings relative to the other side of an AC bearing set, then there will not be a problem when bearing protector seals are being retrofitted. • If the pump manufacturer has omitted these internal balance passages, then oil may properly reach all bearing elements as long as the design incorporates an old-style or conventional wide-open labyrinth housing seal. We often call unidirectional air flow “windage.” It may become a factor and the bearing protector seal often gets blamed, although the problem could have originated with the omission of housing-internal balance holes.1 • Many repeat bearing failures on poorly designed pumps have occurred due to the listed reasons. The appropriate course of action is to consider all factors, study pertinent references and ensure that there are internal pressure balance provisions and other reliability-improving steps. Once these pump improvement steps are confirmed, it is highly recommended to add modern bearing protector seals and to steer clear of the risky ones.1 Insist on safest possible mechanical seal test protocols. Not all mechanical

seal manufacturers apply the same acceptance test procedure for their products. A widely used industry standard stipulates air as the gas for mechanical seal tightness testing. Of course, these seals are ultimately intended for the safe containment of flammable, toxic or otherwise hazardous liquids. While the standard’s expectation is that leakage from seals in critical services does not exceed 5.6 g/hr, it can actually allow orders of magnitude (exceeding 1,000 g/hr) of dangerous liquid to escape from a seal that has just passed the airleakage test. It is, therefore, advisable to question seal vendors on the matter and to purchase only products that meet the purchaser’s well-reasoned safety and reliability requirements.

FIG. 1. Back-to-back oriented bearings; skidding simulated on left. Source: SKF America, Kulpsville, Pennsylvania.

Ascertain safety and reliability. Fortunately, many reputable reliability professionals are very diligent on equipment safety and reliability issues. They insist on seals leaking no more than 5.6 g/hr of liquid when first installed and on pumps with bearing sets that will not skid. Finally, they will review, specify and inspect bearing housing internals for avoidable risks. 1

LITERATURE CITED Bloch, H. P., Pump Wisdom, John Wiley & Sons, Hoboken, New Jersey, 2011.

HEINZ P. BLOCH resides in Westminster, Colorado. His professional career began in 1962 and included long-term assignments as Exxon Chemical’s regional machinery specialist for the US. He has authored over 520 publications, among them 18 comprehensive books on practical machinery management, failure analysis, failure avoidance, compressors, steam turbines, pumps, oil-mist lubrication and practical lubrication for industry. Mr. Bloch holds BS and MS degrees in mechanical engineering. He is an ASME Life Fellow and maintains registration as a Professional Engineer in New Jersey and Texas. Hydrocarbon Processing | FEBRUARY 2013

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Integration Strategies

PAUL MILLER, CONTRIBUTING EDITOR PMiller@arcweb.com

US biodiesel industry regains momentum According to the National Biodiesel Board (NBB) trade organization, the US biodiesel industry produced more than one billion gallons (B gal) of biodiesel fuel in 2011, surpassing the 800 million gallon target established for the year under the US Environmental Protection Agency’s Renewal Fuel Standard (RFS). While this is less than 1% of the total US diesel production, it is a significant volume for a new industry. Experts agree that this record-breaking 2011 production was largely due to the EPA having reinstated the earlier $1/gal tax credit for biodiesel in December 2010. This followed a disastrous 2010, in which the lack of the tax credit resulted in dramatic cuts in production, investment and employment in the biodiesel industry—yet, the industry persevered in 2012. However, 2013 should bode well for the biodiesel industry. In early August 2012, the Senate Finance Committee approved a package extending the biodiesel production tax credit through 2013. In addition, on Sept. 14, 2012, the EPA further increased the 2013 biodiesel volume requirements for biomass-based diesel under the RFS to 1.28 B gal. These actions would appear to position biodiesel for continued growth, at least through the end of 2013. Encouraged by a favorable environment at both the federal and state levels, several companies have announced plans to expand biodiesel production capacities and/or distribution infrastructure. Biodiesel in the US. The EPA is responsible for developing and implementing regulations to ensure that domestically consumed transportation fuels contain a minimum volume of renewable fuel. The RFS created under the US Energy Policy Act of 2005 established the first mandates for renewable fuels. Significantly, the initial RFS applied only to gasoline, not diesel. However, the Energy Independence and Security Act (EISA) of 2007 expanded the RFS program (now referred to as “RFS2”) to include diesel. EISA also increased the required volume of renewable fuel to be blended into transportation fuel (both gasoline and diesel) from 9 B gal in 2008, to 36 B gal by 2022. Pure biodiesel, or “B100,” is typically consumed as a blend with conventional or ultra-low-sulfur diesel (ULSD). Reacting to widespread criticism that the earlier, ethanolfocused program did not result in a net positive effect on greenhouse gas (GHG) emissions, EISA also required the EPA to apply lifecycle GHG performance threshold standards to ensure that each renewable fuel category results in fewer net GHG emissions than the petroleum-based product it replaces. While well-intentioned, the lifecycle GHG threshold standards create additional hurdles for renewable producers, who now have to perform and pay for extensive studies to determine and document net GHG emissions for their new products and processes, it also stifles innovation to a certain degree. Never-

theless, funded in part by US Department of Energy grants, companies continue to develop and commercialize new biodiesel processes. Expanding the biodiesel infrastructure. In September

2012, the EPA announced that it had increased the biodiesel volume requirements under the RFS by 28%, from 1 B gal for 2012 to 1.28 B gal for 2013. According to an NBB news release, while this represents a modest increase over the industry’s 2011 record production of 1.1 B gal, it puts the industry on course for steady, sustainable growth in the coming years. New biodiesel facilities, particularly in the US Midwest, are unlikely, as the majority of the existing plants are located in this region to take advantage of the domestic soybean crop. However, several companies have constructed new plants on both the East Coast and West Coast to serve local markets. The infrastructure required to store and distribute biodiesel still has growth potential and ARC Advisory Group has observed related activities in 2012. Many appear to be based on the anticipation that the government would sustain or increase the biodiesel mandates in the coming year, as well as individual state mandates for greater biofuel use. While these projects are small scale, many are significant. In March 2012, Motiva announced a project to convert existing storage at its Sewaren Terminal in New Jersey to both ULSD and B100 biodiesel storage and to improve associated rail logistics. These investments will enable the terminal to readily supply multiple blends of biodiesel (including ULSD/B100 blends) for shipment to New York State assisting in a new mandate required use of ultra-low-sulfur heating oil. In July 2012, New York-based Ultra Green Energy Services announced the opening of biodiesel operations at the Brookhaven Rail Terminal in New York. This project was also stimulated by the New York State low-sulfur heating oil mandate. In September 2012, Magellan Midstream Partners celebrated the opening of a new $2.5 million biodiesel storage and loading facility at the company’s large Clear Lake Terminal in Des Moines, Iowa. This new facility will help Iowa’s 14 biodiesel production refineries supply truck stops and other fuel retailers throughout the Midwest. PAUL MILLER is a senior editor/analyst at ARC Advisory Group and has 25 years of experience in the industrial automation industry. He has published numerous articles in industry trade publications. Mr. Miller follows both the terminal automation and water/wastewater sectors for ARC.

Hydrocarbon Processing | FEBRUARY 2013

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Boxscore Construction Analysis

LEE NICHOLS, DIRECTOR, DATA DIVISION Lee.Nichols@GulfPub.com

2013 global construction outlook According to Hydrocarbon Processing’s HPI Market Data 2013, total capital spending is estimated to exceed $57 billion (B) in 2013. This amount includes investments in the development and construction of grassroots facilities, along with upgrades to existing HPI facilities to meet growing global demand. The International Energy Agency (IEA) forecasts that global oil demand will reach 95.7 million barrels per day (MMbpd) by 2017. Over the same time frame, global refining capacity could rise to 100 MMbpd. With so much construction activity forecast around the world, there are several major construction trends and regions to watch. This month’s column discusses a number of these trends and projects. For more information, please view the 2013 Market Outlook Webcast at www.HydrocarbonProcessing.com. Asia-Pacific. This region dominates in

total active projects, as shown in FIG. 1. The Asia-Pacific region is led by refining and petrochemical construction projects located in China and India. Downstream construction activity in China and India collectively accounts for 18% of total active projects. Over the next five years, China will contribute 40% of the global refining capacity expansion with nearly 20 new refineries that are under construction. The nation is presently ranked second in the world in refining capacity, accounting for 10.8 MMbpd. PetroChina, a subsidiary of state-owned China National Petroleum Corp., and Venezuelan national oil company PdVSA will construct a $9.7 B, 400,000-barrel-per-day (Mbpd) refinery in China’s Guangdong Province. Also within Guangdong Province, Sinopec and Kuwait Petroleum plan to construct a 300-Mbpd refinery. The $9 B joint-venture project will also include a 1 million-ton-per-year (MMtpy) ethylene complex. China’s petrochemical sector continues to surge, with new construction

by 2015. These include import facilities in Dabhol, Kochi and Mundra. Australia’s primary focus is on large gas projects such as Gorgon, Prelude, Wheatstone, Ichthys, Queensland Curtis LNG, Gladstone LNG and Australia Pacific LNG. Almost 20 LNG export terminals are either planned or under construction, with estimated completion by 2017. This development has put Australia on track to overtake Qatar as the world’s leading LNG exporter by the end of the decade. Indonesia is investing over $15 B in new refinery construction and upgrading projects at Balongan, Cilacap, Cilegon and Tuban. Pertamina, Indonesia’s stateowned oil company, is partnering with several foreign firms on these projects, which will collectively increase Indonesia’s refining capacity by nearly 1 MMbpd by 2014. PetroVietnam, in cooperation with Idemitsu Kosan, Kuwait Petroleum and Mitsui Chemicals, will construct Vietnam’s second refinery. The 200-Mbpd Nghi Son refinery has an estimated cost of $8 B to $10 B. Refinery operations are set to begin in 2014. Additionally, Thailand’s PTT is planning to construct a $28.7 B, 660-Mbpd refinery in central Vietnam. The mega-project includes the construction of a petrochemical facility with a 3.7-MMtpy aromatics plant and a 6.5-MMtpy olefins complex.

at petrochemical complexes in Chongqing, Liaoyang, Nanjing, Shaanxi, Taizhou and Zhanjiang. India has 20 major refineries in operation with a total capacity of 194 MMtpy. According to proposed projects in HP’s Construction Boxscore Database, India will add 1.3 MMbpd of refining capacity through 2017. Leading the charge is Indian Oil Co., which announced plans to expand throughput at the Haldia, Koyali, Panipat and Paradip refineries. These expansion projects will almost double Indian Oil’s refining capacity to 2.5 MMbpd by 2022. Bharat Petroleum Corp. Ltd. (BPCL), Reliance Industries and Hindustan Petroleum Corp. Ltd. (HPCL) also have announced expansion plans for refineries at Kochi, Jamnagar and Visakhapatnam. The total cost of this construction wave will top $15 B. According to India’s 12th five-year plan, natural gas demand should triple by 2017. To meet growing demand for natural gas, India is planning several liquefied natural gas (LNG) regasification terminals along its west coast. Major expansion projects, such as Shell and Total’s Hazira LNG terminal and Petronet LNG’s Dahej terminal, will increase capacity at these facilities by 5 MMtpy each. HP’s Construction Boxscore Database lists several other LNG regasification projects that will raise India’s LNG import capacity by 40 MMtpy 400

Reﬁning Petrochemical Gas processing

350 300 250 200 150 100 50 0 Africa

Asia-Paciﬁc

Canada

Europe

Latin America Middle East United States

FIG. 1. Total active projects by region and sector. Hydrocarbon Processing | FEBRUARY 2013

Boxscore Construction Analysis United States. In the US, the down-

stream construction sector is benefitting from the recent boom in shale gas production. The US market share for new projects increased from 8% in 2010 to 20% in 2012, which is on par with the Middle East. The two countries rank second behind the Asia-Pacific region, which accounts for 30% of total new projects in 2012. US companies aim to construct over 190 MMtpy of LNG export capacity over

the next several years; more than a dozen LNG export facilities are awaiting approval from the US Department of Energy. This LNG construction boom could propel the US to become a dominant LNGexporting powerhouse within 10 years. Cheap ethane feedstocks are fueling additional project activity for natural gas liquids (NGLs), fractionators, ethylene crackers and petrochemical infrastructure construction, primarily along the US Gulf

Integrated Flare System Services Reducing CapEx in revamp and expansion projects by applying inprocess and Softbits proven methodology based on their flare systems and process modeling expertise Analysis of Pressure Relief Devices • • • •

Contingencies analysis for emergency scenarios Loads calculation by SS and Dyn Simulation Relief devices (re-)sizing according to API Standard PSV database creation/consolidation

Flare Header Design & Operational Analysis • • • • •

Validation of existing flare header Header hydraulics behavior Temperature profiles Dynamic analysis of peak loads simultaneity Time duration of constraints violations

Flare Radiation Analysis • • • •

Multiple flare in multiple stacks Shielding with water curtains or physical barriers Sterile Area definition Dynamic radiation and temperature prediction

inprocess Technology and Consulting Group, S.L. Gran Via de Carles III, 86 - Torre Est, 9è-1a • 08028 Barcelona. Spain • Tel: +34 933 308 205 Fax: +34 933 308 206 • email: info@inprocessgroup.com • Web: www.inprocessgroup.com

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Coast. Over 3.5 MMtpy of new cracker capacity is planned to come online by 2017; the largest new unit is Chevron Phillips Chemical’s 1.5-MMtpy ethylene cracker in Baytown, Texas. Other petrochemical product producers such as Dow Chemical, Equistar, Formosa, INEOS, LyondellBasell, Sasol and Shell have expressed plans to build new capacity over the next few years. Latin America. In Latin America, nearly 1.7 MMbpd of new refining capacity is planned by 2017. To capitalize on newly discovered oil reserves, Brazil is gearing up for a new wave of refining capacity construction. In its 2012–2016 investment plan, Brazilian state-owned oil company Petrobras forecasts investment of $71.6 B in the downstream sector. Although delays and higher costs have posed challenges, construction of the Abreu e Lima, Comperj, Premium 1 and Premium 2 refineries are still expected to add 1.3 MMbpd of new refining capacity in Brazil. The Comperj project includes construction of the Rio de Janeiro Petrochemical Complex, which will produce a multitude of petrochemical products such as styrene, ethylene glycol, polyethylene (PE), polypropylene (PP), purified terephthalic acid and polyethylene terephthalate. New refining and petrochemical construction is also planned for Argentina, Ecuador, Mexico and Venezuela. Ecuador’s state-owned oil company, Petroecuador, in consortium with Venezuela’s PdVSA, plans to build the 300-Mbpd Refineria del Pacifico near Manta, Ecuador. The $13 B refinery and petrochemical complex is expected to be online by 2016. PdVSA is also building the Batalla Santa Ines refinery in Barinas, Venezuela. The 60-Mbpd hydroskimming refinery should be operational by 2015. Additionally, Argentina’s state-owned oil company, YPF, plans to construct a $7 B, 300-Mbpd refinery in Bahía Blanca, Argentina by 2017. Peruvian company Petroperu is planning a $1.7 B expansion and upgrade to the existing Talara refinery in Talara, Peru. This project will enable the refinery to process heavier crude and meet low-sulfur fuel specifications. It will also expand the refinery’s capacity from 65 Mbpd to 95 Mbpd. Mexico’s state-owned oil company, Pemex, is constructing a greenfield refinery at Tula, as well as a new petrochemical complex in Coatzacoalcos, a city in the Mexican state of Veracruz. The Tula refinery

Boxscore Construction Analysis project will expand Mexico’s total refining capacity by 300 Mbpd at an estimated cost of $10 B. Completion is set for 2015. Pemex has also awarded contracts for its latest project, Etileno XXI, a $3 B petrochemical complex in Coatzacoalcos. ICA Fluor, Odebrecht and Technip will design and build the Etileno XXI plant. The project includes a 1-MMtpy ethylene cracker, two high-density PE plants utilizing INEOS Innovene technology, a low-density PE plant utilizing BASEL Lupotech technology, as well as storage, waste-treatment and utility facilities. Europe. Nearly 65% of new project construction in this region is centered in Eastern Europe and the Russian Federation. In 2012, the Russian Federation accounted for 45% of new project activity in Europe. Lukoil announced plans to increase automotive gasoline production with modernization projects at the Nizhny Novgorod and Perm refineries. Lukoil is building an $805 MM catalytic cracking complex at the Kstovo refinery, with tentative plans to construct a

$3 B hydrocracking complex at Kstovo by 2018. Russia is also developing its natural gas resources with the Vladivostok LNG, Yamal LNG and Pechora LNG projects. These projects, with a collective value of more than $20 B, will increase Russia’s LNG capacity by over 30 MMtpy. Canada. Most of the downstream construction in Canada is focused on refining heavy crude from Canadian oil sands. North West Upgrading and Canadian Natural Resources have decided to construct a new bitumen refinery in Alberta. The Sturgeon refinery project is a $5.7 B venture with a planned capacity of 150 Mbpd. The facility will also capture 1.2 MMtpy of carbon dioxide, which will be sold to oil companies for use in enhanced oil recovery operations. Due to the recent shale gas boom, the US no longer needs to import excess natural gas from Canada. To offset this financial hit, Canada has planned a number of LNG liquefaction terminals to export LNG to Asian markets. These LNG export facilities are located primarily on

the Pacific Coast in British Columbia. Three projects located in Kitimat, British Columbia are Apache, and Chevron Canada Ltd.'s $15 B Kitimat LNG project; Shell Canada, Korea Gas Corp. (KOGAS), Mitsubishi Corp. and PetroChina’s 12-MMtpy LNG Canada project; and the Haisla Nation and LNG Partners LLC’s 1.8-MMtpy LNG project. Petronas and Progress Energy are also planning the $9 B to $11 B Pacific Northwest LNG project on Lulu Island, British Columbia. The project will include two LNG trains, each with a capacity of 3.8 MMtpy. Expectations for this project include expanding capacity at each train to 6 MMtpy over the near term. Africa. The most notable project is the

Lagos greenfield refinery project. The plan is a consortium between Nigerian National Petroleum Corp. (NNPC) and China State Construction Engineering Corp. (CSCEC); it involves the construction of three greenfield refineries in Lagos (including a petrochemical plant), Bayelsa and Kogi states at a total cost of $28.5 B.

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Boxscore Construction Analysis To prevent a fuel shortage, South African national oil company PetroSA plans to build Africa’s largest refinery. Project Mthombo is a $10 B, 360-Mbpd refinery that will be constructed in the Coega Industrial Development Zone. It will be the first refinery on the continent to produce Euro 5-specification transportation fuels. Middle East. The Middle East is the fo-

cus of a significant number of downstream construction projects. New refining capacity will focus on domestic demand and export opportunities to China and Europe. Major construction projects are led by four major expansions at Saudi Aramco’s Jazan, Jubail, Ras Tanura and Yanbu refineries. These projects will add 1.6 MMbpd of refined products to the global market. Kuwait’s national oil company, Kuwait National Petroleum Co. (KNPC), has announced $40.5 B in new project construction. The Clean Fuels Project is a

$31 B upgrade to KNPC’s Mina Abdullah and Mina Al-Ahmadi refineries; daily throughput will be increased to nearly 800 Mbpd. KNPC is also looking to invest $14.5 B in the construction of the Middle East’s largest refinery. The 615Mbpd Al-Zour refinery should be operational by 2018 and is anticipated to cost $14.5 B. Qatar, meanwhile, will soon embark on the second phase of the Ras Laffan condensate refinery expansion project. The $1 B expansion is scheduled for completion by 2016. Likewise, Abu Dhabi Oil Refining Co. (Takreer) will invest $10 B to expand its Ruwais refinery in the UAE by 417 Mbpd. This expansion will boost Takreer’s overall refining capacity to nearly 1 MMbpd. Iran, the second-biggest petrochemical producer in the Middle East after Saudi Arabia, has announced $80 B of investment in its petrochemical sector.

Nine petrochemical projects will be implemented over the next year, boosting the country’s output by 8 MMtpy. Non-OECD countries will continue to be the driving force for additional capacity construction. The downstream industry is investing billions of dollars in the development and construction of grassroots facilities, along with expansions and upgrades to existing HPI facilities. LEE NICHOLS is Director of Gulf Publishing Company’s Data Division. He has five years of experience in the downstream industry and is responsible for market research and trends analysis for the global downstream construction sector. At present, he manages all data content and sales for Hydrocarbon Processing Construction Boxscore Database, as well as all corporate and global site licenses to World Oil and Hydrocarbon Processing.

Detailed and up-to-date information for active construction projects in the refining, gas processing, and petrochemical industries across the globe | ConstructionBoxscore.com

26 FEBRUARY 2013 | HydrocarbonProcessing.com

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Sulzer Chemtech

Sulzer Technologies for Biofuel Applications

Background In recent years, there have been many advancements in the development of biofuels for the global transportation markets. First generation fuel ethanol plants performed fermentation of grains into high purity ethanol. Further R&D led to the development of biofuels from renewable feed stocks: grains, baggase, switch grass, sugar cane, beets, turnips and wood pulp. These second generation biofuel processes produce high purity methanol, propanol, butanol and other oxygenated hydrocarbons for this emerging market. The development of biofuels has included new technologies for mechanical and thermal processing of biomass, fermentation, and chemical separation processes.

Process Technology Sulzer offers several technologies for second generation biofuels. Our process design experience includes pressure swing, azeotropic and extractive distillation to separate alcohols from aqueous feed streams. Membranes can be used to perform dehydration and overcome azeotropes to produce high purity alcohol products. The combination of these technologies leads to signiﬁcantly lower energy demands. Our test center can verify the capabilities of novel processes with pilot plant studies that can then be applied to scale-up to demonstration and industrial plants. Process plant equipment can be delivered as skid-based solutions that include distillation columns and other process equipment, piping and controls.

Membrane Module and Skid Mounted Column

Mass Transfer Equipment Sulzer’s product portfolio has been successfully used in biofuel applications for many years. In ﬁrst generation fuel ethanol plants, VG AF™ trays have a proven track record of resisting fouling by biomash solids and extending the plants’ operating time. MellapakPlus™ structured packing offers low pressure drop and high capacity for distillation and absorption columns. The Kühni extraction column with its rotating agitation chambers is applied in liquidliquid extraction applications. Vapor permeation with zeolite membranes is most suitable for bioethanol processes. These membranes can be incorporated into hybrid distillation systems used to dehydrate biofuels.

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DR. RAJEEV GAUTAM

Viewpoint

President and CEO, UOP, A Honeywell Co.

Interview with UOP Hydrocarbon Processing had the opportunity to meet with Dr. Rajeev Gautam, president and CEO of UOP, A Honeywell Co., and discuss several high-level factors impacting the global hydrocarbon processing industry and technology development and licensing. HP. What is UOP’s viewpoint regard-

DR. RAJEEV GAUTAM serves as president and chief executive officer of Honeywell’s UOP, a strategic business unit of Honeywell Performance Materials and Technologies. Honeywell’s UOP is a leading international supplier of process technology, catalysts, engineered systems, and technical and engineering services to the petroleum refining, petrochemical, chemical and gas processing industries. Before being named to his present post, Dr. Gautam served as vice president and chief technology officer of Honeywell Performance Materials and Technologies. During the last 30 years, he has held key positions within UOP, spanning research and development, engineering, and marketing, including vice president and chief technology officer of UOP; director of the Process Technology and Equipment business; technology director for Platforming and Isomerization Technologies; product line manager for the Aromatic Derivatives business; senior manager of Adsorption Technology; and manager of Molecular Sieve Process Technology. Dr. Gautam began his career with Union Carbide in 1978, which became part of a joint venture with UOP in 1988. Throughout his career, he has championed innovative solutions for industry needs and has been responsible for the development and commercialization of a broad range of catalytic and separations applications for the refining, petrochemical and gas processing industries. Dr. Gautam earned a BS degree in chemical engineering from the Indian Institute of Technology and an MS degree in chemical engineering from Drexel University. Additionally, he holds a PhD in chemical engineering from the University of Pennsylvania and an MBA from the University of Chicago.

ing natural gas for the petrochemical industry and other industry segments? What are the areas of opportunity in shale gas for the US and elsewhere? RG. Many believe that we have entered the golden age of gas. Not too long ago, natural gas was merely a byproduct of producing crude oil in some parts of the world and was often flared off at the wellsite. Other regions were reducing natural gas consumption because production was declining. Technological advancements that enable the economical development of shale, offshore and lower-quality gas resources have been a game changer. Today, natural gas is widely projected to become the world’s fastest-growing fossil fuel energy source, with applications across many industries, including refining, petrochemicals, transportation and power. Global gas resources are estimated to have the potential to provide 250 years of supply worldwide. In the US, nearly half of the natural gas supply over the next 20–25 years may come from shale gas. In North America, the same production processes developed for shale gas are being applied to produce light crude from tight shale, yielding some changes to the product mix and creating the need for new technology to rebalance the mix, as well as to produce high-value-added petrochemicals from these hydrocarbons. But additional innovations in technology will be required for the potential to be met in other regions. The world still flares about 5% of the natural gas produced. To reduce this percentage, the cost options of getting

associated gas to market need to be lowered. The technologies used to efficiently extract shale gas in North America will need tailoring in other regions faced with tough geological and logistical challenges and limitations on water supplies required for hydraulic fracturing. Some offshore and lower-quality gas resources will remain stranded until lower-cost options enable their development. China has the world’s largest shale gas potential, so we can expect to see a shift away from coal toward natural gas feedstocks for power, to some degree, if this potential is realized. The Middle East will strive to increase its production to meet growing demand, and Latin America will incorporate natural gas into its fuel mix as a lower-cost option for power generation. Natural gas has become a prominent energy source not only because of its abundance, but also because it is a lowcost feedstock that emits fewer pollutants and less carbon dioxide than other fossil-fuel energy sources, including coal and crude oil. In many ways, using natural gas supports global trends and directives to use cleaner fuels. However, the production cost of unconventional and sub-quality conventional resources in China, Eastern Europe, the Middle East and many other regions is still double or triple that of North American shale gas and technology. Global demand for petrochemicals derived from hydrocarbons, such as propylene, is rising due to population growth. UOP’s Oleflex and Methanol-to-Olefins (MTO) processes produce on-purpose propylene and ethylene from low-cost feedstocks, such as natural gas liquids or coal, to help meet this increased demand. The world is shifting from large, centralized processing of clean, conventionally produced natural gas to smaller-scale, distributed production of gas with more processing challenges. Our new UOP Russell product line offers modularized packaged plants that enable producers of Hydrocarbon Processing | FEBRUARY 2013

Viewpoint conventional and unconventional gas to remove contaminants and recover highvalue natural gas liquids (NGLs) used for petrochemicals and fuels, monetizing natural gas resources for our customers worldwide. There is no “one-size-fitsall” solution for managing hydrocarbons from wet shale gas and shale oil resources. As a result, an agile portfolio of solutions is required. Packaged solutions deliver faster onstream time, lower installed cost, highest feed gas flexibility and the ability to relocate plants as processing requirements change because of their modular construction. HP. What is UOP’s viewpoint for the

global hydrocarbon processing industry for the next 10 to 20 years? Where are the growth opportunities? RG. The mix of hydrocarbon feeds is changing. Declining conventional crude production and the need for regional energy independence will continue to drive demand to use lower-cost, alternate feedstocks such as coal, shale oil and heavy crude. To use alternate feedstocks in existing refineries, many processes will need to be modified. The increase in diesel demand and stricter fuel specifications will cause refiners to look for ways to produce higher yields from existing assets. There will be an increase in residue conversion; hydrocracking will evolve as a primary conversion process; and hydrotreating will increase as a way to treat virgin and cracked middle distillate streams. Developing technology that enables the use of cost-advantaged, abundant feedstocks for power, transportation and chemicals production will continue to be of high priority over the next few decades. An agile portfolio of solutions will also be required to optimize gas treating and cleanup. New sources of gas—including coalbed methane; tight gas; shale gas; associated gas from shale oil; biogas; synthetic natural gas (SNG) from coal gasification; and lower-quality, previously stranded conventional gas—vary widely in terms of the levels of contaminants and heavier, valuable NGLs. The desired product gas quality also varies, depending on whether the gas will be transported by pipeline, converted into liquefied natural gas (LNG) or used locally. Gas resources are often located in remote regions challenged by limited water, infra-

30 FEBRUARY 2013 | HydrocarbonProcessing.com

structure and other logistical challenges requiring innovative solutions. These factors increase the complexity of the gas value chain and put new demands on gas transport infrastructure. The role of technological innovation to meet these challenges with economic and environmentally sustainable solutions continues. HP. UOP began as a refining technol-

ogy licensor. What new developments is UOP currently researching? RG. As a technology licensor for nearly 100 years, UOP has always been at the forefront of innovation for the refining industry. Moving forward, we will continue to enhance our technology developments in refining, which will be oriented toward the changing product mix and changing feeds to produce highdemand materials. This will require the modification of many existing processing steps, as well as the development of new, breakthrough technology. In addition to being a leading technology supplier for the refining and petrochemicals industry, we’ve also become prominent in the gas processing industry, with a full suite of solutions to address single-unit operations, along with highly integrated, multiple-technology operations. To help meet worldwide demand for lower emissions and cleaner-burning transportation fuels, we expanded our portfolio with a business dedicated to renewable technologies and have developed landmark renewable transportation fuel processes. Looking ahead, we will focus on developing technologies that are highly efficient, use cost-advantaged resources and provide environmental benefits.

HP. How does the MTO process fit

into the global petrochemical industry? What are the advantages with the MTO for licensees? RG. MTO provides a profitable, lowcash cost of production pathway to light olefins compared to traditional naphthabased steam cracking. MTO also provides product slate flexibility between ethylene and propylene to most effectively address market demands and maximize profitability. UOP has announced three MTO projects in China, where MTO is now commercially proven. The application of MTO in locations outside of China, with access to cost-advantaged natural gas or coal, is expected in the coming years.

UOP’s advanced MTO process allows petrochemical producers to tap into abundant and low-cost feedstocks to produce high yields of valuable petrochemical building blocks at lower cash cost of production than conventional routes. The MTO process converts methanol derived from noncrude-oil sources, such as coal or natural gas, to ethylene and propylene. The process, based on proprietary UOP catalysts, is proven to provide high olefin yields with minimal byproducts. MTO also offers flexibility in the quantity of propylene and ethylene produced, so producers can adjust plant operations to most effectively address market demands. HP. What challenges must refiners address in the near term? RG. As the global economy continues to grow, demand for oil-derived transportation fuels, lubricants and petrochemicals rises. Diesel, in particular, is in high demand. Refiners will need to find ways to efficiently maximize finished products from each barrel of oil and to upgrade the value of their products by increasing petrochemicals production. Although much attention has been focused on the increase in light sweet crude production, heavy crude production will also continue to grow, and demand for low-value residual fuels and petcoke will decline. Refining challenges differ depending on the region. In the US, refiners are looking to efficiently process shale oil, which is much lighter, and to take advantage of low-cost feedstock to produce high-value petrochemicals for domestic markets and for export. In other regions, such as India and China, better technologies are needed to reduce petcoke and residual fuel oils. UOP’s newest residue upgrading technology, the Uniflex process, achieves a maximum conversion of 90% at a modest cost, producing an attractive feedstock for high-quality diesel production. UOP’s Oleflex process produces on-purpose propylene from propane with the lowest cash cost of production and the highest return on investment, allowing refiners to participate in the growing propylene market. HP. What are the major refining devel-

opments for “green” fuels? RG. There will always be new, more efficient alternative energy resources on the horizon, and it is our goal to identify

Viewpoint these renewable resources to develop fuels and chemicals that will support growing energy needs globally, while also addressing environmental concerns. A significant achievement was the development of our technology to produce jet fuel from renewable resources. Our Renewable Jet Fuel Process converts a range of natural oils and animal fats to Honeywell Green Jet Fuel, which, when used as part of up to a 50% blend with traditional jet fuel, requires no changes to the aircraft technology or fuel infrastructure. We’ve also used nonedible, secondgeneration oils, animal fats, green algae, forest residuals and other biomass to produce Honeywell Green Diesel. This fuel is chemically identical to petroleumderived diesel, and can be used as a dropin replacement for traditional diesel. The first commercial facility using our UOP/ Eni Ecofining Process will come online in 2013, providing nearly 300 million gallons of Honeywell Green Diesel to supply sustainable, low-emissions diesel throughout the US and Europe. While we’ve seen great success with these developments, we continue to work toward new solutions for renewable transportation fuels. In 2013, our Rapid Thermal Processing (RTP) technology will be used to upgrade forest residuals, algae and other cellulosic biomass feedstocks into renewable diesel, gasoline and jet fuel. As biofeedstocks become more readily and economically available, and producers become more incentivized to make renewable fuels, we expect the use of renewable technologies to increase over time. As usage rises, UOP is wellpositioned to meet demand. HP. For what upcoming challenges is

UOP directing R&D efforts? RG. Over the next decade, diesel and middle distillate consumption will represent the primary driver for oil consumption growth. Sulfur content in diesel fuels will continue to drop, and gasoline-to-diesel ratios will decline in established markets. UOP is continuing to develop technologies to address these shifts in product demand. We are working on new hydroprocessing technologies and catalysts that will give higher diesel yields and improved cetane index. Refineries that use fluid catalytic cracking (FCC) technology are looking to increase light-cycle oil (LCO) quality

and petrochemicals yields, and we are working on maximum-diesel and propylene FCC designs with flexibility to also produce aromatics. Renewable fuels continue to be an important way for refiners to respond to pressure on carbon emissions, and we are looking forward to the startup of our first commercial-scale plants for making drop-in green diesel and green jet biofuels. We will also continue to focus R&D efforts on petrochemicals. Demand for polyester, plastics and detergents is on the rise, especially in developing economies. New, low-cost feedstocks are entering the supply picture, offering an opportunity for new petrochemical players to enter the market. We are working on refining and petrochemical integration strategies to exploit these low-cost feedstocks to make high-value petrochemicals. For example, we have made improvements in our Oleflex process for light paraffin dehydrogenation to increase the yield of propylene and butenes, and we are working to extend this product line to other high-value olefins. We are also working

on new catalysts and processes to further increase the efficiency of fuel and petrochemicals production. The natural gas sector is evolving rapidly in North America, and, through our acquisition of Thomas Russell, we have become a significant player in NGLs recovery. We are looking at improved techniques for gas treating and contaminant removal to ensure that the gas can be cleaned up to pipeline or LNG specifications. Our Separex membranes are also seeing more use in rejecting carbon dioxide from natural gas, and we are working on the next generation of membranes with higher flux and methane selectivity. We believe gas will be a game-changer for the US petrochemicals industry, and we are looking at several new processes for making chemicals from methane and NGLs. We are proud of the progress we’ve made toward the development of industry-leading technologies that are changing the way the world thinks about and consumes energy, and we are committed to continuing our efforts in that direction.

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Show Preview

Eastern Mediterranean Gas Conference A. BLUME, Process Editor

Discover what opportunities the Eastern Mediterranean holds for you April 8–10, 2013 Hilton Cyprus Nicosia, Cyprus • Inaugural EMGC features more than 40 top-level executive, governmental and academic speakers and representatives • Two days of commercial and technical presentations, panel debates, networking opportunities and openingnight gala dinner • “Doing Business in the Mediterranean” pre-conference workshop held in conjunction with Cyprus Investment Promotion Agency • Only conference in the region hosted by Noble Energy, the Eastern Mediterranean’s largest gas and oil reserves holder and producer • Other sponsors include top companies involved in the region, such as Hyperion Systems Engineering, Deloitte, KBR, Technip, ConocoPhillips, ABS and others www.EMGasConference.com

Eastern Mediterranean Gas Conference (EMGC) 2013 is the comprehen-

sive, breakthrough meeting for professionals working in, and seeking to be involved in, the large, recently discovered offshore gas reserves in the Eastern Mediterranean. This inaugural event, scheduled to take place April 8–10, 2013, at the Hilton Cyprus in Nicosia, Cyprus, is devoted to the discussion of the commercial and technical aspects of producing, processing and distributing these gas reserves. Within the global fuel mix, natural gas is gaining traction at the expense of oil and coal, especially as the development of new offshore and unconventional gas resources ramps up, and as nuclear power and renewable fuels come under scrutiny. The Eastern Mediterranean region, where an estimated 35 Tcf of recoverable natural gas reserves have been discovered, could provide a steady, stable source of gas to local users and to many European countries that are presently limited in their gas supply sources. Liquefied natural gas (LNG) production and transport is a viable option for these reserves, and plans have been proposed for a liquefaction plant on the island of Cyprus. Once Cyprus is able to establish successful operations in the region, such progress is expected to spark additional oil and gas exploration and production across the Eastern Mediterranean. With such large amounts of resource expected to come online in the next few years, the natural gas supply landscape in Europe will undoubtedly change. In addition to Cyprus, Israel, Egypt, Lebanon and Turkey, the area poised to benefit most from natural gas production in the Eastern Mediterranean is the EU. With 27 member countries representing an estimated population of 503 million, the

EU stands to gain increased natural gas resource security through Eastern Mediterranean production gains. Pipelines and liquefaction terminals originating in the Eastern Mediterranean have the potential to serve many EU countries, while future export capabilities could serve buyers around the world, including those across Asia. Conference program. EMGC 2013

will give special focus to the latest market and technology trends related to the exploration, drilling, production, processing and marketing of natural gas in the area. The conference will cover such critical issues as resource potential, leasing and permitting, development plans, infrastructure requirements, government plans and regulations, and more. EMGC will provide an exclusive opportunity to learn more about the companies and technologies behind the planning and development of this important region’s natural gas industry. With approximately 35 trillion cubic feet of gross resources of natural gas located offshore Cyprus and Israel, activity will only continue to increase in the next few years. Preliminary agenda highlights include sessions dedicated to: • The international impact of the new energy resource • Resource potential • Regional seismic data analysis • Gas reserves and recoverable reserves • Cyprus reserves and expected production date • Israel reserves and production forecast • Cyprus licensing and requirements • Offshore regulations • The market for new resources Hydrocarbon Processing | FEBRUARY 2013

Eastern Mediterranean Gas Conference Preview • Managing the risk of establishing a safe and reliable design basis for gas mega-projects • Panel discussion: The impact of the new energy resource • Panel discussion: A game-changer for Europe and international markets • Infrastructure requirements and developments • Panel discussion: Offshore drilling and production—future requirements • Panel discussion: LNG and FLNG • Panel discussion: Subsea • Gas: The fuel for the 21st century • The future of the Eastern Mediterranean. Speakers at EMGC 2013 include executives at some of the world’s most prominent oil and gas companies as well as key government officials. Confirmed speakers include: • Chuck Davidson, CEO of Noble Energy Inc. • Panos Papanastasiou, Dean of the Engineering School, Department of Civil and Environmental Engineering, University of Cyprus

34 FEBRUARY 2013 | HydrocarbonProcessing.com

• Terry Gerhart, Vice President, Operations, Eastern Mediterranean Business Unit, Noble Energy Inc. Benefits of attendance. As activity continues in the Eastern Mediterranean, industry-leading companies are preparing to increase their regional presence. At the inaugural EMGC, executives from operators and service and technology companies active in the region will share insight into their experience with this important new resource area. Conference attendees will have an unmatched opportunity to learn the latest information on the stages of development of exploration, drilling, pipeline and gas processing projects in the region. At EMGC, attendees will hear what some oil and gas operators have planned for offshore Cyprus and Israel. They will also hear from industry experts about the projected global market impact of the region’s resources. Additionally, attendees will have the option to register for a pre-conference workshop on “Doing Business in the

Select 157 at www.HydrocarbonProcessing.com/RS

Eastern Mediterranean,” which will focus on the regulations and practices surrounding business activity in the region. The workshop will be supported by the Cyprus Investment Promotion Agency. Companies involved in a wide range of activities will benefit from attending EMGC 2013, including oil and gas production, natural gas processing, refining, technology and equipment, construction consulting, investment banking, chemicals and petrochemicals, oil and gas services, research and venture/ mutual funds. Gulf Publishing Company encourages your organization to be a part of this exciting conference and explore the many opportunities the Eastern Mediterranean region holds. Do not miss the chance to participate in this groundbreaking event! For more information about confer-

ence registration and sponsorships, contact Melissa Smith, Events Director, Gulf Publishing Company. at +1 (713) 5204475 or Melissa.Smith@Gulf Pub.com.

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| Special Report CLEAN FUELS Demand for refined products is largely driven by “cleaner” middle distillates—lower-sulfur diesel and jet fuel. Other factors, such renewables and biofuels, are influencing the operation of global refining assets. Investment and innovation will continue as global refiners explore cost-effective means to meet present and future clean-fuel demand and specifications.

Special Report

Clean Fuels E. PETELA, Aspen Technology Inc., Houston, Texas

Refinery optimization: Closing the gap between planned and actual performance Refinery optimization is a complex business. Plant managers across the globe face constant pressure to achieve commercial targets. Fundamentally, a key part of the operational planning process relies on setting accurate goals, whereby planning and scheduling, process modeling and day-to-day plant operations are important tools to help set targets and achieve them. Often, management encounters more questions than answers. Why do the linear programming (LP) models not reflect reality? How do we cope with continuously changing targets? Why are we not performing to expectations? The optimal plan typically will be a “stretch” target. It may not factor in certain constraints like tankage, but it will account for plant availability while not assuming any product quality giveaway. Refining is not a linear process. In reality, there is always a broad range of variables and fluctuations to manage. As a result, there will almost certainly be a gap between planned and actual performance. A small percentage variation in the production process or delays in scheduling can be costly and equate to plant inefficiency. For executive decision-makers, this could have a significant impact on planning and forecasting for their entire operation. On the positive side, this could mean that actual selling prices are higher than those for expected or opportunistic purchases. Conversely, the effect might be negative, causing less throughput, lower yields and product quality giveaways. Planning is key to profitability. Pri-

marily, there are two types of gaps: unanticipated events that have a big impact, with a large gap across a short time frame; and the ongoing margin leak during nor-

mal operation, with small gaps over a longer period of time. Overall, these gaps are likely to have negative impacts on refinery profitability levels. The typical gap between planned and actual financial performance is about 5%, but it is not uncommon to see a gap of 10% of gross margin. For a mid-size refinery, at today’s margins, a 10% gap represents a potential financial loss of up to $20 million per year (MM/yr). It is hardly surprising that, for most refiners, closing this gap is one of the largest (noncapital) improvement opportunities. Therefore, from the perspective of the planners, it is important to ensure that plans are as accurate as possible from the outset of the process. To best achieve this accuracy, planners must consistently question their models. They must ask several key questions: • Is the plan optimum, or should it be stretched? • Is the plan fit for purpose, and is it resilient? • Does the plan provide a true representation of the capabilities of the refinery? These considerations must also take into account the current status the plant is operating under, along with the likely changes over time. When first developed, planning models usually reflect reality based upon the criteria known at the point of design. However, changes to the refinery mean that the model will require modifications over time, to prevent inaccuracies from occurring. Since it is necessary to update the planning model, planners must decide how often to make necessary alterations. The best practice will be to use engineering simulation models (process and rigorous reactor models) to update the planning model. Engineering models may require tuning to current operations, but

there is growing awareness that their usage is becoming critical to delivering optimum planning models. In this context, a blend of planning and engineering tools provides a powerful solution. Dealing with risk. Any refinery plan must be able to effectively manage risk. This is always a difficult challenge. Key input variables in planning can have a large degree of uncertainty associated with them—feedstock and product prices, for example. In the course of the planning process, refineries typically will need to make assumptions and even informed guesses about the future values of these variables. Inaccuracies in these guesses will result in significant gaps between planned and actual profitability. The traditional approach to making these assumptions is to perform a scenario analysis. Typically, such an analysis requires the time-consuming definition of a large number of cases. Incorporating risk analysis can help develop more resilient plans that are likely to be achievable. Key role of scheduling. Closely linked

to planning, scheduling is typically more about feasibility than economic optimization. Planning output is typically delivered to the refinery’s management and scheduling teams. The schedulers then take the plans and convert them into hour-by-hour actions. However, a sensible approach to scheduling should not only look at the various options for achieving the plan, but also provide the ability to react quickly to deviations from that plan. Just as with the planning process, refinery management should continuously question the scheduling approach. Key questions typically include: Hydrocarbon Processing | FEBRUARY 2013

Clean Fuels • Are the plans and schedules aligned? • What is the feedback to the planning process? • How quickly can the schedulers cope with unplanned events, and can they evaluate opportunistic sales and purchases in the necessary time frame? Here, petroleum-scheduling solutions that come with a planning and scheduling model accuracy (PSMA) tool, which facilitates and automates the process of modelaccuracy tracking, can play a key role. Managing energy. Another key area

that refinery management must focus on is energy management. Refineries are extremely high consumers of energy; approximately 40% of a refinery’s outgoing

costs are energy-related. The cost of energy is the highest refining cost after crude oil purchases (FIG. 1). The energy cost for an average, 100,000-barrel-per-day (bpd) refinery can hit $100 MM/yr. The rising cost of energy, along with stricter environmental emissions rules, means that there is a need for better planning and management. In the future, there will be an increasing focus within refineries on energy optimization rather than only on hydrocarbon optimization. Today, the focus on energy reporting is being superseded by a focus on energy management, which requires management of both the demand and the supply side. Refiners must question energy costs. In particular, they should ask themselves the following:

FIG. 1. Planners can easily review and manage constraints with a full view of the refinery.

FIG. 2. Visual tools enhance data analysis to support better crude purchasing decisions.

38 FEBRUARY 2013 | HydrocarbonProcessing.com

• Can energy costs be reliably forecasted? • Do energy usage and costs meet the plan? • Can energy and emissions constrain the plan? Operational focus. Some refineries have successfully implemented—and are continuing to integrate—planning, scheduling and energy-management systems as part of an overall risk-management strategy, effectively taking a more integrated approach to their overall operational strategy (FIG. 2). Refiners can look to achieve improvements in unit and refinery-wide performance by concentrating on two areas in particular: closedloop control and open-loop management. Advanced process control (APC) techniques typically come into play with closed-loop control. Recent advances in APC have reduced the cost of implementation and made controller maintenance much easier. As a result, APC can now be justified on most units. Composite APC applications can be used to synchronize and optimize the operation of multiple units. New work is focused on feeding targets from scheduling directly to APC applications, which can understand operating constraints and can feed back to the scheduling system (and, from there, feed back to planning). Open-loop performance management is also vital to adding value in the refinery. Most performance-management systems in use are actually performance-reporting systems. For performance management to be valuable, it needs to move beyond simple reporting by delivering information in as near real time as possible, and it also needs to provide what is known as “look-ahead” capability. This enables refiners to answer the question, “How will this information impact my monthly plan, define the magnitude of the issue and facilitate rapid solution investigation?” Performance reporting is capable of pinpointing where a refinery is making errors and, therefore, help eliminate their reoccurrence in the future. The point is not to avoid making the same mistake twice; it is managing performance to avoid making the mistake the first time. Ultimately, performance management is extremely powerful because it draws on data from many of the other tools previously outlined, from planning and sched-

Clean Fuels

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uling to APC. Refineries should carry out a systematic performance analysis to quickly identify gaps and actions. To be effective, this analysis requires multidisciplinary input. Closing the gap is key to success. Refining margins continue to be squeezed in todayâ&#x20AC;&#x2122;s highly competitive marketplace. The difference between planned financial performance and actual financial performance may be up to 10% of a refineryâ&#x20AC;&#x2122;s gross margin. Closing this gap is one of the highest return opportunities for refinery managers today. Refineries should regularly define gaps in financial performanceâ&#x20AC;&#x201D;typically on a monthly basis. To do so effectively, however, requires a systematic analysis of why actual performance falls below target. Each step of the processâ&#x20AC;&#x201D;from planning to scheduling through operationsâ&#x20AC;&#x201D; needs to be analyzed for gaps, along with the financial value of closing those gaps. Once the reasons for the gaps are known, appropriate actions can be taken. In some instances, these may be one-off actions (e.g., replacing unreliable equipment or process systems that require long-term operational changes). Refinery management must remember that small, incremental changes can make huge differences to the competitiveness of a refinery. Software technology solutions provide a realistic method of closing the gap between planned and actual performance, and they are critical to achieving long-term commercial success. ERIC PETELA is Aspen Technology Inc.â&#x20AC;&#x2122;s director of business consulting for Europe and the Middle East, and he is responsible for providing technical support to AspenTechâ&#x20AC;&#x2122;s oil and gas clients in the areas of manufacturing and petroleum supply chain. Mr. Petela joined AspenTech in 1997 and has over 30 years of experience in the oil and gas, refining and petrochemical industries. Mr. Petela is also a specialist in improving plant operations through process engineering, planning and scheduling technologies. He has extensive commercial experience and in-depth knowledge of refining, olefins, chemicals and polymers process units, and the highly integrated energy and utility systems within complex manufacturing sites. Mr. Petela began his career in the area of process plant design, and he held a variety of roles over a number of years before moving to a business consulting role. He has implemented projects and performed consulting services for many oil and chemical companies around the world. Mr. Petela has a BSc degree from the University of Nottingham, and he is a chartered engineer in the UK and a fellow of the Institution of Chemical Engineers.

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Special Report

Clean Fuels D. DE HAAN, Criterion Catalysts & Technologies, Amsterdam, The Netherlands; M. STREET, Shell Global Solutions International BV, Amsterdam, The Netherlands; and G. ORZESZKO, Grupa LOTOS SA, Gdańsk, Poland

New residue-upgrading complex achieves Euro 5 specifications In late 2010, Grupa LOTOS SA completed construction of a major residue-upgrading project at its refinery in Gdańsk, Poland. Its 10+ Program was designed to unlock a step change in the facility’s long-term profitability. After two years of operating, this project has had a profound effect on the refinery’s economics. Following the project, the refinery increased its crude capacity by 75% to 10 million tpy, achieved higher conversion capacity, and improved margins by $5/bbl. In addition, Grupa LOTOS was able to increase production of higher-margin jet fuel and diesel, while reducing fuel oil production (FIG. 1). Result: The refiner moved closer to its goal of securing the complex’s future in response to increasingly stringent fuel specifications and emissions legislation. Two key process units of the new residue-upgrading complex included an advanced solvent deasphalter and residuum/ distillate hydrocracker. The new hydrocracker could process a blend of deasphalted oil (DAO) and vacuum gasoil (VGO).1 In addition, the DAO hydrocracker used state-of-the-art reactor internals and commercially proven demetallization, hydrotreating and hydrocracking catalysts.2 The hydrocracker successfully completed its acceptance test run in May 2011 and has met all performance guarantees. With the initial cycle now close to two years, the unit has delivered sustained performance in converting the DAO/ VGO feedstock directly into Jet A-1 fuel and Euro 5-quality diesel, both with sulfur contents much lower than 10 ppm. Additionally, Grupa LOTOS worked with the hydrocracker licensor and catalyst provider to optimize the DAO hydrocracker’s performance. The net conversion increased from the original design level of 60% in once-through mode to 80% conversion in recycle mode. These changes have raised middle-distillate yields, while operating within the refinery’s hydrogen availability.

unit or a boiler for power production. There are no large product streams requiring further processing or treating.

Integration into existing refinery facilities. Grupa LO-

TOS’ experience integrated the new residue-upgrading complex with minimal modifications to the existing main infrastructure of the refinery.1 The advanced solvent deasphalting unit requires feedstock (atmospheric or vacuum residue) plus utilities from the refinery. It produces DAO, which is sent directly to the hydrocracker, and an asphaltene liquid residue, which can be sent to fuel oil or asphalt blending, a pelletizing

FIG. 1. Side view of the Grupa LOTOS residue-upgrading complex. Hydrocarbon Processing | FEBRUARY 2013

Clean Fuels The DAO hydrocracker requires feedstock (VGO, DAO and hydrogen) and produces finished products, mostly jet fuel and diesel. It also yields hydrowax, which Grupa LOTOS uses as a feed for base-oil manufacturing and as a component for low-sulfur fuel oil (LSFO). The unit also produces some light naphtha. Grupa LOTOS sends most of the naphtha to the isomerization process, although it could also be sent directly to gasoline blending. The heavy naphtha is used as catalytic reformer feed, although this can also be sold as chemical feedstock. Grupa LOTOS uses the asphaltene residue in the production of heavy-sulfur fuel oil (HSFO) and for bitumen blending. FIG. 2 is a simplified block scheme of the new residueupgrading units installed at Grupa LOTOS. DAO hydrocracking technology. The project team had to consider numerous counterbalancing aspects when developing the reactor configuration and process design. For instance, although it was desirable to maximize the solvent deasphalter unit’s DAO yield and the hydrocracker conversion level, this led to higher metals and Conradson carbon residue (CCR) content. This route required larger volumes of catalyst, especially demetallization catalyst; it also required larger reactors to achieve an economically viable catalyst run length. The hydrocracker licensor, catalyst provider and Grupa LOTOS worked closely together to find the best design that would optimize the returns against the cost. As shown in FIG. 3, the DAO hydrocracker features three in-series reactors designed for sequential processing of the feedstock into finished products. These reactors are the:

Crude Atmospheric residue

Naphtha HVU Vacuum residue

VGO

HCU Hydrowax

Solvent deasphalter

DAO

Asphaltenes

FIG. 2. Flow diagram of the Grupa LOTOS residue upgrader.

Jet/diesel LSFO Lubes

HSFO, bitumen

• Demetallization reactor, which reduces metals in feed to less than 1 ppmw • Pretreatment reactor, which reduces key contaminants such as nitrogen, sulfur and CCR • Cracking reactor, which is designed to achieve target conversion and to produce on-specification liquid products. The DAO hydrocracker at Grupa LOTOS has a capacity of 6,000 tpd (2 million tpy), a catalyst cycle length of a minimum of three years and a net conversion level of 60%, which has increased to 80%. The unit’s hydrogen consumption is within the availability from the refinery’s hydrogen manufacturing unit. Most of the produced naphtha feeds the gasoline production units; the remainder is sold as chemical feed. From almost two years of monitoring data, the unit has achieved sustained performance, and it has overachieved in terms of yield and catalyst life. In addition, the catalyst deactivation is very slow and it is on target for the next planned turnaround. Yields are also stable, as is product quality. Since the startup of the new units, Grupa LOTOS, working closely with technical services from the hydrocracker licensor and catalyst providers, adjusted the operation of the hydrocracker to increase jet fuel and diesel production and to minimize unconverted residue make.1, 2 Middle-distillate selectivity was a key consideration; it prevented higher conversion in the once-through operation. To overcome this condition, recycle of the fractionator bottoms (unconverted residue) was implemented, and the conversion was successfully raised from 60% to 80%. DAO yield from the advanced solvent deasphater unit, and, therefore, the percentage of DAO in the hydrocracker feed, has steadily increased in line with the hydrocracker’s ability to process more difficult feed with higher metals, nitrogen and CCR content. All of these changes were made in incremental steps and closely monitored. Demetallization catalyst performance. Feed metals re-

duction is the most critical performance specification for the demetallization catalyst system, as this determines its ability to achieve a feed quality to the pretreatment catalyst that is more consistent with that of a very heavy VGO feed. The demetallization catalysts installed at Gdańsk are specialty demetallization catalysts that have a very high activity for metals removal, a high metal uptake capacity, and a high crush strength.3 These catalysts are used extensively for: • Removing metals and CCR in the upgrading of heavy VGOs, residues and DAO

80 60 40 HDM, % Metals on catalyst, %

Metals on catalyst, %

Hydrodemetallization (HDM), %

100

0 0

FIG. 3. DAO hydrocracker configuration.1

42 FEBRUARY 2013 | HydrocarbonProcessing.com

100

200

300 Days on stream

400

500

FIG. 4. Demetallization catalysts’ metals removal efficiency and metals buildup.3

600

Clean Fuels • Protecting the pretreatment catalyst from metal poisoning in the guard bed or reactor of a multi-reactor system. The deactivation rate of the demetallization catalyst has been low and is on target for the planned cycle length and turnaround date. As shown in FIG. 4 (blue series), the demetallization removal efficiency has been near 100% over the cycle. The DAO hydrocracker design allows the ability to safely obtain a sample of the demetallization reactor effluent and to directly measure the metal slip to the pretreatment catalyst. The accumulation rate of metals on catalyst is calculated and closely monitored on the basis of real performance data. The trend of total metals on catalyst is in line with the plan, as shown in FIG. 4 (red series). From the sampling program across the demetallization reactor, after nearly two years of operation, the demetallization catalyst continued to achieve significant conversion levels of sulfur (approximately 90%), CCR (80%) and nitrogen (50%). In addition to metals removal, the system has unlocked pretreatment catalyst activity and enabled further feedstock optimization. Pretreatment and cracking catalyst performance. The pretreatment and cracking catalysts are applied in a stackedbed system over multiple beds across the two reactors.2 This system contains: • A high-activity nickel (Ni) molybdenum (Mo) catalyst, which has an exceptionally high hydrodesulfurization (HDS) activity and high-metals tolerance2 • A dual-function, HDS/hydrodenitrogenation (HDN)

active, mild conversion catalyst, which is applied in the bottom beds of pretreatment service2 • Middle-distillate-selective cracking catalysts.2 This catalyst system, which has been proven commercially in many VGO hydrocracking and fluid-catalytic cracking (FCC) pretreatment applications processing heavy feeds, has shown very stable performance. The activity and selectivity closely match the original performance estimates, and the product qualities of the middle-distillate streams (kerosine and diesel) continue to meet and even exceed specifications. After a brief initial operation at near-design conditions, the net conversion of the hydrocracker was increased to 80% over the course of the first year of operation. As shown in FIG. 5, the net conversion has remained close to the 80% level, even as the feed quality has changed with increased nitrogen and CCR content, owing to the higher DAO lift in the advanced deasphalter unit and higher DAO level in the hydrocracker feed blend. Despite this increased severity, the DAO hydrocracker has delivered sustained performance over almost two years of operation. The kerosine product continuously achieves full Jet A-1 fuel quality requirements and significantly exceeds the 25-mm smoke-point specification, as shown in FIG. 6. Similarly, the diesel product has been achieving full Euro 5 quality requirements and significantly exceeding the 46 cetane index specification, as shown in FIG. 7. Significantly, both distillate products continue to have very low sulfur levels, below 2 ppmw and well below the 10-ppmw specification for diesel product, as shown in FIG. 8.

100

75 70 Diesel cetane index

Net conversion, wt %

90 85 80 75

65 60

60 0

100

200

300 400 Days on stream

500

600

700

200

300 400 Days on stream

500

600

700

300 400 Days on stream

500

600

700

FIG. 7. Diesel cetane index.

FIG. 5. Net conversion levels achieved by the DAO hydrocracker. 35

100 9

Kerosine sulfur content Diesel sulfur content

8 25

Sulfur content, ppmw

Kerosine, smoke point

100

20 15 10

7 6 5 4 3 2

1 0

0 0

100

200

FIG. 6. Kerosine smoke point.

300 400 Days on stream

500

600

700

100

200

FIG. 8. Kerosine and diesel sulfur content. Hydrocarbon Processing | FEBRUARY 2013

Clean Fuels With the advanced solvent deasphalter, the design of the DAO hydrocracker offers the refinery more flexibility. From a feedstock perspective, different crude blends are possible while still controlling fuel-oil production. From a refinedproduct optimization perspective, this refinery is able to use the high-quality kerosine as a blending component to increase diesel production; to adjust diesel cold-flow properties; or to be sold as Jet A-1 fuel, depending on the market conditions. The fractionator bottoms, called hydrowax or unconverted residue, form a high-quality product due to the high-hydrogen and low-sulfur contents and absence of CCR species. A profitable outlet for the hydrowax has been as supplemental feed to the base-oil plant at the Gdańsk refinery, which has improved yields and increased quality of the base-oil products. Hydrowax is also blended into LSFO. In an FCC-based refinery, the lowsulfur content of the hydrowax (below 50 ppm) enables gasoline production from an FCC unit, co-processing the hydrowax, to meet the 10-ppm sulfur gasoline specification more easily. Grupa LOTOS looks to the future. Grupa LOTOS launched the 10+ Program in response to increasingly stringent product specifications that were threatening its competitiveness. The rewards that it has unlocked are compelling. Based on this success, Grupa LOTOS has commenced the next chapter in its performance improvement journey. The refiner plans to eliminate all liquid fuel residue and provide the best fit with respect to the strategic drivers and return on investment.

NOTES The Residuum Oil Supercritical Extraction (ROSE) solvent deasphalter and Shell Global Solutions’ distillate hydrocracker, which is processing a blend of deasphalted oil and vacuum gasoil—Shell Global Solutions DAO hydrocracker. 2 Commercially proven demetallization, hydrotreating and hydrocracking catalysts from Criterion Catalysts and Technologies Ltd. and Zeolyst International. 3 Criterion’s MaxTrap (Ni,V) and MaxTrap (Ni,V) VGO. 1

DESIREE DE HAAN works in hydrocracking technical service at Criterion Catalysts & Technologies and covers units in the EMEAR region. She has worked at the Shell Research and Technology Centre in Amsterdam, The Netherlands, and with Criterion for several years in catalyst research and development and technical service in the fields of distillate hydrotreating, fluidized catalytic cracking pretreatment and (mild) hydrocracking. Ms. de Haan holds an MSc degree in inorganic chemistry and catalysis from Utrecht University, The Netherlands. MIKE STREET is a principal process engineer at Shell Global Solutions in Amsterdam, The Netherlands. He is primarily responsible for Shell’s hydrocracking design and technical services in the EMEAR region. Mr. Street has more than 20 years of experience in refining design, operation and technical services, mostly in hydrocracking. He holds a BSc degree in chemical engineering from the University of Birmingham, UK. GRZEGORZ ORZESZKO works in Grupa LOTOS’ hydrocracking department, covering the operation of VGO and DAO hydrocracking units. He has worked in Grupa LOTOS’ investment department (10+ Program) for five years and was responsible for the Shell Global Solutions DAO hydrocracker from initial basis of design through the investment process to startup. Mr. Orzeszko holds an MS degree in chemical technology from AGH University of Science and Technology, Kraków, Poland.

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STEPHANY ROMANOW Editor

BILLY THINNES Technical Editor

ADRIENNE M. BLUME Process Editor

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LEE NICHOLS Director, Data Division

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44 FEBRUARY 2013 | HydrocarbonProcessing.com

Special Report

Clean Fuels T. AYRAL and P. DE JONGE, Honeywell Process Solutions, Camarillo, California, and Calgary, Alberta, Canada

Operator training simulators for brownfield process units offer many benefits In the airline industry, pilots are responsible for complex and expensive equipment, and the lives of many people. Flight simulators are used to train pilots for nontypical events, such as engine failure and water landing, and pilots are required to spend a specified amount of time per quarter-year in simulator training, to maintain certification. As the role of the process console operator has evolved, and he or she now controls more pieces of equipment (assets) and more control loops. The process console operator role approaches the responsibility of a pilot with similar levels of consequences when a failure occurs. Many progressive processing companies have installed operator training simulators (OTSs) to train operators for both routine operations (startup and shutdown) and abnormal situations. Many processing plant executives want to know the financial benefits and justification for implementing and maintaining OTSs for their existing plants and several examples quantify those benefits. However, before discussing the benefits of the process, it is important to understand the components of an OTS. Definition. The components of a firstclass OTS include: • Same equipment, distributed control system configuration, tags and logic as the actual plant • Training environment nearly identical to the control room • High level of realism due to reasonably accurate dynamic process models • Realistic process models to provide the sense for urgency in reacting to training exercise events • Used in teaching operators to recognize and react to plant-specific events

and scenarios, with an instructor console • Ability to run exercises without an instructor • Maintained to remain consistent with the actual process and controls. FIG. 1 is a diagram containing these components. FIG. 2 illustrates a typical OTS graphic, while FIG. 3 offers an example of a typical OTS training room. Costs. An OTS for a standard refinery process unit, like a fluid catalytic cracking unit, including the various software, hardware and service components, will cost approximately $700,000 or more, depending on overall complexity of the unit and the type of control integration that is required. In the presented example, we will assume a cost of $7 million to cover the expense of multiple OTSs for different processing units, not to mention costs associated with training, hardware, maintenance and support. Benefits. Today, construction projects for most new process units include

an OTS. The financial benefits alone for an OTS in greenfield plants have been well documented for more than a decade. When itemizing the usefulness of an OTS, one cannot overlook that it offers:1 • Excellent startup training • Ability to review written operating procedures prior to startup • Identification of major process/logic/control limitations before unit startup • Ability to demonstrate control applications before deployment to the plant • Reduction of the initial startup period by several days. It is also clear that OTSs generate significant benefits for brownfield units (or through the entire lifecycle of a process unit). Several brownfield clients have had OTS programs in operation for all of their plants’ process units for over 20 years. These companies continue to maintain and update their OTSs, ensuring that the OTSs are an integral part of their plants’ continuing operator training.

Same software, same hardware, same conﬁguration Operator station

Controller

Operator station

Server

Field device station

Operator station

Instructor station

Virtualized Server

Same server/controller software same conﬁguration

The control room

The training room

Plant graphics and controls database migrate easily to the training system

FIG.1. OTS components. Hydrocarbon Processing | FEBRUARY 2013

Clean Fuels The main economic benefits of an OTS fall into four categories: • Reduced in planned turnaround time • Fewer in abnormal situations or incidents caused by human error • Improved advanced process control (ARC) utilization • Less in capital equipment for repairs. Some additional benefits are smaller or may be more difficult to quantify. These include benefits resulting from safety improvements, fewer environmental incidents, increased mechanical integrity and energy savings (resulting from fewer startups and shutdowns). The

additional benefits, which can be significant, are not estimated here. The total annualized benefits from an OTS for a 100,000-bpd refinery are estimated and summarized in TABLE 1. One of the key benefits that OTSs offer is a reduction in planned turnaround time. This benefit includes planned startup and shutdown time before and after scheduled maintenance. It is not intended to include benefits for unplanned shutdowns and maintenance. As described in a previous article, an operating company used a basis of 10% reduction in startup time from using a simulator for a brownfield unit.2 We will extend this to include a 5% reduction in shutdown

FIG. 2. A typical OTS graphic.

time and an additional 5% for better operator understanding, for a total of 20% reduction in turnaround time. Using a cracked spread of $24/bbl and a charge rate of 100,000 bpd, this provides a profit of $2.4 million/day. With a conservative 14-day turnaround every three years, an OTS is estimated to generate an annual benefit of $2.24 million. OTS are also useful when addressing the reduction in abnormal situations or incidents caused by human error. An operating company used the following as a basis to estimate the benefits of an OTS:2 • Half of the incidents that were either caused by or exacerbated by human error will be eliminated • A quarter of the incidents that may have been exacerbated by human error will be eliminated • The benefit for a refinery should therefore be calculated to be a reduction in plant downtime of 15%. Using the previously calculated daily profit of $2.4 million/day, and four days per year for unplanned downtime, a 15% reduction in downtime yields a conservative OTS annual benefit of $1.44 million. APC utilization can also be optimitized. This benefit is estimated as a 15% improvement in total plant APC benefits because operators understand and utilize the APC better, and therefore have higher utilization factors. A conservative $7.4 million in annual APC benefits was used here, generated using a simple refinery APC payback calculation to estimate a 15% improvement of $1.11 million/yr. One should also not forget that an OTS offers a reduction in capital equipment for repairs. When abnormal incidents occur due to human error, equipment and materials are required for repairs or additional wear-out because of the incident. This estimate attempts TABLE 1. Estimated annual beneﬁts of an OTS at a typical 100,000 bpd reﬁnery Category Reduction in planned turnaround time

2,240,000

Reduction in abnormal situations

1,440,000

Improved APC utilization Reduction in capital equipment for repairs FIG. 3. Two engineers train in an OTS control room.

46 FEBRUARY 2013 | HydrocarbonProcessing.com

Annual beneﬁt, $

TOTAL

1,110,000 110,000 4,900,000

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to quantify those preventable costs. The benefit is calculated by a reduction in the plant’s capital budget of 0.5% in total material costs of a $22 million annual budget. Estimate summary. These benefit es-

timates are based upon a generic refinery configuration and size. Heuristics, experience, simple financial models and engineering judgments were used for the calculation of these benefits. A better estimate for an actual process could be generated by looking at five years of incident data on a unit-by-unit basis, with actual margins and process unit rates. The annual benefit estimated would provide a simple pay-out time of less than two years, even when the cost of simulator maintenance and instructor costs are added. This should easily surpass the investment hurdle rate of most processing companies. BP Chemical previously studied OTS benefits.3 In a five-year period, BP installed OTSs at four of its major chemical sites in the UK. Benefits were estimated from four quantifiable categories: • Initial startup savings of eight days • One saved day on subsequent startups on overall turnaround

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• Two production days saved each year from improved recovery from upsets • One percent improvement in costs through better control of the plant. These benefits are in line with the benefits estimates provided in TABLE 1. In addition, at another site, BP reported a benefit that was 20 times simple payback over the original investment in a fiveyear period.3 Quantification. The beneficial nature

of OTSs has been quantified here using experience, simple financial models, good engineering judgment and financial calculations. As two of our colleagues stated:2 “The justification for an OTS in a greenfield project is more obvious than for an existing plant. In a new plant, operators need to be trained on something that does not yet exist, whereas the direct benefit of an OTS for training in an existing plant is less certain. Even so, most agree that such a training system in existing plants can reduce losses by improving the startup time, prevent unscheduled downtime and equipment repairs, and maintain production throughputs. It is, however hard to quantify.” Using very conservative estimation

methods, the estimated benefits for OTSs show a return on investment certain to surpass the typical corporate investment hurdle rate. LITERATURE CITED French, S. J. , “Phillips 66 Co.’s financial benefits road map using Honeywell Hi Spec dynamic training simulator,” NPRA Computer Conference, October 2001. 2 Mason, J. and J. A. Alamo, “The role of OTS in operator training programs,” Control Engineering , Nov. 2, 2010. 3 Fiske, T., “Uses and benefits of dynamic simulation for operator training systems,” ARC Insights, August 9, 2007. 1

TOM AYRAL works for Honeywell’s Advanced Solutions division. He has over 30 years of experience bringing new technology to the oil and chemical industries. Mr. Ayral has a BS degree in chemical engineering and an MBA degree. He specializes in developing economic justifications of technologies and has published over 80 articles. PETER DE JONGE graduated with a BSc degree in chemical engineering from the University of New Brunswick in Canada. Mr. de Jonge joined Honeywell as an application engineer for UniSim Design. In March 2008, he transitioned into his current role as a simulation business consultant. He is a registered professional engineer in Alberta, Canada. Hydrocarbon Processing | FEBRUARY 2013

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Special Report

Clean Fuels K. M. BEIRNE, Sabin Metal Corp., East Hampton, New York

How to choose a refiner for your precious metals catalyst Most hydrocarbon and petrochemical processors operate precious metals recovery or asset recovery departments in one form or another. These are typically managed as independent profit centers, which, because of global economic uncertainties, have assumed more important roles in the past few years. Finding and working with the right refiner can make a significant difference in returns, thus enhancing profitability. There are more than a few unfortunate stories about an organization’s selection of, and relationship with, its precious metals refiner. A relationship with a refiner may have significant legal implications if the refiner violates environmental regulations when processing spent catalyst. PGMs and other precious metals. Precious metal-bearing

catalysts are widely used for facilitating or accelerating hydrocarbon/petrochemical processes (where they “rearrange” hydrocarbons into specific molecules); for hydrocracking low-quality feedstock into higher-quality, more commercially useful products; and for controlling/abating harmful or unlawful volatile organic compounds and NOx emissions. Catalysts help reduce energy use in a wide range of other petrochemical/chemical manufacturing processes. For all these applications, the catalysts typically contain platinum, palladium, rhodium or ruthenium; these metals are commonly referred to as platinum group metals (PGMs). Hydrocarbon processing catalysts may contain two or more PGMs, and they may also include rhenium (another valuable precious metal) in addition to gold, silver or other metals. A variety of carriers, or supports, for these metals are also used, depending upon application; these typically include soluble or insoluble alumina, silica/alumina or zeolites (FIG. 1). Over the past few decades, worldwide demand for PGMs has increased significantly, mainly as a result of emerging economies. However, the volatility of global financial markets and geopolitical instability has also served to escalate costs for many precious metals. Precious metals costs represent only a small portion of the total processing/production dollar with regard to raw materials, equipment, personnel, transportation, etc. Nonetheless, they can still be significant when their market value is factored in, along with leasing costs for replacement metals, delays in transit and processing time for recovery and refining, and legal implications if the precious metals refiner commits an environmental infraction. With the dynamics of costs, profits and possible legal problems, it is clearly in an operator’s best interest to work with a precious metals refining organization that does the following:

1. Provides the highest possible returns for PGMs from spent catalysts 2. Provides rapid processing turnaround time 3. Complies with applicable environmental standards concerning process effluent disposal or atmospheric discharges at its refining facilities. Choosing the wrong refiner can prove to be an expensive and troublesome mistake. There are many criteria to consider when selecting a precious metals refiner. Mainly, the rules come down to specific areas that can be controlled and that apply to virtually all refiners that process spent catalyst with PGMs. These include the policies and procedures associated with the refiner’s sampling, assaying, processing and logistics arrangements. Each of these areas are briefly covered as a way of examining how to select and work with the right refiner to meet a plant’s specific requirements. Precious metals sampling. To accurately determine the amount of precious metals present in materials for recovery, refiners typically use three different sampling techniques. These techniques are dry sampling, melt sampling and solution sampling. Each of these techniques offers discrete advantages; determining the most appropriate sampling method

FIG. 1. Hydrocarbon processing catalysts may contain two or more PGMs, and they may also include rhenium, gold, silver or other metals. Hydrocarbon Processing | FEBRUARY 2013

Clean Fuels depends on the type of material being processed, as well as on its estimated precious metals content. In-house moisture and contaminants removal. To provide an accurate determination of remaining precious metals in spent catalyst lots, representative samples of these catalysts must be obtained under accurate and repeatable conditions. Over time, process catalysts become contaminated by sulfur, carbon, volatile organics, moisture and other unwanted elements. As a result, when the catalyst is removed from the process, it is usually moist and sticky, and it will not flow freely through automatic sampling equipment. Contaminants in the catalysts must first be removed to ensure accurate sampling and analysis of the remaining precious metals. This process is accomplished with an indirectly fired rotary kiln (FIG. 2), which not only greatly enhances sampling accuracy to ensure maximum recovery value of remaining precious metals, but also significantly reduces overall refining costs when handled directly at the refiner’s facility. This is a key issue

FIG. 2. Contaminants in the catalysts are removed with an indirectly fired rotary kiln, enhancing sampling accuracy and reducing overall refining costs.

with regard to the total cost of recovery and refining, and, by inference, to the overall profitability of a precious metals refining and recovery program. The typical rotary kiln will remove up to 25% of the materials’ sulfur content and up to 40% of the carbon content, usually at a rate of 300 lb/hr to 1,000 lb/hr. Most contaminants associated with spent precious metalbearing catalysts typically exhibit high loss on ignition (LOI), in addition to other contaminants previously mentioned. The removal of moisture and other contaminants is critical to the downstream sampling process. The reason for this is that the materials must be free flowing (with low LOI) initially to arrive at a final evaluation sample that is accurate to ±2%. Here, pre-burning can make a key difference; if the high moisture content and other contaminants are not removed, a suitably accurate sample cannot be obtained by the refiner, thus eliminating the possibility of providing a fair and true return value to the catalyst owner. Contaminants in spent catalysts also may be removed by a multiple hearth furnace or fluidized-bed furnace. Whatever the case, this first step (i.e., pre-burning) is critical to the sampling process. Just as important—at least from a financial perspective—is where and how the contaminants are removed. This is because many catalyst users must first ship large lots of spent catalysts (35,000 lb to 500,000 lb is a typical range) to an independent facility, where strip-burning removes their hydrocarbon content, and coke burning removes carbon. Another furnace may be required for the drying of fine particulates and other materials to eliminate moisture content. Offsite pre-burning involves additional turnaround time of up to several weeks, along with additional costs for transportation and for leasing replacement metals during the time the PGMs are unavailable to the catalyst user. Offsite pre-burning also adds costs for catalyst owners’ representatives, who must account for their clients’ materials. A refiner’s facility should be equipped with high-volume pre-burning capabilities, since high sampling accuracy requires that contaminants be removed from the mix first. The effects of high LOI after pre-burning in an oxygen environment can account for significant weight reduction in the processed spent catalyst materials, so accurate measurements are important before and after any pre-burning steps. Also, samples must be hermetically sealed following pre-burning to mitigate weight gain from moisture absorption. Accurate LOI data is vital for minimizing measurement errors due to weight changes while a sample is in transit. In general, the highest-accuracy results for LOI are determined when analysis is conducted as closely as possible to the sampling procedure (FIG. 3). Consequently, it is prudent for the catalyst owner to select a refiner that handles in-house LOI determinations under the supervision of independent inspectors. Time and cost for offsite contaminants removal. Added

FIG. 3. The highest-accuracy results for loss on ignition are determined when analysis is conducted as closely as possible to the sampling procedure.

50 FEBRUARY 2013 | HydrocarbonProcessing.com

turnaround time and additional costs are the two main considerations associated with offsite strip and coke burning of spent catalyst materials. Unless these capabilities are available at the refiner’s facility, catalyst users must pay substantial transportation charges for shipping to an independent, offsite facility. It is not uncommon for the material to remain there for up to a month for processing before it is again shipped to the refiner for sampling, analyzing, recovery and refining.

8–10 April 2013 Hilton Cyprus | Nicosia

EMGasConference.com

The Eastern Mediterranean is About to Take Off. Will You be There? Gulf Publishing Company invites you to attend the inaugural Eastern Mediterranean Gas Conference (EMGC) in Nicosia, Cyprus, on 8–10 April 2013 at the Hilton Cyprus. Noble Energy, Inc. will host the event, while Hyperion Systems Engineering will be the gold sponsor. With the development of the Eastern Mediterranean’s natural gas industry, Cyprus, Israel and the surrounding areas are poised to experience unprecedented growth in operations, production, construction, technology and service activity. This is your opportunity to put yourself in the middle of the action. At EMGC 2013, executives from operators, service and technology companies active in the region will share insight into their experience with this important new resource area. The conference will put you at the center of activity, connecting you with the professionals and companies leading development in the area.

Attend EMGC 2013 to:

• Get the latest information on the stages of development of exploration, drilling, pipeline and gas processing projects in the region • Learn more about what oil and gas operators have planned for offshore Cyprus and Israel • Hear from industry experts about the projected global market impact of the region’s resources • Discover what market and technology trends are driving the development of the Eastern Mediterranean’s natural gas industry • Explore critical issues like resource potential, leasing/permitting, development plans, infrastructure requirements, governmental plans and regulations, and more

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VIP Dinner (Invitation only)

DAY 2: TUESDAY, 9 APRIL 2013 7:30 a.m.

REGISTRATION AND CONTINENTAL BREAKFAST

8:55 a.m.

Opening Remarks: John Royall, President and CEO, Gulf Publishing Company

9–10:10 a.m.

Session One: The Impact of the New Energy Resource Government of Cyprus: President (invited) Government of Cyprus: Solon Kassinis, Director of Energy Services, Ministry of Commerce, Industry and Tourism, Cyprus Government of Israel: Sagi Karni, Head of International Affairs Department and Diplomatic Advisor to the Minister, Ministry of Energy and Water Resources Charles D. Davidson, Chairman and CEO, Noble Energy, Inc.

10:10–10:40 a.m.

COFFEE BREAK

10:40 a.m.–12:20 p.m. Session Two: Resource Potential Regional Seismic Data Analysis - Pramod Kulkarni, Editor, World Oil Cyprus Reserves and Expected Production Date - Costas Ioannou, Natural Gas Public Company (DEFA), Cyprus Israel Reserves and Production Forecast - Ophir Gore, Director of Economic Affairs, ISECO, Israeli Ministry of Industry, Trade and Labor Cyprus Licensing Regulations and Requirements - Deloitte, Ltd. (invited) Offshore Regulations - Jude John Gallagher, Director - Offshore Technology Business Development, ABS 12:20–1:20 p.m.

LUNCH

1:20–2 p.m.

Session Three: The Market for New Resources Managing the Risk of Establishing a Safe and Reliable Design Basis for Natural Gas Mega Projects - Richard Whitehead, Director, Manchester Advisory Services, Det Norske Veritas S.A. Regional Potential and Future Projections - Chris Barton, Sr. Vice President, Oil and Gas Business Development, KBR, Inc.

2–2:30 p.m.

COFFEE BREAK

2:30–4 p.m.

Session Four: International Impact Panel Discussion: The Impact of the New Energy Resource Panelists: Jim Rockwell, ConocoPhillips; Philip Hagyard, SVP LNG/GTL Business Unit, Technip; Waﬁk Beydoun, President and CEO, Total E&P Research & Technology USA, LLC Panel Discussion: A Game Changer for Europe and International Markets Moderator: Adi Karev, Oil & Gas Leader, Deloitte Worldwide Panelists: Gunther Oettinger, Directorate General for Energy, European Commission; eni (invited)

4 p.m.

Closing Remarks: John Royall, President and CEO, Gulf Publishing Company

7–9 p.m.

GALA DINNER - Sponsored by Deloitte, Ltd. Introduction by: Nicos Papakyriacou, Partner in charge of Nicosia Office, Assurance and Enterprise Risk Services, Deloitte, Ltd. Keynote: Charles D. Davidson, Chairman and CEO, Noble Energy, Inc.

DAY 3: WEDNESDAY, 10 APRIL 2013 7:30 a.m.

REGISTRATION AND CONTINENTAL BREAKFAST

8:55 a.m.

Opening Remarks: Pramod Kulkarni, Editor, World Oil

9–11 a.m.

Session Five: Infrastructure Developments Panel Discussion: Offshore Drilling and Production - Future Requirements Panelists from: Schlumberger and EMAS Panel Discussion: LNG/FLNG Panelists: Victor Allessandrini, Technip; Maximo Hernandez, Managing Partner, Global Oil and Gas, ERM Panel Discussion: Subsea Panelists: Jim Byous, OSI; Jean Pierre Corbell, Technip; FMC Technologies (invited); Cameron (invited); General Electric (invited) Long and Short of Subsea Pipelines - Uri Nooteboom, President, INTECSEA

11–11:30 a.m.

COFFEE BREAK

11:30 a.m.–1 p.m.

Session Six: A Cypriot View View of Future Developments for Cyprus - Hyperion Systems Engineering Panel Discussion: Infrastructure Requirements Panelists: Khalid Khadduri, Assistant Vice President, Intermediaries & International Banking, Wealth and Investment Management, Barclays; Panos Papanastasiou, Professor, Dean of the Engineering School, Department of Civil and Environmental Engineering, University of Cyprus; George Pelaghias, Executive Director and Program Coordinator, European Rim Policy and Investment Council (ERPIC)

1–2 p.m.

LUNCH

2–3 p.m.

Session Seven: Gas: The Fuel for the 21st Century Speakers from Foster Wheeler (invited), Woodside (invited)

3–3:30 p.m.

COFFEE BREAK

3:30–5 p.m.

Session Eight: The Future of the Eastern Mediterranean Terry Gerhart, Vice-President, Operations, Eastern Mediterranean Business Unit, Noble Energy, Inc. Government of Cyprus: Ministry of Commerce, Industry and Tourism Government of Israel

5 p.m.

Closing Remarks: John Royall, President and CEO, Gulf Publishing Company

“Doing Business in the Mediterranean” Pre-Conference Workshop When you register to attend EMGC 2013, you will have the opportunity to register for an optional* pre-conference workshop on “Doing Business in the Mediterranean.” The workshop will focus on the regulations and practices guiding business activity in the region, and will be supported by the Cyprus Investment Promotion Agency. *Additional fee assessed for workshop attendance.

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Register today at EMGasConference.com to receive our best rates. For more information about the conference, please contact Melissa Smith, Events Director, Gulf Publishing Company, at +1 (713) 520-4475 or Melissa.Smith@GulfPub.com.

Venue information: Hilton Cyprus | Archbishop Makarios III Avenue | Nicosia 1516 | Cyprus Located within easy reach of Nicosia’s city center, the historic Old City and the business district, the Hilton Cyprus hotel is the ideal place to stay while visiting Cyprus. Make the most of the Mediterranean climate as you cool off in the large outdoor pool or relax in the sun on your private balcony. The Nicosia, Cyprus hotel’s wide choice of leisure facilities, which include a fully equipped ﬁtness center, squash courts and tennis courts will ensure that you can stay in shape during your visit. The hotel’s two bars and restaurants offer convenience, choice and the chance to indulge in a variety of settings.

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T H E AU T H O R I T Y O N E N E R G Y

Clean Fuels During this time, the PGMs are unavailable to the catalyst user, and new metal must be acquired at current market prices and interest rates. As an example, with today’s interest calculations on platinum for a typical petroleum/hydrocarbon process at around 3.5%/yr, the interest cost per troy ounce per week is about $1.10 at the present platinum value of approximately $1,625/troy ounce. There is another, equally important advantage of having a refiner handle the pre-burning procedure in-house: The control, or “accountability,” that the refiner has over individual catalyst lots eliminates the possibility that materials could be mixed in with unrelated materials from another organization. If that happens, an accurate calculation of actual catalyst value cannot be made.

During the dry sampling process, materials are allowed to free-fall in a stream into a cross-cut, timed automatic sampler. Representative samples are also taken periodically. Since precious metal-bearing catalysts are made in many sizes and configurations (i.e., pellets, beads, monolithic structures and extrudates), determining the best sampling technique is crucial to recovering the most value from spent catalyst. Accurate sampling of hydrocarbon/petrochemical catalysts involves tight process control to ensure that each sample has the representative composition of the initial material lot. For example, materials must be weighed at every step of the sampling process to minimize the effects of atmospheric conditions (e.g., absorption of moisture) on any measurements performed on the samples.

Dry sampling. After the pre-burning process, the spent catalyst lot is ready for sampling. Dry sampling is used whenever materials cannot be dissolved in solution or are inappropriate to melt, either because of their structure or because of the cost associated with melting vs. the possible return. Precious metal-bearing catalysts applied in hydrocarbon and petrochemical processes are usually sampled with this technique (FIG. 4). Since it is difficult to achieve homogeneity, dry sampling is more complex and potentially less precise than melt or solution sampling. The principle of sampling involves reducing large quantities of precious metal-bearing materials (as much as many tons) into small quantities (as little as a few grams), which yields amounts that are suitable for accurate analysis. In the sampling process, a precious metals refiner typically will assign a tracking number to incoming spent catalyst materials from a customer (FIG. 5). Prior to sampling, the catalysts are tested for viscosity and for any elements or impurities that might pose workplace hazards to the refiner, to determine the most appropriate sampling approach. As the name suggests, the sampling process reduces a large batch of spent catalysts into smaller amounts suitable for accurate analysis. The goal of any materials sampling method is to maintain the relative amounts of component materials in the mix while reducing the amount of the material to a practical level. This permits accurate determination of the remaining precious metals content in the catalysts. Dry sampling involves the use of mesh screens, vibratory feeders and rotary samplers. A typical process begins by extracting two portions equal to 10% of an initial materials lot. Then, 10% samples of these portions are taken, resulting in two 1% samples of the initial lot. One of the 1% samples is used for an LOI test. This test burns moisture and other contaminants to further reduce sample volume, while the other 1% sample is further subdivided to create smaller, laboratorysized samples for the determination of the precious metals content. Samples are then extracted for analysis from different fractions and/or different stages of the resulting sub-lot. To put it simply, the sampling procedure begins by converting PGM-bearing spent catalysts into a homogenous mass so that molecules of precious metals and other constituents are evenly distributed. Results of sampling the homogeneous mass thus represent an accurate ratio of the precious metals content in the overall matrix.

Assaying. Accurate and repeatable assaying procedures, on

the other hand, require sophisticated instrumentation for measuring precious metals content of materials being reclaimed. A well-equipped analytical laboratory utilizes advanced X-ray fluorescence equipment (FIG. 6), atomic absorption and inductively coupled plasma emission spectroscopy. It also incorporates classic volumetric, gravimetric and fireassay techniques. When all methods are used together, they provide the most thorough and precise approach for determining precious metals content in spent catalyst materials, thus ensuring the highest possible returns. Generally, specific assaying techniques are determined by the types of materials being processed. Dry sampling

Coarse sampling Size reduction (mill) Fine splitting

To lab

FIG. 4. Precious metal-bearing catalysts employed in hydrocarbon and petrochemical processes are usually dry sampled.

FIG. 5. In the sampling process, a precious metals refiner typically will assign a tracking number to incoming spent catalyst materials from a customer. Hydrocarbon Processing | FEBRUARY 2013

Clean Fuels Processing turnaround time and the bottom line. The speed at which spent catalysts are processed and their precious metals recovered (i.e., reclamation turnaround time) must also be considered, since this can impact both costs and profits. Faster turnaround reduces interest charges accrued for leasing replacement precious metals obtained to minimize or eliminate plant process/production downtime. Faster processing turnaround time also reduces the need for purchasing precious metals on a volatile spot market for use in the timely manufacture of catalysts, allowing uninterrupted processing or production. Additionally, the refiner’s in-house capabilities for pre-burning spent catalysts avoids the necessity for trans-shipment of large lots of spent catalysts, which can introduce an entire new set of problems, as previously stated. There are a number of nuances and fine details associated with the fundamentals of selecting a precious metals refiner. Essentially, however, selection criteria must cover—in as much detail as possible—the refiner’s sampling, assaying, processing and shipping procedures, including turnaround times and environmental compliance issues. All of this information should be made available to the plant operator. Environmental concerns and legal implications. The

legal implications associated with processing procedures at a precious metals refiner must also be evaluated. In addition to

How to select a precious metals refiner To ensure that a relationship with a precious metals refiner will be mutually profitable and based on trust and fair treatment, operators must address several key questions. This checklist may help: • Select a refiner that uses state-of-the-art techniques and equipment • Select a refiner that has a long and successful history and a good reputation within the industry • Discuss the refiner’s performance and policies that it maintains with its customers • Request appropriate reference material, including environmental regulation documentation • Request the final destination for effluent leaving the processing plant • Determine whether the refiner has the financial resources to arrive at a settlement in a timely manner • Select a refiner that has full in-house capabilities, without the use of outside subcontractors that might affect returns in values and timeliness • Ask the refiner for detailed weight and analysis reports on shipments • Ask the refiner if sample materials are assayed in triplicate • Ask the refiner if it is allowable to be present during materials sampling, and whether an independent analysis can be conducted, if desired. 52 FEBRUARY 2013 | HydrocarbonProcessing.com

choosing the wrong refiner with regard to maximum PGM recovery and fastest possible turnaround, choosing the wrong refiner with regard to possible unlawful effluent or atmospheric discharges could become even more costly. The reason for this is simple: If a refiner violates an environmental law, not only is the refiner subject to legal action (most likely by more than one authority), but the catalyst owner will also be cited and held responsible, in most instances. Avoiding problems in refiner selection. When selecting a

refiner, one must not only be aware of how the plant’s materials will be processed, but also of how materials from the refiner’s other customers are processed. It is the operator’s responsibility to determine how any solid, liquid or gaseous byproduct is handled at the processing facility. Ideally, no hazardous waste should be shipped from a precious metals processing facility. While this may no longer be possible because of increasingly stringent environmental regulations, some refiners will ship hazardous waste materials under approved procedures and conditions; an operator should be aware of this difference. In addition, minimal pollutants should be emitted before, during or after refining. Exhaust air quality should be managed with state-of-the-art pollution control systems (FIG. 7). The refiner’s process water treatment procedures should minimize all causes of pollution. While each of these functions is fundamental, there are many hidden pitfalls surrounding them with regard to environmental compliance. Request full documentation from your catalyst refiner. Requesting detailed documentation on environmental law compliance may also help determine that the selected refiner will not violate any applicable law or regulation. To responsibly recover and refine precious metals, a refiner must use well-controlled processes that comply with applicable environmental agencies, such as the US Environmental Protection Agency (EPA). In the US, legislation such as the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), or the Superfund and the Superfund Amendments and Reauthorization Act (SARA), establish guidelines for report-

FIG. 6. A well-equipped analytical laboratory utilizes advanced X-ray fluorescence equipment, atomic absorption and inductively coupled plasma emission spectroscopy.

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Clean Fuels ing and managing chemical and toxic emissions. The Superfund Act makes it clear that a user of precious metal-bearing catalyst materials and its precious metals refiner are responsible for the materials and the processing of those materials in recovering PGMs. Many European countries have even more stringent environmental regulations. Similarly, the Resources Conservation and Recovery Act (RCRA) encompasses the generation, storage, transportation, treatment and disposal of solid and hazardous wastes. The Clean Air Act (CAA) and the Clean Water Act (CWA) are mandated by the US EPA to set environmental standards for air and water, respectively. There also exists another, more recent series of laws under the overall umbrella of the US PATRIOT Act that could have significant negative impacts on precious metals users and refiners. The PATRIOT Act, in short, mandates that virtually all transactions involving precious metals must be fully traceable. The scope of this law is so broad that it makes sense to review it thoroughly before engaging any precious metals refiner. One way to determine if a refiner can comply with all of these criteria is to check its use of appropriate pollution-abatement technology such as afterburners, bag houses, wet scrubbers, and liquid effluent neutralizing equipment. Also, the refinerâ&#x20AC;&#x2122;s approval status with all applicable agencies at the local, state and federal levels should be evaluated. Most precious metals refiners will provide copies of required documentation, which could include permits under the

CAA and CWA mandates, and proof that the refiner qualifies as a bona fide precious metals refiner, as specified in Subpart F of the RCRA regulations and the preamble to the Boilers and Industrial Furnace rule and its amendments. Takeaway. The information here is designed to provide a gen-

eral approach to seeking and working with a precious metals refiner for PGM-bearing spent catalyst materials. While each of the areas discussed is important on its own merits, the issue of a refinerâ&#x20AC;&#x2122;s compliance with regard to environmental regulations might be the most critical. All else being equal (getting maximum returns on precious metals values as quickly as possible), environmental violations at a refinery have the potential to create problems for an operating company. These steps, and the refinerâ&#x20AC;&#x2122;s overall policies with regard to applicable pollution codes and standards compliance, should provide operators with the knowledge and confidence to select the right precious metals refiner for a specific application. In any case, the relationship with that refiner must be viewed as a partnership, and it must be based on mutual trust and fair treatment. KEVIN M. BEIRNE is vice president of sales and marketing at Sabin Metal Corp. in East Hampton, New York. He has been in the precious metals industry for over four decades. In addition to his sales and marketing background, Mr. Beirne has managed analytical, instrumentation and fire assay laboratories, as well as precious metals refining and manufacturing organizations. Mr. Beirne attended Fairleigh Dickinson University. He has also been a member of the American Electroplater Society (AES), the Investment Recovery Association (IRA), and is a past president of the International Precious Metals Institute (IPMI).

FIG. 7. Exhaust air quality should be managed with state-of-the-art pollution control systems.

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Special Report

Clean Fuels R. PILLAI and P. K. NICCUM, KBR, Houston, Texas

Select new production strategies for FCC light cycle oil Global product demand trends favor diesel fuel over motor gasoline. This provides a challenge for fluid catalytic cracking (FCC) centered refineries because FCC-based light-cycle oil (LCO) now has limited value as a component in modern diesel transportation fuel due to its aromatic and sulfurous character. To make matters worse, quality virgin distillate included in the FCC feedstock is essentially destroyed during FCC processing. How can a refiner with a traditional FCC as the primary conversion unit stay profitable in a flexible market-driven economy? Recognizing the disparity between modern diesel specifications and the quality of FCC LCO provides both the keys and limitations to unlocking the potential of the FCC-based refinery to maximize high-quality diesel production. Traditional operating methodologies for maximizing the diesel yield from a low-conversion FCC refinery are briefly discussed here. The methodologies range from controlling FCC feed and product distillations, catalyst management, slurry and heavy cycle oil (HCO) recycle, FCC reactor operating conditions and hydroprocessing options for converting the aromatic LCO into highquality diesel. Also, selected FCC revamp opportunities are presented, describing some solutions to the reaction, distillation and FCC heat balance challenges of maximizing LCO production.

DIESEL ORIENTED MARKET Global demand for diesel is expected to increase from 27 million bpd (MMbpd) in 2012 to 33 MMbpd in 2025 with a marginal increase in gasoline demand during the same time.1 These trends have led new refiners to utilize hydrocracker units as their main conversion vehicle. So, can an FCC-based refinery increase diesel production? The answer to this question is “yes.” However, the big question is whether or not the associated investment costs and the unit operating trade-offs are justified by the increased diesel production. FCC optimization for maximum LCO production. There

are various methods to increase “diesel” production from an FCC-centered refinery. First, the refiner has to take basic steps to minimize the loss of straight-run (SR) diesel to the FCC feedstock and hydrotreat the LCO as needed. Low-severity FCC operations can be considered the traditional avenue for maximizing diesel production from an FCC-centered refinery. To maximize LCO yield from an FCC unit, several operational strategies are commonly applied.2 Lower FCC naphtha end point. This technique is being practiced in many refineries to meet the seasonal swing in demand for gasoline vs. diesel. The LCO obtained will be lighter (higher °API) as heavy naphtha ends up in the LCO stream.

The naphtha end point is commonly limited by the LCO flash point, LCO cetane or the onset of fouling in the top of the FCC main fractionator or its overhead system. The FCC naphtha ASTM D-86 end point would not be reduced to less than about 150°C.3 Lowering the naphtha end point can have a positive, neutral or negative effect on the FCC gasoline octane number. Gasoline octane is most likely to increase for a low-conversion FCC unit when the gasoline end point is lowered. Lower FCC reaction severity. The severity can be lowered by reducing the riser outlet temperature (ROT), reducing catalyst activity, and reducing the catalyst-to-oil ratio, thus minimizing the conversion of LCO product in the reaction riser. These can be considered as standard adjustments when operating to maximize LCO production. As the cracking severity is lowered, the LCO aromaticity also decreases. Result: The cetane number increases. The regenerator heat balance temperature decreases with decreasing ROT and decreasing catalyst activity. At some point, the low regenerator temperature can become a limitation to further decreasing reaction severity. The operation of a fired feed furnace can also be desirable when maximizing LCO production, as the higher feed temperature reduces the catalystto-oil ratio while supporting the regenerator temperature. There is also a nontraditional tactic that can be applied to maintain regenerator temperature as reaction severity is lowered. This is the continuous direct firing of the regenerator with fuel, and this can be especially helpful in maximizing LCO FCC operation when processing nonresidue containing, hydroprocessed FCC feedstocks: • Continuous regenerator air heater firing can be applied, but it has a deleterious effect on the velocities through the regenerator air distributors, as well as the practical issue associated with monitoring air heater firing. • Some refiners have also practiced continuous torch-oil firing, which is typically done only during startups. This method is commonly associated with accelerated catalyst deactivation and catalyst attrition. • A recently developed and commercialized system can be applied to distributing liquid fuel in the regenerator.a The system is designed to mitigate catalyst damage associated with conventional torch-oil firing. This technology has been adapted for use in conventional FCC units.4, 5 A patent-pending version is available for use in conventional FCC operations. In addition to this system for liquid fuels, a system for firing the regenerator with fuel gas, which is often a lower-cost fuel, has also been commercialized.a Recycle HCO/slurry. In a low-conversion FCC unit, depending on the regenerator heat balance requirement, HCO or Hydrocarbon Processing | FEBRUARY 2013

Clean Fuels slurry can be recycled back to the cracking riser. In the applications where maintaining regenerator bed temperature is not an issue, such as when processing residue feedstock, HCO may be preferred over slurry as the recycle material. As shown in FIG. 1, HCO from a low-conversion FCC operation has reasonable hydrogen content and low carbon residue. It can be readily cracked to lighter, useful liquid products, thus making it a potentially good recycle feedstock. Conversely, even in a low-conversion FCC unit, the heavier fractions of slurry oil are more hydrogen deficient and high in carbon residue; this fraction is a poor recycle feedstock unless needed for heat balance purposes.6 Adjust FCC catalyst formulation. Low-hydrogen-transfer FCC catalysts with high matrix activity but low equilibrium catalyst activity are typically recommended for maximum LCO operation in an FCC unit. Low-hydrogen-transfer catalysts are characterized as having low levels of zeolite rare earth exchange and a low zeolite unit cell size. Hydrogen-transfer reactions strip hydrogen from LCO boiling range molecules and transfer it into gasoline boiling range olefins. Result: The LCO becomes more aromatic, and gasoline becomes saturated, thereby increasing gasoline yield by limiting

overcracking of gasoline-range olefins, and, likewise, the LPG olefins yield drops. In high-LCO yield FCC operations where LCO quality, gasoline octane and LPG yield considerations are more important than gasoline volume, the hydrogen-transfer reactions are counter-productive. FCC catalysts with an active matrix are also recommended for LCO maximization. These FCC catalysts enable cracking of LCO boiling range aliphatic side chains from high molecularweight-feed components. In addition to LCO yield increase, these aliphatic side chains increase the cetane of the LCO.7 Maximize LCO end point. Maximizing the LCO end point shifts heavier slurry into the LCO stream. This method should be practiced with caution, as concern for coking in the FCC main fractionator bottoms circuit limits the LCO end point. Some other factors influencing the predilection of the bottoms circuit to suffer coking problems are: • Bottoms-circuit temperature • Slurry residence time in the circuit • Concentration of unconverted paraffins in the slurry oil. High-conversion FCC units generate a more aromatic slurry oil. It can be held at higher temperatures and longer residence times without coking.

TABLE 1. Feedstock properties Feedrate, bpsd

40,000

°API

Molecular weight

445

Sulfur, ppmw

0.05

Total nitrogen, ppmw

Watson K

12.27

CCR, wt%

0.2

Distillation type D22887, °C 10%

371

30%

401

50%

429

70%

473

90%

536

HCO Little CCR Good H2 content Slurry oil Signiﬁcant CCR Low-hydrogen content Worse with higher IBP

HCO

Slurry

8 4 0 12

Hydrogen, wt%

Separation of pilot plant products D-1160 distillation Minimal product overlap

Conradson carbon, wt%

11 10

FIG. 1. FCC recycle properties.

58 FEBRUARY 2013 | HydrocarbonProcessing.com

850°F +

800°F +

750°F +

650°F +

650°F–850°F

650°F–800°F

Source: Catalagram, No. 105, Spring 2009

650°F–750°F

Fresh feed

CRUDE DISTILLATION Another common practice is maximizing diesel production from the crude distillation unit (CDU) to minimize loss of potential diesel to the FCC feed. There are intermediate swing cuts from some CDU operations that can be routed to the FCC unit when gasoline is demanded and routed to diesel production when the objective is maximizing diesel. As a side benefit, keeping the diesel out of the FCC feed also improves FCC gasoline octane.8 Pilot-plant data have shown that, in moderate or high-severity FCC operations, most of the SR diesel will be converted to gasoline and lighter products with only 20% to 30% leaving the FCC in the LCO product.2 The data have also shown that the LCO made from the distillate will have cetane values of 10 to 15 numbers below that of the distillate feed but still higher than that of typical FCC LCO. Beyond standard operating adjustments, there may be investment opportunities in CDU hardware that can achieve a sharper separation between the diesel product and FCC feed streams, thus reducing the loss of potential diesel to the FCC feed. A survey of over 100 refineries indicated that FCC feed typically contains between 10 vol% and 15 vol% of material, mostly diesel, boiling below 343°C.9 In environments where gasoline production is maximized, the diesel-material loss to the FCC unit has little negative impact. However, if the objective is diesel maximization, then investments in better crude fractionation efficiency between diesel and FCC feed can be economically justified. Some options are:10 • Revamp the atmospheric distillation column to increase the degree of fractionation between diesel and atmospheric gasoil (GO) products • Revamp the vacuum column to produce a diesel product • Add a GO tower or a vacuum preflash tower in between the atmospheric and vacuum distillation columns, and recover diesel from the vacuum tower feedstock • Add a splitter column to process the light-vacuum GO (VGO) and produce a diesel stream.

Clean Fuels sel-blending component. Directionally, the yield and quality of the LCO can be improved by lowering FCC conversion and adjusting the FCC catalyst formulation. However, improvement in LCO quality is still not sufficient for the produced LCO to be considered a desirable diesel-blending component.

LCO HYDROPROCESSING OPTIONS There are various options for LCO upgrading, ranging from mild hydrotreating to full-conversion hydrocracking. Refinery diesel target sulfur levels and the cetane index determine the required LCO upgrading option. Four upgrading options are described here:11 LCO hydrotreating. A straight-run gasoil (SRGO) can meet

Regenerator bed temperature, °C

the refinery target cetane, and with a mild hydrotreating, it will be able to meet the final diesel-product specification. A small amount of LCO (10%), when added to this SRGO, can result in an off-spec final diesel product from the hydrotreater. Conventional ultra-low-sulfur diesel (ULSD) hydrotreaters use cobalt (Co)-molybdenum (Mo)-based catalyst at moderate pressure conditions, which can yield marginally on-spec prod680 675 670 665 660 655 650 645 640 635 630 500

505

510

515 ROT, °C

520

525

530

FIG. 2. Impact of ROT on heat balance. 30

Heater duty Slurry recycle

Recycle, % FF

Regenerator heater duty, MMkcal/hr

2 1 0 500

5 505

510

515 ROT, °C

520

525

0 530

FIG. 3. Adjustments to maintain a 675°C regenerator bed temperature.

LCO, vol %

EXAMPLE OF LCO MAXIMIZATION The importance of the FCC heat balance when considering various operating parameters is demonstrated in a hypothetical example using proprietary yield modeling software. The Base Case for the example is a hypothetical 40,000-bpsd FCC gasoline operation using a good-quality hydrotreated VGO feedstock. TABLE 1 summarizes the Base Case feedstock quality. The study cases, as listed in TABLE 2, are based on a constant feed preheat of 343°C, which is fairly high, providing a low catalyst-to-oil ratio for high LCO yield, while helping to maintain a sufficient regenerator bed temperature as reaction temperature is reduced. For this example, consider that the regenerator bed temperature must be sustained to complete carbon monoxide combustion, so the bed temperature is limited to not less than 675°C. In this example, the riser temperature is lowered in increments to 500°C. As shown in FIG. 2, by simply reducing the riser temperature while maintaining other independent operating variables constant, the regenerator temperature would fall well below the chosen minimum of 675°C. The first step targeting maximum LCO is to lower the equilibrium catalyst activity from 72% to 60% as limited by the 675°C bed temperature while maintaining the Base Case ROT (Case 1). After lowering the catalyst activity in the first step, the ROT cannot be decreased any further without violating the set minimum regenerator bed temperature of 675°C unless some other adjustments are made. The next adjustments are to utilize slurry recycle to elevate the regenerator temperature as the riser temperature is lowered. FIG. 3 shows the slurry recycle rates required to maintain the regenerator bed temperature of 675°C. For this example, 30 vol% is considered to be the upper limit of the slurry-oil recycle. Further reductions in ROT without increasing recycle will be enabled by directly firing fuel in the regenerator, utilizing a variable-duty regenerator fuel-injection system, as shown in FIG. 3. FIG. 4 summarizes the LCO yield from all the steps taken to increase LCO yield with decreased ROT as other operating variables are changed to maintain the regenerator bed temperature at 675°C. The first adjustment, shown on the right axis of the figure, is a lowering of catalyst activity by 12 vol% until the 675°C temperature is reached. Then, as the riser temperature is lowered to 510°C, slurry recycle is increased up to the value of 30 vol% of the fresh feedrate. For riser temperatures below 510°C, external fuel is added to the regenerator as needed to maintain the 675°C bed temperature. Finally, on the left axis of the figure, the gasoline/LCO cutpoint is lowered to achieve the ultimate LCO yield (Case 8). With the combination of low ROT and catalyst activity along with slurry recycle, a flexible regenerator-fuel-injection system can result in a constant cutpoint LCO yield of 32 vol%, while respecting the minimum regenerator bed temperature. Lowering the FCC naphtha cutpoint to 150°C in the listed example results in an LCO yield of about 50 vol%, which is more than four times the Base Case LCO yield of 12 vol%. TABLE 2 summarizes all the cases studied in this example. Applying the discussed methods still produces a significant quantity of high-sulfur, low-cetane LCO. Modern diesel quality specifications dictate that LCO must be upgraded in hydrotreating or hydrocracking units to make it an attractive, modern die-

50 Lower MAT + slurry cycle + heater + cutpoint adjustment 45 (LCO cutpoint reduced from 221°C to 175°C) 40 35 Lower MAT + slurry cycle + regenerator heater 30 Lower MAT + slurry recycle Lower MAT 25 20 15 Base Case 10 500 505 510 515 520 525 ROT, °C

530

FIG. 4. Impact of adjustments on LCO production. Hydrocarbon Processing | FEBRUARY 2013

Clean Fuels uct for a 10% LCO in the diesel pool during the start of run conditions. However, to meet the overall Euro-5 diesel specifications for cetane, density and polynuclear aromatics may require additives. Better product specifications can be achieved if the feed is processed at a higher pressure using nickel (Ni)-Mobased ULSD catalyst. To accommodate more LCO volume in the diesel pool, more selective reaction pathways should be followed to improve cetane, density and aromatic content. Aromatic saturation. Depending on the amount of aro-

matic saturation required, there are single-stage and two-stage aromatic saturation options. While the single-stage aromatic saturation process is new, the conventional two-stage process is relatively simple and established. In a two-stage process, the first-stage operation generates ULSD with low-nitrogen content for the second stage to complete aromatic saturation reactions. The second stage uses very active noble-metal-based catalyst, yielding high levels of conversion, even for monoaromatics. The drawback of ring saturation is high hydrogen consumption. The amount of LCO upgrading by this process is limited by the aromatic precursors in the feed. Selective-ring opening. Another alternative to upgrade the LCO quality is to rely on a selective-ring opening (SRO) method. SRO provides a refiner with the biggest LCO cetane and density improvements for the amount of hydrogen consumed. The challenge with SRO is that the catalyst formulation should be carefully controlled to stop the reactions from proceeding to full hydrocracking, which converts diesel to gasoline-range molecules. Mild hydrocracking. An alternative is to rely on ring opening

with mild hydrocracking (MHC) to move some of the polyaromatics into gasoline. This approach can provide substantive LCO quality improvement with lower hydrogen consumption. The di-aromatic molecules are first partially saturated in the “desulfurizing” section of the reactor and then cracked to monoaromatic naphtha boiling range molecules. The benefit of an MHC TABLE 2. Case study summary Case

Base

Riser outlet temp., °C

530 530 525 520 515 510 505 500 500

Feed preheat temp., °C 343 343 343 343 343 343 343 343 343 Regenerator bed temp., °C

702 675 675 675 675 675 675 675 675

Catalyst activity, vol%

Slurry recycle, vol%

Regenerator fuel addition, MM kcal/hr

0.8

3.5

7.6

221

221 150

Gasoline/LCO cutpoint, °C LPG yield, vol% Gasoline yield, vol%

221 221

32 24.3 22.6 21.1 19.9 19.6 17.9 16.4 16.4 67.2 63.0 62.2 61.1

60 60.8 58.4 55.5 37

LCO yield, vol%

18.2 21.3 23.2 25.5 26.6 29.3 31.8 50.4

Slurry yield, vol%

4.6

7.3

6.1

6.0

5.3

60 FEBRUARY 2013 | HydrocarbonProcessing.com

3.1

3.9

5.4

option increases with LCO content as the poor-quality diaromatic molecules in the LCO are converted to naphtha. The MHC option is different from SRO in that naphtha production is desired and the diesel-to-naphtha-yield ratio is controlled. Managing LCO. With increasing demand for diesel, coupled with its supply/demand ratio, the incentives to make high-quality diesel will remain elevated. Selective adjustments to FCC operating variables and catalyst quality can significantly increase LCO production that can be ungraded into diesel blendstock, using appropriate hydrotreating processes in an FCC-centered refinery. Balancing the FCC reaction heat demand with the heat available from combustion in the regenerator provides a framework that must be adhered to when optimizing this unit. Low FCC reaction severity, coupled with the processing of a severely hydrotreated feedstock, can make supplemental firing of the regenerator with fuel an attractive option for closing the FCC heat balance while maximizing LCO production. ACKNOWLEDGMENT An upgraded and revised version of the original paper presented at the 10th International Oil and Gas Exhibition (PETROTECH 2012), New Delhi, India, October 2012. NOTES a Commercialized system can be applied to distributing liquid fuel in the regenerator which is commercialized in the KBR SUPERFLEX process4, 5 LITERATURE CITED Eskew, B., “The diesel challenge—and other issues facing US refiners,” NPRA Q&A and Technology Forum, Champions Gate, Florida, Oct. 6, 2008. 2 Niccum, P. K., “Maximizing diesel in FCC centered refinery,” AFPM Annual Meeting, March 11–13, 2012, San Diego, California. 3 Melin, M., C. Baillie and G. McElhiney, “Salt Deposition in FCC Gas Concentration Units,” Catalagram, No. 107, W. R. Grace &Co., 2010. 4 Peterson, R. B., C. Santner and M. Tallman, US Patent 7,153,479. 5 Gilbert, M. F., M. J. Tallman, W. C. Petterson and P. K. Niccum, “Light olefin production from SUPERFLEX and MAXOFIN FCC technologies,” ARTC Petrochemical Conference, Malaysia, February 2001. 6 Hunt, D., R. Hu, H. Ma, L. Langan and W.-C. Cheng, “Recycle strategies and MIDAS-300 for maximizing FCC light cycle oil,” Catalagram, No. 105, W. R. Grace &Co., Spring, 2009 7 Silverman, L. D., S. Winkler, J. A. Tiethof and A. Witoshkin, “Matrix effects in catalytic cracking,” NPRA Annual Meeting, March 23–25, 1986, Los Angeles, California. 8 Fletcher, R., Meeting Transcript, 1997 NPRA Q&A Session—Refining and Petrochemical Technology, October 1997, New Orleans, Question 18, pg. 66. 9 Sloley, A., Refinery Process Services—FCC Network News, Vol. 35, January 2010. 10 Sloley, A. W., “Increase diesel recovery,” Hydrocarbon Processing, June 2008. 11 Flinn, N. and S. P. Torrisi, Jr., “LCO Upgrading Options: From Simple to Progressive Solutions,” 8th Russia & CIS Refining Technology Conference & Exhibition, Moscow, Sept. 25, 2008. 1

RAHUL PILLAI joined Kellogg Brown & Root’s Fluid Catalytic Cracking (FCC) team in 2008. Since that time, he has been performing process engineering design activities for grassroots FCC units, FCC revamp projects, numerous studies, technology proposals, technical service and plant startup assignments. Mr. Pillai holds an MS degree in mechanical engineering from Texas A&M University, College Station. PHILLIP NICCUM joined KBR Inc.’s fluid catalytic cracking (FCC) team in 1989, following nine years of FCC-related work for a major oil company. Since that time, he has held various FCC-related positions at KBR Inc., including process manager, technology manager, chief technology engineer of FCC, director of FCC technology, and now process engineering manager. Mr. Niccum’s professional activities have included engineering management, process engineering, project engineering, marketing, and licensing. Areas of technical strength include FCC unit design, precommissioning and startup, troubleshooting and economic optimization of FCC unit operations.

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Special Report

Clean Fuels Y.-A. JOLLIEN, Tamoil S.A., Collombey, Switzerland; and C. KEELEY, J. MAYOL, S. RIVA and V. KOMVOKIS, BASF Corp., Iselin, New Jersey

Use an innovative cracking catalyst to upgrade residue feedstock

Discuss concerns Cold-eyes review Appraise risks with workbook tool Process simulation Technical and commercial proposal

Select Catalyst and additives selection Finalize contracts and agreements

Deﬁne

Implement

Improve Form the best team

Risk minimization action plan Logistic plan Trial procedures

Routine technical discussion Optimize catalyst and additives Technical service support reports

FIG. 1. The catalyst change management process.

Develop new base case Plan to further improve performance

đ Appraise situation đ Challenge the status quo

đ Customize procedures, models and Create other tools customized đ Monitor solutions progress and optimize đ Improve understanding Deliver đ Deﬁne for measurable continuous improvement improvement

At the molecule level. The new RFCC

catalyst has a unique catalyst pore architecture, providing optimized porosity for heavy-feed molecule diffusion with selective zeolite-based cracking. In addition, the catalyst has an ultra-stable and cokeselective matrix along with ultra-low sodium (Na) zeolite. The zeolite and matrix

Ecat REO, wt%

THE TRIAL Working with catalyst development companies, refiners can fine-tune operations. The evaluation requires a wide range of tools that when selectively used, based on specific refiners needs, ensure a flawless catalyst change. FIG. 1 summarizes the key tools that were used at the Collombey refinery. Following appraisal activities, an innovative RFCC catalyst was selected to fit the Collombey operation and deliver the highest value.b The

new catalyst combines the benefit of the distributed matrix structures platform with the proximal stable matrix and zeolite platform.2–4 This combination can achieve deep-bottoms conversion with low-coke make.

Ecat TSA, m2/g

Appraise

was a residue catalyst with a high zeoliteto-matrix (Z/M) ratio and an average of 3.3 wt% of RE content. A trial was conducted using one of the competitor’s low RE products with 2.6-wt% RE. This trial was abandoned due to poor performance, increases in the LPG yield (which was the unit’s main operating constraint), bottoms yield, and catalyst addition rate. Since the driver for a catalyst change was still valid, Tamoil decided to trial a catalyst from another supplier.

3.8 3.6 3.4 3.2 3.0 2.8 2.6 2.4 2.2 2.0 1/7/07 150 140 130 120 110 100 90 80 1/7/07 50

A-3.3% RE A-2.6% RE B-2% RE B-2.8% RE 1/7/08

1/7/09

1/7/10

1/7/11

1/7/12

1/7/08

1/7/09

1/7/10

1/7/11

1/7/12

1/7/08

1/7/09

1/7/10

1/7/11

1/7/12

45 Ecat MSA, m2/g

Tamoil S.A. is a major downstream organization active in Europe and Africa. This energy company has refineries in Hamburg, Germany, and Collombey, Switzerland, in addition to distribution networks operating in Italy, Germany, Switzerland, The Netherlands and Spain. The Collombey refinery operates a resid fluid catalytic cracking (RFCC) unit. The RFCC technology provides a cost-effective, flexible and reliable means to upgrade residue feedstocks to higher-value refined products.a This unit processes a 100% residue feedstock with up to 7 wt% Conradson carbon residue (CCR) and a high contaminant metal level—the equilibrium catalyst (Ecat) nickel (Ni) is up to 6,000 ppmw and vanadium (V) is up to 6,000 ppmw. Due to the adverse rare earth (RE) market conditions in 2011, Tamoil reevaluated the operation of the Collombey RFCC unit.1 At this refinery, the base catalyst in use was the best proposed solution offered by a competitor. The catalyst

40 35 30 25 20 1/7/07

FIG. 2. Catalyst customization for the Collombey new RFCC catalyst trial. Hydrocarbon Processing | FEBRUARY 2013

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Clean Fuels

Circulating catalyst inventory composition Tamoil Collombey

đƫ *%0% (ƫ0! $*% (ƫ/!.2% !ƫ/1,,+.0ƫ.!,+.0 đƫ ƫ/!(! 0%2%05ƫ.!2%!3 đƫ +.! /0ƫ+"ƫ(+*#ƫ0!.)ƫ 0 (5/0 ƫ ĂŌƫ ƫ,!."+.) * ! đƫ %)1( 0%+*ƫ/1##!/0! ƫ+,0%)%6 0%+* ƫ +,,+.01*%05ƫ

đƫ !#%**%*#ƫ+"ƫ.+10%*!ƫ0! $*% (ƫ/!.2% ! Fresh feedrate, m3/hr

āĆĥĀăĥāĂ ĂĂĥĀăĥāĂ ĂĊĥĀăĥāĂ ĀĆĥĀąĥāĂ āĂĥĀąĥāĂ āĊĥĀąĥāĂ ĂćĥĀąĥāĂ ĀăĥĀĆĥāĂ āĀĥĀĆĥāĂ āĈĥĀĆĥāĂ ĂąĥĀĆĥāĂ ăāĥĀĆĥāĂ ĀĈĥĀćĥāĂ āąĥĀćĥāĂ ĂāĥĀćĥāĂ ĂĉĥĀćĥāĂ ĀĆĥĀĈĥāĂ āĂĥĀĈĥāĂ āĊĥĀĈĥāĂ ĂćĥĀĈĥāĂ ĀĂĥĀĉĥāĂ ĀĊĥĀĉĥāĂ āćĥĀĉĥāĂ ĂăĥĀĉĥāĂ A-3.3% RE A-2.6% RE B-2% RE B-2.8% RE

1/7/08

1/7/09

1/7/10

1/7/11

1/7/12

0.4 0.3 0.2 0.1 1/7/07

1/7/08

1/7/09

1/7/10

1/7/11

1/7/12

6 5 4 3 2 1/7/07 .96 .95 .94 .93 .92 .91 .90 .89 1/7/07 140 130 120 110 100 90 80 70 60 50 40 1/7/07

A-3.3% RE A-2.6% RE B-2% RE B-2.8% RE 1/7/08

1/7/09

1/7/10

1/7/11

1/7/12

1/7/08

1/7/09

1/7/10

1/7/11

1/7/12

1/7/08

1/7/09

1/7/10

1/7/11

1/7/12

FIG. 4. New RFCC catalyst trial feed quality and unit throughput. 9

1/7/08

1/7/09

1/7/10

1/7/11

1/7/12

8 7

Ecat Fe, wt%

0.5

7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 1/7/07 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 1/7/07

Feed CCR, wt%

7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 1/7/07 0.6

Ecat Ni, ppmw

Ecat V, ppmw

đƫ 1((ƫ0! $*% (ƫ/!.2% !ƫ/1,,+.0ƫ.!,+.0

FIG. 3. Collombey catalyst change to new RFCC catalyst.

Ecat Na, wt%

đƫ +( ġ!5!/ƫ.!2%!3ƫ+"ƫ đƫ 0 (5/0ƫ $ *#!ƫ 0%+*ƫ,( * đƫ %/ 1//%+*ƫ+"ƫ 0 (5/0ƫ"+.)1( 0%+*/ đƫ ƫ,%(+0ƫ/01 5ƫ3%0$ƫ*!3ƫ 0

*2!*0+.5ƫ +),+/%0%+*ČƫŌ

100 90 80 70 60 50 40 30 20 10 0

pared to past periods with feed CCR content ranging from 4 wt%–6 wt% (FIG. 4). Using the data represented in FIG. 4a, periods of distinct operation can be singled out, as shown in FIG. 5. As illustrated in FIG. 5, the average feed CCR during the new RFCC catalyst trial was typical for the operating period. Comparing the RFCC catalyst trial to previous operating periods, for a similar fresh catalyst addition rate, the Ecat V levels were similar; the Ni was slightly lower; the Na level was definitely lower; and the Iron (Fe) was toward the higher range of previously experienced levels. The operating data is presented in FIG. 6. Tremendous strides have been attained in catalyst technologies as demonstrated with very low Na levels (FIG. 6c). It is well

Feed CCR, wt%

bottoms cracking, an active matrix was added; thus, the new design offers a higher matrix surface area (FIG. 2c). During the define stage (FIG. 1), the catalyst provider worked closely with the Collombey refinery staff to develop a detailed catalyst change plan, logistics plan and trial procedures to minimize all risks. The technical review required input from Collombey’s procurement, planning and operation specialists, and equivalent participation from the catalyst provider. Throughout the catalyst change, the RFCC unit was closely monitored, and process simulation was conducted to forecast the long-term performance and to optimize the catalyst. FIG. 3 shows the timing of the key value-added technical service before and during the catalyst change. During the catalyst trial, a wide range of unit processing throughput was explored, and the feed quality was com-

Feed SG

are innovatively formed in a single manufacturing step. This catalyst design can provide refiners the flexibility to improve gasoline and light cycle oil (LCO) yields with low-coke make. It also improves metals tolerance and bottoms cracking. To address Collombey’s requirements, the RFCC catalyst needed customization. To minimize catalyst cost, the RE level was reduced (FIG. 2a). Even at low RE levels, the V contaminant metal tolerance was excellent because the metals passivation technology is not RE based, and the low-Na zeolite provides inherent V tolerance.b To compensate for the loss of catalyst stability/activity when reducing the RE level, the zeolite surface area was increased (FIG. 2b). A unique in-situ catalyst manufacturing process allowed increasing the zeolite to higher levels without compromising the catalyst’s physical strength. To substantially improve the

6 5 4

A-3.3% RE Average 2007– A-3.3% RE 2011 A-2.6% RE Low CCR feed

A-3.3% RE

B-2.8% RE

3 2 1

1/7/08

1/7/09

FIG. 6. New RFCC catalyst trial Ecat metals vs. previous operating periods.

1/7/10

1/7/11

1/7/12 FIG. 5. New RFCC catalyst trial feed CCR vs. previous operating periods. Hydrocarbon Processing | FEBRUARY 2013

Clean Fuels 8

8 A-3.3% RE A-2.6% RE B-2% RE B-2.8% RE

6 5

7 Dry gas yield, wt%

Dry gas yield, wt%

4 3

6 5 4 3

2 2 1 1 610 615 620 625 630 635 640 645 650 655 660 500 Average of regenerator temperature and ROT, °C

505

510

515

520 525 ROT, °C

530

535

540

0.34

0.32 A-3.3% RE High A-3.3% RE CCR Low A-3.3% RE feed CCR Average A-2.6% feed 2007–2011 RE

5 4

LPG/gasoline ratio, wt/wt

Dry gas yield, wt%

FIG. 7. New RFCC catalyst trial dry gas yield and ROT correlation.

B-2.8% RE

0.30

0.26 0.24

0.22

FIG. 10. New RFCC catalyst trial improved LPG/ gasoline selectivity vs. previous operating periods.

1.4

10 LCO/CLO ratio, wt/wt

Coke yield, wt

B-2.8% RE

7 6 5

0.4

0.2

FIG. 12. New RFCC catalyst trial bottoms upgrading vs. previous operating periods.

FIG. 9. New RFCC catalyst trial coke yield vs. previous operating periods.

30 A-3.3% RE A-2.6% RE B-2% RE B-2.8% RE

25 Slurry yield, wt%

20 18 16 14 12 10 8 6 4 60

B-2.8% RE

A-3.3% RE Low CCR A-3.3% RE 1.0 A-3.3% RE feed Average High 2007–2011 CRR 0.8 feed A-2.6% 0.6 RE 1.2

A-3.3% RE High CCR A-3.3% RE feed A-3.3% RE Average Low CCR 2007–2011 A-2.6% RE feed

75 80 Conversion, wt%

20 15 10 5 60

75 80 Conversion, wt%

20 18 16 14 12 10 8 6 4

25 Slurry yield, wt%

LCO yield, wt%

B-2.8% RE

0.28

FIG. 8. New RFCC trial dry gas yield vs. previous operating periods.

LCO yield, wt%

A-3.3% RE A-3.3% RE A-3.3% RE A-2.6% High CCR Low CCR Average RE Feed feed 2007–2011 Summer Summer Summer

20 15 10 5

5 CCR, wt%

FIG. 11. New RFCC catalyst trial LCO and slurry yield.

66 FEBRUARY 2013 | HydrocarbonProcessing.com

5 CCR, wt%

known that Na cations negatively impact zeolite stability.5 Accordingly, the new RFCC catalyst suffers less from Na acidsite neutralization and zeolite deactivation compared to other available catalysts. Since the fresh catalyst has low-Na content, the new RFCC catalyst has inherent V resistance. Furthermore, because of the low-Na content, hydrogen transfer reactions are minimized, thus preserving LCO quality at similar RE/Z levels. FIG. 7 shows that the dry gas yield is a function of the mix-zone temperature, which can be estimated using the regenerator temperature and the riser operating temperature (ROT). Despite the much higher matrix surface area (FIG. 2c), the dry gas yield trended to the lower end of the range previously experienced, as shown in FIG. 7. High levels of Fe were present in the unit feed during RFCC catalyst trial. Based on past experience, Collombey refinery was ready to use flushing Ecat to lower the Fe content of the circulating catalyst inventory. However, with new RFCC catalyst, there were no signs of catalyst surface sintering, dry gas selectivity deterioration or activity loss. Therefore, flushing Ecat was not necessary. The new RFCC catalyst has high porosity and, therefore, is resistant to Fe pore-plugging deactivation. Furthermore, by comparing the dry gas yield to periods of distinct operation (FIG. 8), the new RFCC catalyst dry gas yield is similar to the average dry gas yielded with the base catalyst despite the lower RE level and much higher matrix content (FIG. 2c). FIG. 9 shows a similar result for the coke yield. The LPG yield was controlled by the new RFCC catalyst despite the low RE level, and the gasoline yield remained similar. Thus, the LPG/gasoline selectivity was even better than the summer season performance of the base catalyst, as shown in FIG. 10. This significantly improved LPG/gasoline selectivity. The new RFCC catalyst removed the unit’s main operating constraint. However, if a refinery needed to maintain the same LPG yield, then a lower RE/zeolite catalyst formulation, either on its own, or in combination with ZSM-5 additive could be used to convert the gasoline to LPG. With the new RFCC catalyst, bottoms upgrading was improved. FIG. 11 shows increased LCO yield and decreased slurry yield—also known as clarified oil (CLO).

Clean Fuels FIG. 12 shows that this amount of bottoms

upgrading is a record for the Collombey unit. When the trial results were considered along with the dry gas yield data (FIG. 8) and coke yield data (FIG. 9), the refinery data proved that the new catalyst’s added active matrix truly can achieve coke-selective bottoms upgrading. Final word. Tamoil’s Collombey refinery worked very close with a new catalyst supplier to remove the main operating constraint and significantly improve the unit profitability. Several project goals were set and attained. The performance of the customized new RFCC catalyst, despite the low RE content and higher matrix surface area, exceeded Collombey’s expectations. For similar fresh feed quality and feedrate, and similar fresh catalyst addition rate, compared to the base catalyst, the new RFCC catalyst: • Was 0.5 wt% lower in RE content • The plant LPG/gasoline selectivity was improved • The dry gas yield was similar or in the lower range

• The coke yield was similar • An outstanding improvement in the bottoms cracking was achieved with record LCO yield and significantly reduced slurry yield. The customized new RFCC catalyst with 2.8 wt% of RE substantially improved the unit’s profitability, which is estimated using standard feed, product and utility prices to be: • +1.2 $/bbl vs. the competitive low RE catalyst with 2.6 wt% RE • +0.4 $/bbl vs. the competitive high RE catalyst with around 3.3 wt% RE. NOTES The RFCC technology installed at the Collombey refinery is the R2R process offered through the FCC alliance between Axens (technology developer and licensor), IFP Energies Nouvelles (R&D), and Technip/Shaw (licensing and engineering innovation). b BASF’s Aegis catalyst, introduced to the market in 2010, combines the benefit of BASF’s Distributed Matrix Structures (DMS) platform with BASF’s Proximal Stable Matrix and Zeolite (Prox-SMZ) platform. This catalyst uses an integral Ni trap and separate non-RE based V trap.2–4 a

LITERATURE CITED Available online at HydrocarbonProcessing.com.

YVES-ALAIN JOLLIEN is a process engineer for Tamoil S.A., Raffinerie de Collombey. With over six years of experience, he is the FCC unit process engineer. Mr. Jollien holds an MEng degree from the Swiss Federal Institute of Technology Lausanne; later, he studied for one year at the IFP School near Paris. CARL KEELEY is the marketing manager, refining catalysts for Europe, Middle East and Africa, BASF Corp. He earned his MEng (Hons) in chemical engineering and applied chemistry from Aston University, UK. Mr. Keeley is a professional engineer (CEng). He has over 12 years of experience. Previously, he worked with UOP, BP and Dow. JEREMY MAYOL is Tamoil’s technical account manager, BASF Corp. With over 15 years of experience in the hydrocarbon processing industry, he is a recognized technical specialist in FCC unit operation. He has worked for BASF for four years. Prior to this, Mr. Mayol spent 12 years working for INEOS and BP. STEFANO RIVA is the technical service manager, refining catalysts for Europe, Middle East and Africa, BASF Corp. With over 20 years FCC experience: 10 years with Engelhard and BASF in technical sales and technical service; two years with Tamoil and eight years working in the technical support group at ExxonMobil. DR. VASILEIOS KOMVOKIS is the technology manager, refining catalysts for Europe, Middle East and Africa, BASF Corp. He holds BS and MS degrees in chemistry, and a PhD in chemical engineering from Aristotle University. He was a researcher at CPERI Institute of Thessaloniki and a research professor at the University of South Carolina.

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Special Report

Clean Fuels S. BROWN, Invensys Operations Management, Houston, Texas

The next generation of interfaces for engineering software Today you can point your smart phone at a bag of rice and see recipes, reviews and directions to a store that sells it at a lower price. So why can’t you point it at a distillation column and see its internal flows and properties? Or at a storage tank and see its contents and scheduled movements? This information is probably available in electronic form somewhere, so there is no technical reason why the next generation of process software shouldn’t provide engineers with the rich user experience we are growing accustomed to in our daily lives. The following pages will offer insight into how the user interfaces to the next generation of process engineering software might look, how they will benefit their users and the key enablers that will make it all possible. Visualization. It’s well known that the brain is better suited to identifying patterns and correlations in images, rather than in tables of data. This is why so many engineers are adept Excel users, skilled at transforming numerical data into graphs of various kinds. Data visualization is an active field of research in computer science, the social sciences, and even psychology, where academics study how to best present large data sets for human comprehension. These days there is an emphasis on interacting with data, rather than just presenting it. A good visualization of a heat exchanger fouling application, for example, would allow its user to quickly change the type of plots, the variables displayed and transformations of those variables. In addition to showing temperatures and flows, the user should be able to show the daily averaged log mean temperature difference for each heat exchanger, even if these values are not in the data set. Stanford University’s Polaris system, now commercialized as Tableau, is an example of a tool that was born of such research. Using simple drag-and-drop gestures, its users can create and interact with sophisticated visualizations and even publish them on web pages for others to explore. For many inspiring examples, see their gallery of interactive visualizations.1

EXAMPLE 1 As part of an initiative to reduce flowmeter uncertainty, a refinery has deployed software that calculates several quality-indicating statistics for each of its several hundred meters. In the past, the results would have been presented to the engineer in a multi-column report; however, even this modest-sized data set is difficult to comprehend by looking at the raw numbers. FIG. 1 shows the data table rendered in Google’s motion chart, a tool originally developed to analyze public health and demographic information.2

Each “bubble” represents a meter and simultaneously displays four statistics: X and Y coordinates, bubble size and color. In this particular data set, large values indicate problems; thus, large bubbles near the upper right corner are of primary interest. Color indicates the software’s best attempt to classify the meter fault. Hovering over a bubble displays summary information about that meter. For example, the plot indicates that meter HGO is in gross error, probably due to a problem with its compensating thermocouple (TI207). The user can then switch to the trend tab, and view historical values for this meter.

EXAMPLE 2 While the familiar process flow diagrams (PFDs) effectively convey equipment connectivity and material flow, they cannot show much quantitative information, because there is simply not enough room. This is especially unfortunate for process simulators, which could display any calculated value the user desires. One solution to this overcrowding problem is “semantic zoom,” as shown in FIG. 2, where the information displayed increases as the user zooms in and space becomes available. FIG. 2 also shows how the thickening and coloring of streams can very intuitively increase the information content on the PFD. Even at the medium zoom level, it is clear that a high rate (thick stream) of cool (blue) material is being heated on the tube side and that the separator produces much more liquid than vapor. FIG. 3 shows part of a refinery-planning model, where the stream thickness is proportional to the flowrate, and the color indicates flows that the optimizer drove to their upper (blue)

FIG. 1. Bubble plot made with a Google motion chart. Hydrocarbon Processing | FEBRUARY 2013

Clean Fuels or lower (green) limits. A quick glance tells the user that the planning software recommends: • Maximizing the coker throughput • Minimizing the FCC throughput • Producing very little fuel oil. As always, interactivity is key, and the user should be able to easily change the variables that determine the stream formatting. For example, users might thicken streams based on their metals content in order to understand why the coker is favored. TABLE 1 shows other stream formatting themes. Overlaying data on a PFD can be enlightening; however overuse can defeat its purpose—it is hard to call attention to the truly noteworthy streams if three-fourths of them are colored.

EXAMPLE 3 Certain process modeling applications naturally yield very large PFDs, and some existing simulators manage this complexity with features such as: • Subflowsheets allow the user to collapse groups of objects into blocks that can be accessed in a separate view. For example, the crude distilling unit in FIG. 3 actually represents the objects that make up the crude unit. For a planning model, there might be a few sub-objects, but for a real-time optimization (RTO) model, this subflowsheet might encapsulate hundreds of objects. Double-clicking on the CDU icon would launch

Zoom

HX4

HX3

200°F 10 Mbd

360°F 20 Mbd 130°F

110°F 100 Mbd

HX3

205°F

Sep

Zoom

another flowsheet that includes the preheat train, desalter and atmospheric and vacuum columns. • Queries allow the user to find model values that meet certain criteria. These are often exported to Excel for sorting, graphing and further analysis. • Layering allows the user to segregate certain types of objects into different drawing layers that can be shown or hidden. For example, by putting the process models in one layer and the instrumentation and control objects in another, the user can temporarily hide the instrumentation layer to get a clearer view of the underlying process. Flowsheet and tabular views of a process provide different benefits to the user, and combining them is even better. FIG. 4 shows how a simulator could simultaneously display data at three different levels of information density: • The table at the bottom shows the result of a query, in this case for large contributors to a refinery’s economics • The top-right pane shows the “30,000-foot view” of the flowsheet, with the query results marked using zoom-invariant pushpins; this view provides context for the quantitative information in the table view. The Neighborhood view on the left shows one object and its nearest neighbors. Its relatively high zoom level allows it to display more numerical information, but less contextual information than the flowsheet view. In FIG. 4, it shows a glimpse into the reformer subflowsheet. A key feature is that all three views are synchronized to the same selected object. Here the user has selected the reformer operating cost, by clicking on either the table item or the pushpin. This automatically selects the corresponding object in the other two views. By combining the views in a single application, the user doesn’t need to zoom in and out or switch to a detached report to see the needed information. The pushpins that mark the query results can convey more information than just the location of these “points of interest.” By using different shapes and colors, they can also bring two pieces of qualitative information onto the flowsheet. In this example, color indicates the sign of the cashflow and shape indicates the trend, as shown in FIG. 5.

HX4

Data aggregation and contextualization. Before you can FIG. 2. Semantic zoom.

create insightful visualizations, it is necessary to gather the raw data into one place for the visualization tool to consume. Modern process plants are awash in data, including from the Historian, distributed control system, laboratory information management system and scheduling systems. Steady state simulators can act as “soft sensors,” calculating unmeasured and immeasurable values, e.g., column tray efficiency and dynamic simulators that can predict future values. To these, add maintenance, yield accounting and transactional information and the challenge becomes making sense of it all. Refiners who can intelligently anaTABLE 1. Sample stream formatting themes

FIG. 3. Large PFD divided into subflowsheets.

70 FEBRUARY 2013 | HydrocarbonProcessing.com

Application

Stream thickness

Stream color

Energy study

Energy ﬂow

Temperature

Utilities study

Hydrogen rate

Hydrogen fraction

Economic study

Cash ﬂow

Stream price

Clean Fuels lyze data in a broad context—rather than in isolation—are in a position to make smarter decisions. Aggregation brings together disparate data to achieve value that exceeds the sum of its parts. For example, while GPS navigation software is useful, it is more valuable when it includes live traffic information and the locations of nearby restaurants. If your crude unit’s furnace inlet temperature has sharply decreased over the last week, you might combine calculated fouling trends with measured operational data to work toward the root cause and corrective actions. Bringing all of this data together into a single view might reveal obvious correlations. For example, low flow, increasing crude-side pressure drop, and a recent switchover to high asphaltene crude would suggest crude-side deposits on certain preheat exchangers. A FIG. 4. Multi-resolution view of a refinery model. good aggregator would also help answer questions like: What crudes was I running when I observed a similar fouling trend during the last three years? 1 2 3 4 In practice, aggregation can be a difficult task that involves gathering data from different sources, which might not communicate well with the target visualization app or might reside on Unchanged Decreased At upper Near upper isolated parts of the corporate network. Fortunately, the widePositive cash ﬂow Negative cash ﬂow bound bound spread adoption of open data standards, like structured query FIG. 5. Using pushpin shape and color to convey information. language and object linking and embedding for process control, has mitigated these difficulties, and several commercial products exist to simplify data aggregation within the process industries. the “h” key—though not the key itself—if the previous character was a “t.” This is because an “h” is far more likely to follow a “t” than is its neighboring “g,” “b,” “n” and “j,” whose hit targets Pairing the interface to the device. Six years ago, smart will be shrunken. Such dynamic resizing opportunities will unphones weren’t so smart and tablets were almost nonexistent. doubtedly exist in process engineering software. Now both are ubiquitous and offer new ways to interact with plant data. Software vendors might be tempted to serve up data on a website accessed through each device’s browser. While this Pairing the interface to the user. Software vendors will one-size-fits-all strategy is easy to develop, it fails to leverage see their products used more if they provide comfortable interthe specific strengths of the devices. A better strategy is to defaces to a wide variety of users. This is done now, to a certain velop custom apps tailored to the device. This is especially true extent, using localization, where text, units of measure, and nufor smart phones, where the limited screen space must not be merical values are displayed according to local standards. squandered. In contrast, the large multi-pane view shown in FIG. Extending this concept, the next generation of process software will also provide interfaces customized to the user’s role, 4 would be useful only on a large PC screen or dual monitors. which indicates how they will interact with the data. Providing Touch is different. Touch-based interfaces require a funmultiple interfaces allows the software to hide complexity from damental redesign of graphical user interfaces. The pointing users who neither need nor desire it. Using a process simulator device (a finger) does not have the precision of a mouse, so as an example: hot-spots cannot be too close together. It is also attached to • A manager would examine results, but never run the a large object (a hand) that can block large portions of the model. For instance, a dashboard would be used to view screen. A traditional PC menu that drops down from the top coarse-grained information, like averaged throughput and ecoof a window could be obscured by the user’s hand on a tablet. nomics of the major process units. The manager would have This is why many apps written for touch devices rely on swipeno knowledge that the values were produced by a model that from-the-side gestures. Left-handed users will typically find it combines plant measurements with sophisticated data reconeasier to view data on the opposite (right) side of the screen ciliation techniques. than right-handed users, and a good touch interface should • A planner might need to change feeds, run the model and adapt itself to the user’s handedness. view results. The planner’s Excel-based interface would proOne way to make touch devices more forgiving of “fat finvide features to line up and run hundreds of case studies and gers” is to dynamically resize hit targets. For example, an Engcompare the results. He or she would never see the flowsheet lish language e-mail program might enlarge the hit target for Hydrocarbon Processing | FEBRUARY 2013

Clean Fuels view of the underlying model and could not change parameters like unit yields. • A process engineer working on a debottlenecking study would use the flowsheet interface, since he will experiment with adding new equipment or changing operating parameters. He or she is interested in the details like column hydraulics, catalyst activity, and exchanger fouling.

EXAMPLE 4 Lisa supports several RTO models deployed in her refinery. These models run unattended and make significant money for the organization by calculating optimal control targets. They also calculate and historize equipment performance indicators like fouling, efficiency and meter error. Lisa’s goal is to help maximize the utilization of these RTOs, and she uses a dashboard to notify her of problems and to facilitate basic troubleshooting. She configures the dashboard through her company’s information server by subscribing to events of interest from a very large list. Users in different roles will select different items for their personal dashboards. While away from her desk, Lisa receives an instant message indicating that an event she subscribes to has triggered with an error status. She logs on to the dashboard app on her smart phone and sees the tiles on the left of FIG. 7. The red tile indicates the problem is in the crude unit, so she selects it to check Notify me of warnings:

E-mail

Instant message

Phone call

Notify me of errors:

E-mail

Instant message

Phone call

Value 10% 90%

Action Warning Warning Error Warning Error Warning Error

Event Throughput decreased by more than... Percent successful runs less than... Optimized targets rejected Percent successful runs less than... New ﬂow meter in gross error Cost of heat at exchanger fouling exceeds... Ship arrival delayed by more than...

90% 500 $/day 36 hours

FIG. 6. Part of an information subscription dialog.

the details. Presenting the key performance indicators (KPIs) as a bar chart (middle of FIG. 7) facilitates interactivity on the smart phone’s small screen, since the bars are easy to distinguish and select for further drill down. The same would likely not be true if all six values were presented as separate lines in a graph, which might be the better choice on a PC. The bar chart compactly shows the KPIs on three scales: annual range on the x axis, weekly range on the grey bars and daily range with the red and green lines. A quick glance indicates that the RTO model decreases throughput to a weekly minimum value, while increasing hydrogen consumption and decreasing energy consumption. Heat exchanger fouling is not an expensive problem at this time. Lisa presses the throughput bar, whose red border highlights a drop of over 10% in throughput. This launches a trend (right side of FIG. 7) of crude throughput and sulfur content. The “?” badges indicate times where relevant information is available, such as product analysis from the LIMS system or crude changeover information from the scheduling system. From here, she can drill down into maintenance logs—perhaps an equipment problem has caused a bottleneck in the hydrotreating section that would explain the throughput cut for this high-sulfur crude. She instead chooses to check the refinery’s CDU forum (FIG. 8), a Facebook-like tool where plant personnel share information. Lisa wants to discuss the issue with Jacob, who the forum indicates has been working with Bob to explain the throughput cut. The orange dot by Jacob’s name indicates that he is currently in a meeting, so she calls Bob instead. Note that part of this application’s strength comes from the information server’s ability to aggregate data from the historian, online model, maintenance log, crude assay library, and even the site’s shared online calendar. Enabling technology and methodologies. The interfaces described in the presented examples are possible due to a combination of innovative technologies and software development methodologies. Hardware: The popularity of smartphones and tablets makes it commercially worthwhile for software vendors to de-

FIG. 7. A) Initial status screen; B) Key performance indicators summary view; and C) Trend of crude rate and sulfur.

72 FEBRUARY 2013 | HydrocarbonProcessing.com

FIG. 8. Collaboration features.

Clean Fuels velop apps that leverage their unique feature sets. Their touchbased interfaces will challenge software providers to deliver engineering information in the fast-and-fluid manner that users of these devices expect. Software technology and standards: It is easier than ever before for software engineers to build sophisticated applications by combining “loosely coupled” components. This is due largely to the popularity of modern architectures, like service oriented architecture (SOA). Because loosely coupled components are largely independent of each other, they can be individually installed, patched, and even swapped out when something better comes along. For process simulators, components might include thermodynamics, solvers, model libraries, data visualizers and flowsheet drawing toolkits. Even without SOA, simply adhering to industry standards like OPC and CAPE-OPEN lets end users combine the best features of disparate and even competing applications into custom solutions. For instance, the widespread adoption of OPC enables simulators and historians to share calculated and actual plant data. The smart phone market has several dominant technologies, led by iOS and Android, so it is risky for software developers to bet on a single platform. In the past, it has been expensive to target all of them; however, thanks to new software toolkits, like the opensource PhoneGap, developers can deploy their app to essentially all mobile devices from a single HTML5 or Javascript code base. Software development methodology: Finally, it is important to note that the process of creating software has also

HYDROCARBON PROCESSING

undergone important improvements in recent years. The latest methodologies are inspired by lean manufacturing principles that strive to minimize waste and work-in-progress. These techniques, known as “agile,” prescribe developing functionality in many short cycles, i.e., a few weeks, with the goal of getting working (if not polished) features into users’ hands for early and frequent feedback. Early feedback is critical; it allows software providers to make course corrections when it is relatively inexpensive to do so. Increased usability and power. The ever-changing world of

hardware and software not only allows, but compels, software vendors to build far richer user experiences than the current generation of products. Users can expect access to more data and better ways to interact with it. What was once a single engineering application will likely have several interfaces, tailored to the user’s role and the device he or she uses to access the app. The resulting benefit to the process engineering industry will be decision-support tools with greatly increased usability and power. LITERATURE CITED Complete literature cited available online at HydrocarbonProcessing.com. SCOTT BROWN is a consulting engineer within Invensys Operations Management, concentrating on the company’s SimSci-Esscor software products. During his 19 years with the company, he has been a developer of ROMeo, the company’s online optimization software, and has authored training classes. Mr. Brown has a PhD degree in chemical engineering from Princeton University.

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Special Report

Clean Fuels T. THOM, Calumet Superior LLC, Superior, Wisconsin; R. BIRKHOFF and E. MOY, Badger Licensing LLC, Cambridge, Massachusetts; and E-M EL-MALKI, ExxonMobil Research and Engineering Co., Fairfax, Virginia

Consider advanced technology to remove benzene from gasoline blending pool Under present clean-fuel regulations, specifically Mobil Source Air Toxics II (MSAT II), US refiners must reduce the benzene content in gasoline to 0.62 vol% on an average annual basis. This rule went into effect Jan. 1, 2011, for large refiners; small refiners received deferments until 2015. In Europe and many other countries, a 1 vol% maximum benzene level in gasoline is also in effect. Other regions are expected to adopt similar clean-fuel regulations. For refiners, the challenge is to meet these tightening gasoline specifications for benzene costeffectively without significant octane loss.

CHALLENGES Several approaches are available to reduce benzene levels in finished gasoline. Naphtha reforming is the predominant refinery benzene source. Accordingly, preventing the formation of benzene in the reformer is accomplished by prefractionation of the naphtha feed by removing benzene precursors. However, for many refiners, prefractionation of the reformer feed does not provide sufficient benzene reductions to achieve the 0.62 vol% in the gasoline pool. Alternatively, converting the reformer-produced benzene is done downstream of a reformate splitter. Benzene containing the light-reformate fraction from this splitter is sent to a hydrogenation reactor where benzene is converted to cyclohexane. Both strategies incur octane loss and add extra burdens onto the hydrogen balance for the refinery. A third approach is benzene extraction for the petrochemical market. While petrochemical benzene can be an attractive product, significant investment is required to recover benzene unless the refinery has existing facilities or spare capacity for such a process. It is very difficult to justify this investment on a small scale. An alternative technology, reformate-aklyation process, can provide a low-cost solution for refiners to meet the benzene regulation without the octane loss and hydrogen debits associated with other processing options.1

8,000 bpd. Prior to the acquisition by Calumet, this refinery was managing the MSAT II benzene compliance with reformer feed precursor removal through a naphtha splitter installed upstream of the reformer in 2010. In addition, this refinery purchased credits from other refineries within the organization’s network. The decision to install technology was made in 2010. Initially, it was economically driven to counter the losses from the reduced reformer feedrate. Later, the new unit facilitated the sale of the refinery, as purchasing benzene credits became a mute issue. In the decision-making process, octane losses were mostly weighed against necessary investments to increase hydrogen production due to losses via the reformer. At this time, with the reformate-alkylation unit in full operation, this refinery easily met the 0.62 vol% specification without requiring credits. New technology. The advanced reformate-alkylation process catalytically converts benzene into high-octane alkyl-aromatic blending components by reacting a benzene-rich stream with light olefins, such as ethylene or propylene.1,2 In a typical application, the new process reduces benzene concentrations in reformate by reacting benzene contained in a light-cut reformate with refinery-grade propylene from a fluid catalytic cracking (FCC) unit over a proprietary zeolite catalyst. Typical benzene concentration in a light-cut reformate, produced by the reformate splitter, ranges from 10 vol% to 30 vol%. FIG. 1 is a simple flow diagram of the new reformate-alkylation process. Key features include: • Fixed-bed catalyst technology. This advanced process uses a fixed-bed, liquid-phase reactor with low utility requireLight reformate

Reformate

CALUMET SUPERIOR REFINERY The refinery in Superior, Wisconsin, was acquired by Calumet Superior, LLC, in October 2011. At that time, the benzene-reduction project was in progress. The Superior refinery has a nominal crude capacity of 36,000 bpd, along with a semi-regenerative catalytic reforming unit with a capacity of

Reformate splitter

Propylene

LPG

Mogas

Reformate alkylation

Heavy reformate

Stabilizer

FIG. 1. Process flow diagram of reformate-alkylation technology. Hydrocarbon Processing | FEBRUARY 2013

Clean Fuels ments. The reactor can be a single bed (stage) or multiple beds, depending on the benzene content of the feed and desired benzene conversion. In revamp projects, it is possible to retrofit existing tubular or fixed-bed reactors for the new application. • Catalyst. The process uses a proprietary high-activity zeolite catalyst with long cycle lengths. In addition, the catalyst is regenerated ex-situ to further extend service life. • Stabilization. Propane fed to the unit with propylene is removed from the reformate-alkylation product in a stabilizer. It can produce a propane product of HD-5 quality. Product from the reformate-alkylation unit is a light reformate with a reduced Reid vapor pressure (Rvp). FCC propylene Benzene-containing feedstock

2-Stage once-through reactor system

Propane

Stabilizer

Reformate alkylation product

Besides benzene reduction, the process provides several advantages. The reaction of benzene with light olefin results in a volume swell, which largely depends on the benzene content of the feed and degree of benzene conversion. Also, an octane gain of 2 to 3 numbers of (R+M)/2 in the total reformate is typical. The advanced technology offers reformer flexibility, since it allows refineries to process the full-range naphtha feed in the reformer, thus increasing hydrogen production along with significant octane gain.

THE PROJECT Before selecting the advanced reformate-alkylation technology for the project, the licensor performed a pilot study using reformate provided by the refinery.3 With the pilot-plant product, the refinery conducted blending studies to verify the product properties and blending value. The refinery evaluation matched the estimates provided by the licensor. A technology license was executed in July 2010 and preparation began for the new process design.3 Since the refinery regularly

FIG. 2. Flow diagram of reformate-alkylation unit at Calumet’s Superior, Wisconsin refinery.

FIG. 3. Calumet’s Superior refinery reformate-alkylation unit was constructed in modules.

76 FEBRUARY 2013 | HydrocarbonProcessing.com

FIG. 4. Side view of Calumet’s new reformate-alkylation unit.

Clean Fuels sells its propylene to the US Gulf Coast market, a reactor conan increase of about 4 points octane (R+M)/2 across the unit, figuration was selected to minimize propylene consumption which is equivalent to an increase of about 2 to 3 points on the and further optimize the process economics. FIG. 2 is a flow basis of total reformate. The new unit has enabled Calumet to diagram of the new reformate-alkylation unit. The recently installed reformer naphtha feed splitter was changed to operate as the reformate-product splitter Tighter gasoline specifications challenge for the new reformate-alkylation unit. Two new benhow to handle benzene precursors in lightzene alkylation reactors and a new product stabilizer with all associated equipment were installed. cut reformate cost-effectively and maintain Calumet had an aggressive timeline for the projoctane levels for final blending. ect execution with mechanical completion targeted for November 2011. Given the climatic conditions at the refinery location, the short seasonal construction window was given full consideration. Due to close coopimprove the hydrogen management within the refinery. The eration with the licensor, collaboration with selected detailed Calumet Superior reformate-alkylation unit is designed to engineering contractors and utilization of selected modular process 5,500 bpd of feedstock. construction, Calumet was able to achieve mechanical completion ahead of schedule and startup of the unit within 16 Benefits to the Superior refinery. The new reformatemonths.3 Long-delivery equipment were ordered shortly after alkylation unit was designed, constructed and commissioned on an aggressive project timeline. This project applied creative project kick-off. The licensor provided information that aland forward-thinking execution strategies. The new unit had lowed Calumet to quickly submit applications for regulatory an installation cost of approximately $19 million, within the permits.3 Using modular design accelerated the construction original budget allocated at the early stages of the project. With and minimized the footprint of the new unit within the refinthe new unit at the Superior refinery, Calumet complied with ery. Six separate structural modules containing equipment, the MSAT II regulations for benzene. In addition, the project piping and instrumentation were delivered to the refinery to provided several economic benefits with a simple investment create a tri-level structure. The major vessels, such as alkylapayback in approximately 20 months: tion reactors, stabilizer and pumps, were placed on the perim• With the new technology, Calumet meets benzene cometer of this tri-level structure, as shown in FIGS. 3 and 4. pliance while allowing for full reformer operation. Recovering more hydrogen at the reformer has averted installing a hydroUnit operation. Initial plant commissioning activities begen unit. gan in mid-November 2011 with assistance of operations and • With the additional octane increase, Calumet can operate technology experts from the technology licensor providers.2 the reformer at less severity to produce more gasoline volume. Catalyst was loaded November 9–10, and, after a subsequent • With the new unit, benzene compliance is achievable, as two-week period to set up rotational equipment and process shown in FIG. 5. The benzene level is consistently maintained controls, the unit began operations on December 1, reaching steady-state operation within a matter of days. Operating below 1 wt%. When the product is blended in the gasoline and process control strategies were fine-tuned in the followpool, the Calumet refinery meets the 0.62 vol% maximum ing weeks. At the end of December, the startup was officially benzene level. completed. • The product is fully blendable into the gasoline pool. The operation of the new unit was straightforward and easy NOTES to control. Minimal staffing is required, one board/field op1 BenzOUT reformate-alkylation technology was developed by ExxonMobil erator per shift. The unit is operated without any online analyResearch and Engineering Co. (EMRE) and is licensed by Badger Licensing LLC. 2 sis, and one daily set of samples. Performance exceeded design In December 2009, EMRE and Badger agreed to jointly market BenzOUT technology to third parties. Since then, licenses and related engineering services are expectations, in terms of benzene conversion and propylene provided exclusively through Badger. consumption. The product quality is consistent with projec3 Badger Licensing LLC. tions made at the onset of the project. Calumet benefited from TIMOTHY THOM is the engineering manager at the Calumet Superior refinery. He is responsible for turnaround planning and capital project management.

2.5

Benzene, wt %

2.0

RONALD BIRKHOFF is director of business development for Badger Licensing LLC. He is responsible for commercialization of new process technologies.

1.5 ERIK MOY is a technology manager at Badger Licensing LLC in Cambridge, Massachusetts. He is responsible for the BenzOUT technology design and development activities.

1.0 0.5

0.0 Time

FIG. 5. Benzene concentration in treated reformate by the new technology.

DR. EL-MEKKI EL-MALKI is the licensing manager at ExxonMobil Research and Engineering Co., located in Fairfax, Virginia. He is responsible for licensing ExxonMobil downstream technologies in the Middle East and Africa regions. In addition, he is the BenzOUT portfolio manager responsible for the marketing and licensing of EMRE’s reformate alkylation (BenzOUT) technology for benzene reduction in gasoline. Hydrocarbon Processing | FEBRUARY 2013

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IMPROVE THE PERFORMANCE OF YOUR EXISTING STEAM SYSTEM R. O. PELHAM, Merrick & Company, Aurora, Colorado

Refinery and petrochemical plant engineering staffs must understand complex-wide steam systems, and they should seek to improve the performance of these systems. Here, the adaptation of existing facilities in response to process changes in the refinery or petrochemical complex is examined. Pursuant to the January 2013 article, “Improve your plantwide steam network,” this article is concerned with improving the performance of existing steam equipment. Several articles1–3 have been written over the years regarding ways to improve steam systems. These articles have mainly focused on specific elements or “pieces” of the total system, and they touch on the timeless issues of boiler performance, steam turbines, steam reboilers/heaters, letdowns, process uses, condensate recovery, steam traps, deaerating, etc. Also highlighted are some aspects that generally receive less attention, or that are altogether ignored. Steam system weaknesses and inefficiencies. Industry has

not developed a specific metric that defines overall steam system performance. For the most part, it is left to the knowledge and experience of the engineers and operators to observe and develop improvements. Since the “utility system” engineer is frequently chosen from the ranks of younger engineers, and since operations personnel are responsible for their process area only and not the refinery-wide steam system, progress can be slow. After completing all the steps discussed in Part 1 of this article, the total system is understood—but what comes next? How does one go about improving the system? There are a number of items to look for and consider. The following discussion tracks a logical material flow through the steam system, starting with the feed (i.e., cold, demineralized water), and continuing with steam generation, steam uses (and abuses) and, finally, condensate recovery. Preheating treated makeup water to deaerator. Most energy-conservation schemes in refining come down to one of two approaches: either not using the energy in the first place, or recovering more energy from the multitude of streams being cooled in air or water coolers. In the latter case, the limitation is not the heat available, but rather having sufficient ΔT to recover the heat (i.e., second law of thermodynamics efficiencies, commonly referred to as “pinch” technology). The colder the sink into which heat is recovered, the more ΔT is available. The two largest cold sinks in a refinery are cold crude and cold deaerator makeup water. Heating cold crude gets attention in crude preheat trains, and effort is made to practically and economically recover all heat from crude unit product streams prior to air and water cooling. The equivalent opportunity to maximize recovery of waste

heat against cold makeup water rarely receives equivalent attention. Instead, the bulk of water preheating is done with low-pressure (LP) steam. FIGS. 1 and 2 illustrate a refinery setup with letdown stations at various locations throughout the plant. Some stations were metered and some were not. Steam to the deaerator was not metered. Knowing the water rates around the deaerator allowed a simple deaerator heat balance, which gave an accurate measure of steam rate—an eye-opening occurrence. Another attention-drawing factor was the rates through different letdown stations in the refinery. Operators discovered that the equivalent of an entire fired boiler was devoted to the sole purpose of generating high-pressure (HP) steam, which was then let down and used to preheat cold water to the deaerator. Using waste-heat streams eliminated a fired boiler. Since deaerator feedwater still contains oxygen, heating to the 100°F–180°F range requires stainless steel plumbing for exchanger and piping to the deaerator. A new approach, which may reduce capital costs, is to deaerate the cold feedwater using membrane technology.4 This approach is now being introduced at some US refineries. Boiler firing and efficiency. Clearly, if fired boilers operate at 75% efficiency, it is unlikely that the steam system can be deemed “efficient.” Issues include standard ones, such as recovering stack heat with economizer sections, and air preheating. A good stack temperature objective is 400°F–450°F. The aim of control furnace firing is to maintain low excess air (e.g., less than 20%). HP boilers

HP header 450 Mlb/hr PC

Intermediate-pressure header 120 Mlb/hr

255 Mlb/hr PC

MP header > 50 Mlb/hr PC

LP header 230 Mlb/hr Deaerator

Softened makeup water, 80°F

FIG. 1. Deaerator feedwater heating, no deaerator feed preheat. HYDROCARBON PROCESSING | HEAT TRANSFER 2013

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HEAT TRANSFER Boiler blowdown. Over the past 20 steam system surveys, the author has observed blowdown rates of between 3% and 13% of the boiler feedwater. The major cost of a high blowdown rate is the cost of steam used to heat the cold deaerator feedwater. Additional costs are incurred from raw water cost, water-treating cost and sewage cost for the blowdown. Two factors are in play. First is the boiler feedwater quality. Generally, in refineries, the feedwater quality is well understood, and blowdown percentage (or cycles) is set accordingly. If the blowdown target is high, the only solution is improved water treating. The second factor is blowdown control. Ideally, blowdown is controlled automatically in ratio to boiler feedwater. In practice, however, many boilers do not have automatic ratio control. In that case, blowdown flow may be on flow control. A setpoint is frequently used to ensure that the blowdown is nevHP boilers Δ ≈ -120 Mlb/hr PC

HP header 330 Mlb/hr PC

Intermediate-pressure header 0 Mlb/hr

255 Mlb/hr PC

MP header > 50 Mlb/hr PC

LP header 110 Mlb/hr Deaerator

160°F

Softened makeup water, 80°F

Low-level waste heat ≈ 120 MMBtu/hr

FIG. 2. Deaerator feedwater heating, with deaerator feed preheat.

HP boilers

HP header

er less than the target percentage. Unfortunately, since steam rate varies, blowdown is usually too high when the boiler load is less than the maximum. Worse still are boilers where no blowdown control is present; blowdown must be done manually, by outside operators. In this case, the actual blowdown rate is a guess. Given the consequences to the boiler of too little blowdown, the actual blowdown is set high as a precaution. When blowdown is high (e.g., over 5%), cost should be calculated, as explained in the preceeding article published in January 2013. That cost should be compared to the cost of installing automatic blowdown controls. Header pressure control. On an overall basis, most steam systems control the HP header pressure by pressure control on boiler output. Intermediate and LP headers are then controlled by letdown from above to maintain the target pressure at the lower level. The general scheme is shown in FIG. 3. A few refineries and petrochemical complexes run HP superheated boiler steam through large, double-extraction turbines. The turbines generate power. The turbine extraction rates are on pressure control at the desired intermediate header pressures. These are large, sophisticated machines. The practice is more common in European refineries than at US plants, although the difference seems to be cultural rather than technical or economic. In terms of what to watch for in header pressure control, the following should be considered: • The HP header • Intermediate-pressure headers • The LP header. In all cases, there are two things to consider. First, how is the pressure controlled? Second, how is the target pressure determined? Typically, the HP header pressure will be controlled by pressure control on fired-boiler output. In this setup, output on more than one boiler may be ramped up or down together to maintain target pressure. In other cases, some boilers may be on flow control, and one “swing” boiler will handle pressure control. These controls are normally in the utilities control room or console, and they are handled by the utilities operators. However, the HP header control does not normally end there. Somewhere in the refinery, there will be one or more letdown stations. It is acceptable if these stations are configured and set to maintain only an intermediate pressure below. Frequently, however, the control may be set to maintain

Intermediate-pressure header

HP boilers

MP header

HP header PC

LP header

Deaerator

FIG. 3. Normal header pressure controls. H–82

Softened makeup water, 80°F

HEAT TRANSFER 2013 | HydrocarbonProcessing.com

Intermediate-pressure header

FIG. 4. Header pressure control.

HEAT TRANSFER

HP header pressure locally. Common arguments are that the stations are too far from the boilers, that there are restrictions in the line, and that local HP waste-heat boilers are a disturbance. Regardless, there is now more than one controller performing control operations. It is key to ensure that HP boilers are not working at one end to maintain a pressure, and that letdowns on the same header are letting down to relieve pressure. Setpoints vs. control. There are two things to keep in mind.

First is the relative setting of the pressure control targets at competing controllers. The setpoints should not be configured so that the letdown relief setpoint is at a higher pressure than the boiler output pressure control (FIG. 4 ). In this scenario, the boiler will increase output, and the letdown will relieve the overpressure, in effect dumping excess boiler steam into the lower-pressure systems. (Note: The setpoints are typically configured by operators in different process departments, with no overall coordination.) Second, the letdown station may have a split-range controller that will switch from makeup control for lower pressure to letdown control of higher pressure in response to an overpressure situation. In a recent steam system review, the author was assured that a split-range controller only let down in rare overpressure situations. An examination of a year’s worth of process information data showed that the controller was in HP relief mode 46% of the time. Another overall issue to consider is the target pressure. For example, if the nominal, 600-psi system is running at 580 psi, then the question to be answered is, “Do we have the flexibility to raise or lower the 600-psi system target pressure, and, if so, where should we set it?” In most plants, this question is rarely asked. At the HP header, the best practice is to run at the lowest pressure practical. (Note: This is an operating recommendation for an existing system; it may not apply in the design of a new steam system.5) The lower limit will be reached when, for example, a turbine does not generate enough horsepower, a reboiler does not provide enough heat, or a live steam stripper no longer meets flashpoint. This issue is worth investigation, and operation at lower pressure, with some operating margin, should be considered. The benefits of running at lower pressure include higher boiler efficiency, reduced line heat losses and reduced steam loss at steam leaks. Never assume that the nominal nameplate pressure is the actual pressure, however. The author was recently involved in a process and instrumentation (P&I) meeting between engineering company designers and refining company operators. In the meeting, it was revealed that the designers had assumed that the 150-psi system was operating at 150 psi and had designed on that basis. Refinery personnel knew that the 150-psi system ran at 130 psi, but no one had ever pointed out that fact. Intermediate-pressure headers raise similar questions to those above, but they are more complex. There is a mixture of steam supplies (e.g., letdown stations, process steam generators, condensate flashing, back-pressure turbine exhaust), as well as a mixture of uses (e.g., letdowns, heating/reboiling, turbines and process steam).

The most critical question is, “Are we sure that controllers are not set somewhere that cause simultaneous letdown from above (to maintain pressure) and letdown to below (to relieve pressure)?” Each option will look normal in the particular process area in which it occurs, but it will not be logical from a total system viewpoint. It is always good practice to raise the question, “What has determined the actual pressure at which the pressure is controlled?” Is it arbitrary, or has it been lowered to maximize power from a critical turbine that exhausts into this header? Or has it been raised to achieve maximum power from a turbine using this header as inlet steam, or from some reboiler where a few more degrees were needed to bring sufficient heat into some column? If there is no known constraint, then the benefits of raising or dropping it by some Δpsi can be brought into question. The answer can be in either direction; it is specific to the steam suppliers and to the users connected to that header. Chances are good that the pressure is suboptimal. The LP header will have steam supply from letdowns, turbine exhaust, waste-heat boilers and condensate flash. Uses are limited to those things that can be achieved with steam having a temperature of 240°F–260°F (10 psi–20 psi of steam). Every steam system is different, but, overall, refineries and petrochemical complexes tend to be long on LP steam. If there is excess, it will vent to atmosphere. Venting steam—which ultimately comes from a fired boiler—is expensive and frequently noisy; it is a visible signal of imbalance and should be avoided if possible. However, some refineries (in the author’s experience, approximately 20%) treat continuous venting of LP steam as inevitable, and it has become accepted as a simple cost of doing business. One important thing to look for is whether different letdown and atmospheric vent pressure controllers in different parts of the complex are configured with the inlet setpoint higher than the atmospheric vent setpoint. The result is continuous venting (FIG. 5). The author has observed this phenomenon on several occasions. Usually, the engineer attempts to find the causes of the steam imbalance that is causing excess LP steam to vent. This can be frustrating, as it is not a material balance issue; it is a control problem. The solution is to understand the normal setpoints of the letdown and vent controls. Keep in mind that these controls are typically in different sections of the refinery, controlled by operators in different control rooms, and there is no overall coordination. Another important thing to look for is whether excess LP steam is being hidden by excessive use. Examples discovered include: Setpoint 10 psi Letdown PC

LP header

Setpoint 8 psi

Deaerator

To atmosphere

FIG. 5. Low-level header pressure control. HYDROCARBON PROCESSING | HEAT TRANSFER 2013

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stations. Justification for additional letdowns then occurs. Typical justifications include: • One letdown is needed to control pressure locally • Two letdowns are needed if each one’s line size is too small • Letdowns are needed to protect local critical equipment. These claims must be analyzed carefully. ReaThe ultimate question to be answered is, sonable concerns are legitimate, although letdowns should not be added without a thorough analysis of “How many letdowns are really needed where and how many are needed. for system control?” Generally, the number In a recent steam system review, 11 letdown stations were uncovered—three in just one process unit. is less than the number of existing letdowns. The recommendation was to reduce the number of letdowns from 11 to three, which required proper sizing of the stations. What are reasonable letdown flowrates? Once the num• Hidden vents (i.e., condensing excess steam in air or waber of letdown stations has been determined and everything ter coolers, or even venting steam in a cooling tower). possible has been done to identify total steam flows, two new The solutions in these cases are: issues emerge. First, the total aggregate amount of steam be• Examine all sources of LP steam and evaluate methods to ing let down may be larger than realized. (Note: This scereduce or eliminate that supply nario is acceptable if it is legitimately required for low-level • Consider alternate, legitimate uses for LP steam uses.) Often, however, it inspires ways to use LP steam that • Check options to thermally recompress the LP steam are much less efficient than simply not making the steam in (occasionally, there may be a large letdown of 600 psi–150 psi the first place. A telltale indication is a large use for preheating of steam that could be used in an eductor to thermally comcold deaerator feedwater. That flow is generally not metered press the LP steam to a more useable pressure). and is given little recognition, and it is very easily calculated Number of letdown stations. Discerning the real numby deaerator heat balance. The overall objectives are to miniber of letdown stations in a refinery is always an interesting mize LP steam consumption and, in turn, back up the system challenge. There are the “official” stations, and there are also to reduce boiler-fired steam production cost. the “forgotten” ones. Conversations with the boiler house opThe second issue is that, when letdown rates are minierators will typically elicit information about two to three letmized, the question then becomes, “How much letdown is ledowns from the HP system. These may include a few that are gitimately required for system control?” The author has yet to under boiler house control, and perhaps another significant establish a general guideline or best practice in this area. Typione out in the refinery. Beyond that, further investigation is cally, a value of around 10% of steam demand at the outlet generally required. pressure header is reasonable to maintain control. In reality, The discovery of additional letdown stations requires conit becomes a question of analyzing size, rate and frequency of versations with process personnel in other areas of the refindemand swings at the particular header, and using some judgery or complex. These discussions will typically affirm several ment as to the letdown capacity reasonably needed to handle more stations. This process typically requires some debate that level of demand variability. and clarification as to exactly at which pressure levels one or Desuperheating. It is not uncommon to discover at least more of the letdown stations function. one desuperheating station in a complex steam system. It is The final effort is to make another investigative round, this typically found where there is a large letdown steam flowrate, time including board operators in different control rooms. It or where steam is superheated to begin with (e.g., typical is advisable to ask about the letdown stations that are unused fired-boiler steam that has a superheater section and becomes or that have been shut in or removed in the past. This process more superheated across the letdown station). typically turns up one or two more candidates requiring field There are two points to understand. First, highly superheatinspection to find out what stations are still in use. After this ed steam is not beneficial to most refinery users. It is not adstep is completed, all of the letdown stations can be added to vantageous for reboilers and steam heaters, since some surface the steam system drawing. area is used up in cooling steam (low heat-transfer coefficient The next step is to find out how much steam is actually beand duty) as opposed to the surface area used up in condensing ing let down. This is frequently a challenge. Some of the main steam (high heat-transfer coefficient and duty). Second, highletdown stations may be metered; others may need to be estily superheated steam is typically not efficient in hydrocarbon mated by valve characteristic and ΔP across the headers. Furstripping, where moles of steam per mole of hydrocarbons is the ther insight might be gleaned by the steam system balances. target, and fewer (but superheated) steam moles may not have The ultimate question to be answered is, “How many letvalue. Superheat is typically beneficial to back-pressure steam downs are really needed for system control?” Generally, the turbines. However, if steam is let down in parallel to a back-presnumber is less than the number of existing letdowns. The resure turbine, then turbine efficiency and steam superheat is not quired approach is to ask why each letdown is needed. Ideally, important. Steam superheat is favorable in condensing turbines; there is just one letdown between each pressure level; i.e., a however, most refineries have already eliminated these turbines. steam system with four pressure levels requires three letdown • Excess amine regeneration • Very high iC4 /olefin ratio in an alkylation unit to consume excess LP steam in the deisobutanizer tower reboiler • Very high steam stripping in a sour water stripper

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HEAT TRANSFER 2013 | HydrocarbonProcessing.com

HEAT TRANSFER

Expanding steam across a valve is an adiabatic process; no heat is gained or lost. Instead, the outgoing steam is more superheated than the incoming steam. Since steam letdown superheats steam, and since superheat is technically a disadvantage in many applications, desuperheaters are not uncommon. Desuperheating simply injects water into the letdown station. The effect is to increase pounds of steam, with each pound being of a lower quality or a lower superheat. A short dialogue on wet steam vs. dry steam may be useful at this point. Steam engineers like to design so that the whole system is dry. There is some opinion that the whole system must be dry for safe operation. The author was once almost asked to leave a European refinery when he proposed an idea that would have created some wet steam. The belief was that the whole system needed to be dry everywhere. Ironically, at the next system on which the author worked, most of the steam was generated at saturation, with no superheat, and the whole system was wet. So, how much superheat is appropriate? That is a tough question, as there is no measure of superheat (or wetness) in the system, and steam quality is not always known at the end of the line, or in distant areas, or following certain weather events, such as a thunderstorm. On the basis that more pounds of steam of lower quality are more useful than fewer pounds of high-superheat steam, there are a couple of general guidelines: • Desuperheat large letdown flows of already superheated steam • Aim for enough superheat to avoid condensing in steam lines (around 30°F–40°F superheat), assuming lines are properly insulated. The local process area ‘protection’ racket. There is an old adage that says, “If you don’t ask the right questions, you won’t get the right answers.” In studying existing steam systems, this adage applies. It is the author’s custom, when talking with process staff and board operators in various refinery process areas and control centers, to ask what steam system control practices are applied in local areas to protect their domain. Typically, in any process area, there are equipment inadequacies, such as a back-pressure turbine that struggles to put up enough pressure for the reflux pump, or a reboiler that does not quite achieve the duty a column needs. As a result, these items are “protected.” A spare letdown station is used to maintain a specific local pressure or to tweak steam supply when needed, with no measurement and no record. Some of these practices are appropriate. However, some of them may have consequences elsewhere in the steam sys-

tem. A local control practice may impact other parts of the system in a different process area—i.e., Area A may be normal, but Area B may experience an upset or a consequence for reasons not understood. The net result is negative from a total-system viewpoint. Steam vs. electric-driver sparing. Refineries and chemical complexes tend to have a large number of back-pressure steam vs. electric-driver sparing options. Local circumstances generally dictate which driver is normally run and which is normally used as the spare. However, switching to or from a back-pressure turbine affects the steam letdown between the same pressure headers. Turning on a 150-psi–20-psi turbine will reduce the existing letdown by the amount of steam the turbine uses. Conversely, taking a steam turbine out of service will increase letdown. A more expensive issue occurs when the LP header is out of balance and excess steam from too many turbines online is vented to atmosphere. A more common issue is to use a steamsparing or electric-sparing option to provide some rough control on reducing excessive letdown rates. Actual practices vary widely, depending on the severity of the variation and the ability to switch turbines. A good practice is to provide a central source of information and control on the following management and procedural issues: • Monitoring the actual letdown rates • Targeting the minimum and maximum desirable letdown rates • Considering the steam-sparing and electric-sparing options available • Having knowledge of which driver is running for each sparing option • Following established operator instructions on the sequence of which drivers are to be added or removed • Adhering to procedures to request switching if the next combination to be switched is in another control room. HP boilers

HP header Reboiler Flash

Flash stream MP header

TABLE 1. Amount of HP condensate flashed to generate LP steam Condensate pressure, psig

Flash (steam) pressure, psig

Reboiler

Condensate flashing to steam, %

600

150

600

150

Flash

Flash stream LP header Condensate

Deaerator

Softened makeup water, 80°F

FIG. 6. Condensate flashing. HYDROCARBON PROCESSING | HEAT TRANSFER 2013

H–85

HEAT TRANSFER Condensate flashing and condensate recovery. Condensate is produced from three main sources: 1. Reboilers and steam heat exchangers 2. Condensing turbines 3. Steam tracing/tank heating.

In any one plant, this may have merit as a measure of whether the local situation is improving or regressing. However, this criterion is useless when comparing different refining and petrochemical complexes. A refinery or petrochemical complex with little demand for heating/reboiling steam (e.g., a plant where an extensive hot oil system is used), and with high usage of steam for live stripping or process consumption (e.g., a hydrogen plant), will expect low recovery of condensate relative to steam produced. A more meaningful measure of condensate recovery is:

The most critical question is, “Are we sure that controllers are not set somewhere that cause simultaneous letdown from above and letdown to below?” Each option will look normal in the particular process area in which it occurs, but it will not be logical from a total system viewpoint. The biggest supply comes from reboiling/heating. This typically happens at some high or intermediate pressure level and is “clean,” as it has not been in contact with hydrocarbons. In a perfect steam system, this condensate will be flashed to produce steam for use in the LP system, and the LP condensate is collected for return to the boiler feed system (FIG. 6). Wherever possible, condensate should be flashed in condensate flash pots to generate additional LP steam and help prevent dangerous water hammer in condensate return piping. TABLE 1 provides a perspective on the amount of HP condensate that can be flashed to generate LP steam. The values in TABLE 1 assume that condensate is available at its saturation temperature. The percentage of condensate actually recovered as steam will be less, depending on system heat losses. This is largely a function of insulation quality and geography. For a large, well-insulated steam reboiler, with condensate collected and flashed close by, losses will be small. At the other extreme, condensate recovered in a distant tank farm and brought back onsite may experience significant cooling before being flashed. Condensate should be tracked carefully as part of the steam system definition. A well-designed and well-operated steam system should recover up to 70% of available condensate. Losses tend to build from the accumulation of small quantities of condensate that do not justify lines and pumps for recovery. These quantities are instead dumped to local sewers, or even to the ground. For steam systems that recover less than 50% of condensate, effort should be made to locate points where condensate is lost, to determine the size of this loss, and to consider the cost of recovering the condensate vs. the value of the condensate recovered. Note that some complexes define the percentage of condensate recovery as: Percentage of condensate recovery = (condensate recovered ÷ steam production) ⫻ 100 H–86

HEAT TRANSFER 2013 | HydrocarbonProcessing.com

Percentage of condensate recovery = (condensate recovered ÷ condensate produced) ⫻ 100

In the author’s experience, different complexes range from a low (20%) recovery to a high (75%) recovery. Vents to atmosphere. Continuous venting of LP steam to atmosphere has occurred in approximately 25% of the steam systems reviewed by the author. This is a costly practice, since every pound of steam vented represents the full cost of steam. Continuous venting is caused by either a fundamental steam mass balance issue, or by improper control practice. Commonly, continuous venting is a mass balance “imbalance”; i.e., more LP steam is produced than used. The solution is to either find effective ways to use the LP steam, or to reduce the supply of LP steam. Supply reduction includes checking all letdown sources, the replacement of back-pressure turbines exhausting to the LP steam system, or finding other uses for waste heat used to generate LP steam. While LP venting is typically assumed to be a steam imbalance problem, it can also be caused by an improper and unrecognized control issue. A shortlist of things to investigate includes: • Actual setpoints for the various letdown and vent controllers • Board operating practices regarding those setpoints • Control system configuration • Header pressure drops in and between different process areas • Transient steam demand or supply • Conflicting local process issues being protected. It is important to recognize that LP steam controls may be scattered throughout the refinery. Local area practices are dictated by local area concerns. Commonly, there is no overall coordination; a “systems view” is critical to solving the problem. LITERATURE CITED Pelham, R. O. and R. D. Moriarty, “Survey plants for energy savings,” Hydrocarbon Processing, July 1985. 2 Improving Steam System Performance: A Sourcebook for Industry, 2nd ed., February 2012. 3 Tanthapanichakoon, W., “Saving energy in multilevel steam systems,” Chemical Engineering Progress, January 2012. 4 Dogan, A., “Using cold boiler feedwater for energy recovery,” Petroleum Technology Quarterly, Q1, 2012. 5 Peterson, J. F. and W. L. Mann, “Steam system design—how it evolves,” Chemical Engineering, October 14, 1985. 1

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